ML18039A348
| ML18039A348 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 05/05/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18039A346 | List: |
| References | |
| 50-259-98-02, 50-259-98-2, 50-260-98-02, 50-260-98-2, 50-296-98-02, 50-296-98-2, FACA, NUDOCS 9805210295 | |
| Download: ML18039A348 (67) | |
See also: IR 05000259/1998002
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:-
License
Nos:
50-259,
50-260.
50-296
Report Nos:
50-259/98-02,
50-260/98-02,
50-296/98-02
Licensee:
Valley Authority
Facility:
Browns Ferry Nuclear Plant, Units 1, 2.
8 3
Location:
Corner of Shaw and Browns Ferry Roads
Athens,,AL
35611
Dates:
March 1,
1998 - April 11,
1998
Inspectors:
L. Wert. Senior Resident
Inspector
J. Starefos,
Resident
Inspector
E. DiPaolo. Resident
Inspector
G. Hopper,
Reactor
Engineer
(Section 05. 1)
C. Smith, Reactor
Inspector (Section El. 1)
W. Smith, Reactor
Engineer
(Section 05. 1)
Approved by:
H. 0. Christensen,
Chief
Reactor Projects
Branch
6
Division of Reactor
Projects
98052i02'P5
980505
ADGCK 0500025'P
8
Enclosure
2
EXECUTIVE SUMMARY
Browns Ferry Nuclear
Plant, Units 1. 2.
8 3
NRC Inspection Report 50-259/98-02.
50-260/98-02,
50-296/98-02
This integrated
inspection included aspects of licensee operations,
engineering,
maintenance,
and plant support.
The report covers
a six-week
~
~
er iod of resident inspection
and inspection in the areas of Licensed Operator
raining and Engineering
by a Region II Division of Reactor
Safety Inspector
and two Reactor
Engineers.
~oereti one
Overall conduct of a complex surveillance involving 3EC shutdown board testing
was good.
Self-checking
and communications
practices
were observed to be
strong. 'he Senior Reactor Operator
(SRO) coordinating the testing
was well
prepared
and applied excellent supervisory oversight throughout the test.
The
SRO promptly identified and corrected
two personnel
errors during the testing.
The investigation
and immediate corrective actions for an emergent electrical
board switch problem were performed well (Section 01. 1).
Licensee
management
promptly and aggressively
responded to an
NRC observation
that
an expectation
contained in a standing order for control rod exercise
testing
was not implemented.
The issue
was thoroughly reviewed by the
licensee,
documented in the corrective action program,
and acceptable
corrective actions were completed.
In general.
the inspectors
have noted
increased
Operations
Department sensitivity to meet
management
expectations
during the performance of this testing (Section 01.2).
Control
room operators
properly inserted
a manual scram after entering
Region
1 of the core thermal
power to flow diagram following a recirculation
pump runback.
The runback resulted
when
a breaker
opened in the recirculation
pump control circuitry.
The problem was caused
when an engineer
taking
measurements
in an instrumentation
cabinet allowed
a metal tape measure to
contact a'use
holder.
Operator
response
following the scram was good.
The
peer
check performed
on the shutdown cooling lineup was considered
a good
practice.
The Incident Investigation
was thorough in review of the scram
and
equipment
issues
(Section 01.3).
The inspectors
concluded tha't
a recent increase
in the number of operations
performance
issues
did not constitute
a significant negative trend.
The
safety significance of many of the items was minor and
a low threshold of
problem identification was noted (Section 01.4).
Attendance of support group representatives
(i.e.. fire protection, security.
maintenance,
and engineering)
at the shift turnover
meeting
was considered
a
good practice.
Board walkdowns by operators
were detailed.
thorough.
and
consistent
from crew to crew.
Pre-shift reviews of 'required documentation
were generally thorough (Section 01.5).
The licensed operator requalification program was adequate
with respect to the
examination question sampling process,
remediation training, operating
examination content validity, and feedback of plant events
and incidents into
the training curricula.
However. the written examinations
contained
questions
of marginal discriminatory value,
and therefore.
did not fully meet the
standards
established
in NUREG'-1021.
Interim Revision
8 (Section 05.1).
The licensed operator activation/reactivation
process
was incorrectly
implemented resulting in operator licenses
being certified active when in fact
they were not.
As a result. the licensee failed to meet the minimum shift
crew requirements
on several
occasions.
A violation was identified by the
inspectors for noncompliance with Technical Specification (TS) 6.2.2.a.
(Violation 259,260,296/98-02-01.
Failure to Meet Minimum Shift Crew
Requirements)(Section
05. 1).
In several
observed control
room simulator training scenarios,
the crew
successfully
recognized
the major events'tilized
response
procedures,
and
stabilized the unit.
In general,
operator
performance
issues
such
as
use of
procedures
and communications
were addressed,
however management
expectations
for self-checking were not consistently
emphasized.
During observation of
the critique sessions,
the resident
inspectors
noted several
examples
which
indicated that the training personnel
were not consistently enforcing high
standards
of overall proficiency (Section 05.2).
Maintenance
The licensee did not initially perform an aggressive
review of the inspector's
concern that
SBGT testing relied upon the skill of the maintenance craft to
work around procedural
obstacles.
The
NRC subsequently
identified that the
model of DOP generator
used for testing of the Standby
Gas Treatment
(SBGT)
and Control
Room Emergency Ventilation
(CREV) systems
was not equivalent to
that model required
by the procedure.
A violation was identified for failure
to follow testing procedures.
(Violation 259,260 '96/98-02-02 'ailure to
Follow High Efficiency Particulate Air Filter Testing Procedures).
Additional
NRC review identified that the procedure for testing the
SBGT downstream
filter did not meet the requirements of American National Standard Institute
(ANSI) N510-1975
as required
by TS.
(Violation 259.260.296/98-02-03,
Inadequate
Testing of Downstream Standby
Gas Treatment
HEPA Filter)(Section
Ml.1) .
Periodic replacement of the High Pressure
Coolant Injection System turbine
exhaust
rupture disc assembly
was performed satisfactorily except that the as-
found inspection
process
was not adequate to'identify that the disc material
was degraded.
The licensee did not identify the degradation until the
inspectors
questioned
the inspection
method.
(Violation 260/98-02-04,
Failure
to Identify Degraded
HPCI Rupture Discs)(Section
M1.2).
Overall. conduct of Fix-It-Now team work was good.
The inspectors
questioned
the procedural
guidance
and implementation regarding the use of personnel.
in
some cases,
to ensure that
a component
was maintained in the safe position
instead of using
a clearance.
Licensee
management
is reviewing the practice
to determine if procedural
guidance is appropriate
and management
expectations
were met.
Additional
NRC review of the licensee's
evaluation is necessary.
(Inspection Follow-up Item 260,296/98-02-05.
Use of Personnel
in Place of
Equipment Clearances)(Section
Ml.3).
Major maintenance activities on two residual
heat
removal service water
pumps
were conducted well.
Placement of the
pump assemblies
was performed carefully
and actions to address
shaft wear were good (Section M1.4).
En ineerin
The inspector concluded that the licensee's
gualified,50.59 Preparer Training
met ANSI-3.1-1981 (Section El.l).
Six 10 CFR 50.59 safety evaluations
were chosen for review, five were
determined to be technically adequate.
One safety evaluation
had
a minor
deficiency, in that the
SER incorrectly stated the scope of the change
(Section El. 1) .
Plant
Su
ort
The licensee properly posted required notices to workers
as required by 10 CFR 19. 11.
Technical
Information Center
personnel
were knowledgeable of the
locations of documents
required to be available to workers (Section R1.1).
~RO
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.
Unit 3 operated at or near full power.
On Harch 27.
1998,
power was reduced
to about
65 percent
rated for flux suppression
testing
and control rod
adjustments.
One additional
rod was inserted to suppress
flux near
a fuel
leak and power was restored to full rated several
days later.
On April 7,
1998, the unit was manually scrammed after the recirculation
pumps
ranback.
The runback resulted
when
a breaker
opened in the recirculation
pump control
circuitry.
The problem was caused
when an engineer
taking measurements
in an
instrumentation
cabinet allowed
a metal tape measure to contact
a fuse holder.
Section 01.3 contains additional details.
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 Hl. 1 describes
issues
involving testing that was not conducted in the manner described in
Section 5.3 of the
No other issues
were identified.
~l.
0
Ol
Conduct of Operations
01. 1
4kV Shutdown
Board Undervolta
e Start of Diesel
Generator
Division II
Surveillance Test
and Failure of the
3B 480V Shutdown
Board to Transfer
to Alternate
Su
1
a.
Ins ection
Sco
e
71707
61726
One of the resident inspectors
observed significant portions of 3-SI-
4.9.A.4.b(II), 4kV Shutdown
Board Undervoltage Start of Diesel Generator
Division II.
During the testing,
the 3B 480V Shutdown
Board failed to
transfer to its alternate
supply.
The inspector observed
some of the
troubleshooting activities
and corrective actions.
b. Observations
and Findin s
The inspector
observed the portions of the test associated
with the
3C
4kV Shutdown
Board and the
3EC Emergency
Diesel Generator
(EDG).
Performance of the test
began
on Harch 10,
1998.
The briefing held
prior to testing
was thorough.
All pertinent
items listed in Section
3.6 of Site Standard
Practice
(SSP)-12. 1, Conduct of Operations,
were
addressed.
The Senior Reactor Operator
(SRO) who was the lead performer
of the test led the briefing.
Specific responsibilities
by involved
performers
were discussed.
The
SRO had closely reviewed the test
procedure in preparation for the test.
For example.
steps necessitating
entry into Technical Specification
(TS) Limiting Condition for
Operations
(LCOs) or Appendix
R issues
were marked
as such.
Limitations during alternate
power alignments
were also discussed.
\\
2
The initial portions of the test went well.
Transmission
and
Power
Services
(TPS)
and Operations
personnel
verified correct functioning of
key relays
and alarms.
The inspector observed that the
TPS personnel
consistently utilized good self-checking techniques.
Independent
verification of the removal of test plugs was performed correctly.
Step 7.2.45 required transfer of the
3B 480V Shutdown Board to its
alternate
power source in accordance
with Operating Instruction (OI)-
57B.
A separate
briefing was held before the evolution.
The inspector
noted that notification of other site organizations
was
made before the
transfer.
The inspector
observed
two SROs in the attempt to transfer
the 480V shutdown board.
The operators
were actively referencing the
rocedure
and correctly performed the steps
leading
up to closing the
reaker switches.
The inspector observed that the
SRO fully moved the
control switch handle to the close position.
The alternate
breaker
did
not shut and the
SROs promptly closed the normal breaker
as directed
by
the procedure
and halted the testing evolution.
The failure of the board to transfer resulted in a loss of the 3B
Reactor Protection
System
(RPS) bus.
A 10 CFR 50.72 notification was
made to the
NRC Operations
Center.
The potential
loss of an
RPS bus
had
been addressed
in the briefing.
The inspector
observed that control
room personnel utilized procedures to respond to the engineered
safety
feature system actuations.
Two minor discrepancies
were observed.
The
operators
had to shut off one train of Standby
Gas Treatment to correct
a reactor building static pressure
condition which inhibited restoration
of reactor
and refueling floor ventilation.
This issue
was later
addressed
as
an operator work around.
The Unit Supervisor initially did
not recognize that
a
TS Limiting Conditions for Operation
(LCO) entry
was required
due to the mode switch shutdown
scram function being
inoperable for
a short time after the transfer failed.
Procedure
3-AOI-
-99-1,
Loss of Power to One
RPS Bus,
and
GE Service Information Letter
(SIL) 344 describe
how a relay race
may cause this condition and
how to
clear the condition.
The condition was subsequently'orrected
within
several
minutes in accordance
with procedures.
The licensee
developed
a detailed troubleshooting
plan to systematically
examine the problem.
After some investigation,
technical
support
ersonnel
noted that
a wire connected to the back of the alternate
reaker control switch was very close to a moveable contact finger
and
may have prevented the contacts'from closing as the switch handle
was
rotated to the close position. It was postulated that the slip-on cover
on the back of the
GE SB-1 type switch was pressing the wire down enough
to inhibit contact closure.
On March 12. the licensee
established
proper plant conditions
and attempted transfer of the board again.
The
resident
inspector
observed that the suspect wire was barely clear of
the contact finger before the switch was
moved and appeared
to just
contact the finger as it was operated.
Under the wire there
was
some
marks indicating that the wire had rubbed against the contact in the
past.
When workers
removed the lid or back enclosure
from the switch
cover and installed just the edge piece,
the inspector noted that the
cover edge
was against the wire and just slight pressure
on the piece
was sufficient to press the wire down.
By examining
a similar
uninstalled switch, the inspector
noted that it was easy to hold the
moveable contact
as the control switch handle
was rotated
due to some
"float" or free motion in the switch design.
A Problem Evaluation
Report
(PER)
was initiated to address
the issue.
The failure of. the
board to transfer
to the alternate
breaker
was not of large safety
significance.
Transfer of the board is manually initiated by operators
if power to the board is lost.
There is another
480V shutdown board
on
each unit with the loads divided between
them.
The licensee
subsequently
placed the 480V shutdown board
on the
alternate
supply and on the evening of March 14, continued the
surveillance test.
Again, the inspector
observed
good overall
use of
self checking by TPS personnel.
During preparation to perform
a slow
start of the
C EDG, the inspector observed
a personnel
error on the part
of the
AUO which was identified and immediately corrected
by the
leading the test.
During a subsequent
step,
an error by the two TPS
workers was also promptly identified and corrected
bP the
SRO.
The
detection of the errors indicated
good attention to detail
on the part
of the
SRO.
Problem Evaluation Reports
(PERs) were initiated to address
the issues.
The inspector also observed that the Unit 3 Control
Room
(CR) operators
utilized good self checking
and adhered to the procedures
during
startup, paralleling,
and shutdown of the
EDG.
Conclusions
Overall conduct of a complex surveillance involving 3EC shutdown board
testing
was good.
Self-checking
and communications
practices
were
observed to be strong.
The
SRO coordinating the testing was well
prepared
and applied excellent supervisory oversight throughout the
test.
The
SRO promptly identified and corrected
two personnel
errors
during the testing.
The investigation
and immediate corrective actions
for an emergent electrical
board switch problem were performed well.
Control
Rod Exercise Testin
Observations
Ins ection Sco
e
71707
61726
During the inspection period, the inspectors
observed
performance of
portions of control rod exercise testing.
Problems
were previously
identified by the licensee
regarding execution of the control
rod
exercise test which resulted in a mispositioned
rod.
That incident was
addressed
in Inspection Report 50-259.260.296/98-01
Section 01.4.
Observations
and Findin s
On March 7,
1998, the inspectors
observed control
room personnel
during
performance of Surveillance
Instruction, 3-SI-4.3.A.2
~ Control
Rod
Exercise Test,
Revision 9.
Shortly after the inspectors
arrived in the
control
room, performance of the surveillance
was stopped for a short
break.
The Peer Checker
and the Reactor
Engineer left the control
room.
After a brief period, the Peer Checker returned
and discussed
restart of
the surveillance activities.
The
RO selected
rod 30-39 and began the
two step insertion from'tep 48 to 46.
At that time, the inspectors
got
the attention of the Unit Supervisor
(US) who was just ending
a
telephone
conversation
and identified to him that the surveillance
was
restarted without the Reactor
Engineer
back in the control
room.
The
US
immediately stopped the operators
performing the testing.
Within
moments.
the Reactor
Engineer entered the control
room.
The
US briefed
the Reactor
Engineer
that the rod movement
was started
and allowed the
surveillance to continue.
.The Shift Manager
was briefed shortly
thereafter
and stopped
performance of the surveillance.
Operations
and
plant management
were notified and responded to the control
room.
Ouring the brief observation of the performance of the surveillance
prior to the break, the inspectors
noted that control
room personnel
demonstrated
an acceptable
level of formality and attention while
performing surveillance activities.
The surveillance instruction in use did not require that the Reactor
Engineer
be in the Control
Room for the movement of rods.
Recent events
in this area
have heightened
the licensee's
sensitivity to this
surveillance activity and specific control rod drive exercise
expectations
were promulgated
as Standing Order OS-0130.
Among the
written expectations
was that the Nuclear Engineer shall
remain in the
affected Control
Room. during the pre-job brief, and while control rods
are being exercised.
There was not
a technical
or safety concern with
the operators
moving the control
rod in accordance with the surveillance
instruction without the Nuclear Engineer in the control
room.
The
problem was limited to a lack of attention-to-detail
on the part of the
operators
performing the test in that they did not ensure that the
Nuclear Engineer
was in the control
room before recommencing
the test.
The Reactor Operator,
Peer Checker,
and Unit Supervisor were
subsequently
rotated to other positions not associated
with the testing.
The licensee restarted testing with the new group of operators.
The
inspectors
observed that the operators
were performing the surveillance
with an appropriate
level of formality and that the operators actively
referenced
the operating instruction.
Licensee
management's
sensitivity
to this issue
was evident.
The licensee also addressed
this issue with
problem evaluation report 980342,
which identified additional
concerns
and documented
thorough corrective actions.
On March 28.
1998.
one of the resident
inspectors
observed
portions of
the Unit 3 control rod exercise test.
The inspector specifically noted
that the formality of the performance
was appropriate
and consistent
with management
expectations.
c.
Conclusions
Licensee
management
promptly and aggressively
responded
to an
NRC
observation that an expectation
contained in a standing order for
control rod exercise testing
was not implemented.
The issue
was
thoroughly reviewed by the licensee.
documented
in the corrective action
program,
and acceptable
corrective actions
were completed.
In general,
the inspectors
have noted increased
Operations
Department sensitivity to
meet management
expectations
during the performance of this testing.
Unit Three Manual Reactor Scram after Recirculation
Pum s Runback
Ins ection Sco
e
71707
93702
The resident
inspectors
observed
and reviewed the actions of control
room operators
following a manual reactor scram due to entering
potential instability Region .1 on the core thermal
power to flow
diagram.
A resident inspector also observed
portions of the plant
cooldown including placing shutdown cooling in service.
Observations
and Findin s
At 11: 12 a.m.,
on April 7,
1998.
both recirculation
pumps
(3A and 3B) on
Unit 3 experienced
a run back to the 28K speed limiter .
The operator s
commenced inserting control rods
and performed 3-SI-4.5.M. l.b, Core
Thermal Hydraulic Stability Flow Decrease,
in accordance with Abnormal
Operating Instruction (AOI) 68-1.
Performance of 3-SI-4.5.M. l.b
indicated that core thermal power/flow was just inside Region
1 of the
core thermal
power to flow diagram.
At 11:16 a.m., the operators
inserted
a manual scram in accordance with TS 3.5.M.2 and AOI 68-1.
One
of the resident
inspectors
responded to the control
room and monitored
operator recovery actions.
The other
resident
inspectors
observed
conditions in the reactor building following the scram.
By examination of control
room chart recorders
arid other indications.
the inspectors verified that reactor vessel
level decreased
to a minimum
of -18 inches before being restored
by the reactor
feed pumps.
Primary
containment isolation equipment
performed
as designed
and no safety
system problems occurred.
The cause of the 3A and
3B recirculation
pumps run back was due to a
loss of power to the 3A and
38 Recirculation
Pump Auxiliary AC Circuits.
A TVA corporate engineer
was taking measurement
in an auxiliary
instrument
room cabinet in preparation
for
a recirculation
pump
controller modification in the upcoming Unit 3 outage.
The corporate
engineer
was briefed by the system engineer to perform
a visual
inspection of the cabinet internals.
He was aware that equipment within
the cabinet
was energized
and was also briefed by the control
room unit
supervisor.
The loss of power to the 3A and
3B Recirculation
Pump Auxiliary AC
Circuits occurred
when the supply breaker
(Unit Preferred
Breaker 603) opened
as
a result of a circuit fault.
When taking
measurements
in the cabinet in the vicinity of a fuse (FUl-68-2A/K4A),
the supply side of the fuse was accidentally shorted to ground by a
metal
measuring
tape
used
by the engineer.
This caused
the supply
breaker to open.
This de-energized
relays
and opened contacts
in the
recirculation
pump speed control circuits which normally bypass the 28K
speed limiter.
As
a result.
the recirculation
pumps experienced
a run
back to 28K speed.
The inspectors
inspected
the interior of the cabinet
and found that the fuse holder for FUl-68-2A/K4A was mounted
on
a metal
backing plate.
The supply side of the fuse was apparently shorted to
the metal backing plate by the measuring
tape
as indicated
by burn marks
on the fuse and plate.
The inspectors verified that controlled drawings
of the involved circuitry supported the postulated
series of events.
One of the inspectors
observed
Incident Investigation (II) team members
questioning the engineer
on his actions.
The team asked
good questions,
including requesting
his input for corrective actions.
The inspector
reviewed II Event Report 98-003814-000
and the Scram Report
(Attachment
1 of 3-AOI-100-1. Reactor Scram).
The inspector
concluded
that the II team performed
a thorough review of the incident and the
lant response
to the scram.
At the close of the inspection period. the
icensee
was developing corrective'ctions
including strengthening of
controls over such evolutions inside electrical cabinets.
Following the manual
Unit 3 performed
a plant cooldown to
commence
a mid-cycle refueling outage.
This outage
was preplanned
in
the event of a reactor
shutdown in order to replace leaking fuel
assemblies.
A resident
inspector
observed
portions of the plant
cooldown including placing shutdown cooling in service.
The inspector
verified that 3-SI-4.6.A.l. Reactor
Heatup or Cooldown Honitoring, was
being performed during the cooldown.
The inspector observed that
control
room operators
performed
a detailed
peer
check of the shutdown
cooli'ng lineup prior to placing it in service.
Conclusions
Control
room operators
properly inserted
a manual scram after entering
Region
1 of the core thermal
power.to flow diagram following a
recirculation
pump run back.
The run back resulted
when
a breaker
opened in the recirculation
pump control circuitry.
The problem was
caused
when an engineer taking measurements
in an instrumentation
cabinet allowed
a metal tape measure to contact
a fuse holder.
Operator
response
following the scram
was good.
The peer check performed
on the
shutdown cooling lineup was considered
a good practice.
The Incident
Investigation
was thorough in their review of the scram
and equipment
issues.
0 erations
Performance
Issues
Review
Ins ection Sco
e
71707
The resident
inspectors
reviewed operations
performance
issues
which
occurred over the last several
months to determine if a significant
negative trend existed.
The inspectors
requested
that the licensee
provide Tracking and Reporting of. Open
Items
(TROI) data to identify the
problem evaluation reports
(PERs) which were status control issues.
In
addition, the inspectors
considered
other recent
issues of concern.
Observations
and Findin s
The inspectors
developed
a list of operations
performance
issues
from
review of the
PER items identified by the search of the TROI database
and by consideration of other
recent events that the inspectors
were
aware of.
Although the period of review was approximately six months,
most of the items
on the list occurred within the last two months.
It
initially appeared
that an increase in the number of operations
performance
issues
had occurred:
however,
upon review of the individual
items, the inspectors
concluded that the saf'ety significance of many of
the items was minor.
The more significant items on the list were
dispositioned
in NRC inspection reports or will be addressed
through
review of a Licensee
Event Report
(LER).
Half of the more significant
items. were at the beginning of the review period.
In addition,
two
items will be addr essed with an
NRC review of Unit 1 items.
The majority of the items reviewed were identified by the licensee.
The
licensee
noted
an increase
in the number of personnel
errors in the
February
1998 time frame and initiated
a
8 level problem evaluation
report to review this issue.
Additionally, the licensee
informed the
inspectors that
a third party independent
detailed review of Operations
performance
was planned.
Conclusions
The inspectors
concluded that
a recent increase
in the number of
operations
performance
issues
did not constitute
a significant negative
trend.
The safety significance of many of the items was minor and
a low
threshold of problem identification was noted.
0 erations Shift Turnover
Ins ection Sco
e
71707
The resident inspectors
observed
numerous shift turnovers of operations
department
personnel.
Pre-shift turnover meetings
were also observed.
Observations
and Findin s
Requirements
for the shift turnover are described in SSP-12. 1, Conduct
of Operations.
The inspectors
observed
numerous shift turnovers of
operations shift personnel
and compared their performance with the
expectations
described in the procedure.
The turnovers
observed utilized shift turnover checklists
as
a guide for
the turnover process.
These checklists
are contained in O-GOI-300-1,
Operator
Round Logs.
The shift turnover checklists
were detailed
and
contained
good summaries of plant conditions.
Information on the
checklists
included equipment out of service/reduced
status,
equipment
returned to service.
evolutions
and maintenance
in progress,
and other
pertinent plant information.
These checklists
were effective in
E
capturing important plant information and resulted in consistent
information being passed
from crew to crew.
All observed
pre-turnover
board walkdowns by control
room personnel
~
(i.e... unit supervisors'esk
unit operator
and board unit operator)
were
considered detailed.
Pertinent plant information, such
as recent
equipment
problems
and evolutions in progress,
were effectively relayed
to the oncoming watchstander.
Oncoming operator
reviews of specified documentation
(e.g.
~ narrative
log. disabled annunciator
log, etc.) generally satisfied the
expectations of SSP-12. 1.
The inspectors
noted minor discrepancies
in
the manner that two of the four board unit operators
observed
reviewed
the operating logs.
One operator
reviewed the narrative log after
taking the watch.
This was the operators first day back
on shift and
thus
he was expected to review the previous
5 days of log entries.
The
other
operator
was not observed to review any documentation
but
discussed
the logs with the off going board operator.
'he inspectors identified an inconsistency
between the SSP-12. 1
description for auxiliary unit operator
(AUO) turnover requirements
and
the 0-GOI-300-1 turnover checklist.
The SSP-12.1 description states
that the 0-GOI-300-1 checklist documents that review of the narrative
logs has
been performed by the oncoming operator.
However. there was no
requirement
on the 0-GOI-300-1 checklist for the
AUO to review the
narrative logs.
The AUO turnovers
observed did not perform the
narrative log review.
The inspectors
informed licensee
management
of
the discrepancy.
The licensee
plans to revise
SSP-12.
1 to clarify that
AUO review of the narrative log is not required prior to turnover.
The shift turnover meetings
were conducted following individual operator
pre-turnover activities.
The shift turnover
meetings
were led by the
oncoming shift manager
and were formally structured.
Following a brief
discussion of plant status
and recent
problems. all shift personnel
discussed
the status of their individual watch station.
This discussion
included
a summary of the information contained
on the turnover
checklists.
These discussions
were considered
detailed
and thorough.
New operations
department
instructions.
standing orders,
recent
PERs
associated
with operations
and industry events
were also discussed.
Management
expectations
were also routinely stressed
at the meetings.
Support group representatives
(i.e.
~ fire protection, security,
maintenance,
and engineering)
also attended
the shift turnover meetings.
These personnel
provided discussions
of pla'nned activities for the
shift.
The attendance
of the these
personnel
was considered
valuable in
that equipment operational
concerns
are discussed.
Also, conflicts with
lanned activities were occasionally identified based
on the discussions
etween operations
and support personnel.
05
05.1
Conclusions
Attendance of support group representatives
(i.e.. fire protection.
security.
maintenance,
and engineering)
at the shift turnover meeting
was considered
a good practice.
Board walkdowns by operators
were
detailed,
thorough,
and consistent
from crew to crew.
Pre-shift reviews
of required documentation
were generally thorough.
Operator Training and Qualification
Licensed
0 er ator
Re
ua1 ification Pro
ram
Ins ection Sco
e
71001
The inspectors
conducted
a routine.
announced
inspection of the licensed
operator requalification program during the period March 2-6,
1998.
Specific areas of review included requalification examinations,
sampling
methods
used for examination generation,
training feedback,
remedial
training,
and conformance with operator
license conditions.
Observations
and Findin s
The inspectors
reviewed the licensee's
methodology for sampling of the
examination
database
in developing the requalification examinations
for
licensed
Reactor
Operators
(ROs)
and Senior Reactor Operators
(SROs).
The examinations
were developed
and implemented in accordance
with TVA
Nuclear Training Procedure
TRN-11. 10,
"Annual Requalification
Examination
Oeyelopment
and Implementation,"
Revision 2.
The inspectors
examined the licensee's
"Exam Content by Subjects" matrices for the 1996
and
1997 training cycles
and noted that the subjects
covered were in
compliance with the requi rements of 10 CFR 55.41
and 43 as applicable,
and as delineated
in Procedure
TRN-11. 10, Appendix C.
Also. the above
matrices
appeared
to be well balanced
between
what material
was
specifically covered during the training cycle and an approximate
sample
of 20K of need-to-know material that was not covered.
The inspectors
concluded that the licensee's
sample plan was very good.
The inspectors
reviewed
a representative
sampling of the requalification
operating examinations that were administered
in the fall of 1997.
The
simulator
scenario content
and level of difficultywas appropriate to
properly evaluate the competency of the
and
SROs examined.
The
inspectors
also reviewed
a small sampling of the
1997 written
requalification examinations
and noted,
howevers
a large number of
questions that only required
a fundamental
(simple memory) level of
knowledge in order to answer the questions. 'n addition,
some of the
multiple choice distractors
were easily eliminated without a strong
knowledge in the subject matter.
The inspectors
were concerned that
because all of the examinations
were "open
book ~ " the examinee
could
simply look up the answers without demonstrating
minimal competency
requirements
as operators.
This issue
was discussed
with the licensee
during the inspection
and during the exit meeting of March 6.
1998.
The
licensee
was already
aware that the examination did not fully meet'the
10
standards
of NUREG 1021.
Operator Licensing Examination Standards
for
Power Reactors."
Interim Revision 8.
and as discussed
during the
NRC
Region II sponsored
workshop conducted in January
1998.
The licensee
stated that future examinations
would be written to the higher
standards.
The inspectors
concluded that the examinations
as
administered
were marginally adequate
to discriminate against
incompetent operators;
howevers
a strong training program combined with
a 'lower examination quality may have contributed to the high grades
(approximately
95K average)
that were achieved in 1997.
The inspectors
reviewed remediation activities for two individual
that failed their weekly written examinations,
for one
RO that
demonstrated
notable weaknesses
on the control
room simulator
.
and for
two crews that failed their weekly simulator examination.
The licensee
documented
the failures,
removed the operators
from licensed duties
until satisfactorily remediated,
and documented
the material
covered
during remedial training.
In all cases,
an examination
was administered
to confirm remediation.
The inspectors
found no problems with the
licensee's
remedial training process.
Element (5) of the Systems
Approach to Training,
as defined in
10 CFR 55.4. requires evaluation
and revision of training based
on the
performance of trained personnel
in the job setting.
The licensee's
training staff provided the inspectors with objective evidence that this
approach
was being taken at the Browns Ferry Nuclear facility.
The
inspectors
reviewed several
simulator exercise
guides which incorporated
events
and incidents that had occurred at this facility.
In addition.
the inspectors
randomly selected
a Browns Ferry incident from the NRC's
tracking system.
On April 1,
1997. control
room operators failed to
promptly reset
a locked recirculation
pump scoop tube under runback
conditions.
The inspectors
noted that this incident was addressed
in
Simulator Exercise
OPL173S194,
dated April 28,
1997.
The inspectors
concluded that the licensee
had implemented
a feedback
process
as
required
by 10 CFR 55.4.
The inspectors
reviewed the licensee's
program for reactivating inactive
operator
licenses
and assessed
compliance with 10 CFR 55.53(e)
and (f).
The inspectors identified problems with the licensee's
process to ensure
operators
gained the proper quantity and. quality of practical
experience
in order to maintain
an active license
or to reactivate
an inactive
license,
as required
by NRC regulations.
10 CFR 55.53(e) states.
in part, "If a licensee
has not been actively
performing the functions of an operator
or senior operator,
the licensee
may not resume activities authorized
by a license
issued
under this part
except
as permitted by paragraph (f) of this section."
states,
in part, "If paragraph
(e) of this section is not met
~ before
the resumption of functions authorized
by a license
issued
under this
part,
an authorized
representative
of the facility licensee shall
certify the following: ... (2) That the licensee
has'completed
a minimum
of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions under the direction of an operator or
senior operator,
as appropriate,
and in the position to which the
11
individual will be assigned.
The 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> must have included
a complete
tour of the plant and all required shift turnover procedures."
.
The inspectors
reviewed the License Status
Change
Forms, control
room
logs, and,the vital area
access
records for 13 operators that had
reactivated their licenses
at some time during the period March 11,
1996, to January
27 '998.
A review of the vital area
access
records
for each reactivation period resulted in total hours ranging from a
minimum of 28.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to a maximum of 37.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, with the average
being
32.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
These totals were compiled using generous
acceptance
criteria which gave credit for short time intervals of as little as
one
minute spent
by the operators within a control
room boundary.
The total
hours also included time in-plant making tours and, in some cases,
shift
turnover.
Nevertheless,
the inspectors
found that
12 operators
were
significantly short of the 40-hour minimum requirement to reactivate in
the position to which the individual was to be assigned.
The inspectors
also were unable to verify 'that
an individual stood
a parallel watch in
the position to which he was to be assigned
given the large number of
vital access
area entries
and exits that occurred during the stated
reactivation periods.
The inspectors
determined that, in each of these
12 cases.
an authorized representative
of the facility incorrectly
certified that the operators
had completed
a minimum of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of
shift functions
under
the direction of an
RO or SRO and in a position to
which the individual will be assigned.
The inspectors
noted that circumstances
surrounding this problem were
similar to those associated
with a previous violation *that was
identified in December
1994.
This was Violation
50-259,260,296/94-11-01.
"Requirements for reactivation of
operators'icenses
were incorrectly certified."
The corrective actions taken
as
a
result of the previous violation were not effectively implemented to
preclude repetition.
In view of the continued
problems identified in the licensee's
operator
license reactivation
program,
the inspectors
requested
the licensee to
determine if inappropriately reactivated
operators
were performing
licensed activities at the time of this inspection
and over the past
year.
The licensee
found several
instances
where operators fulfilling
the minimum shift crew requirements of TS 6.2.2.a
were not holding
properly reactivated
licenses.
The inspectors
also questioned
the
functions performed by operators while maintaining their licenses
active.
requires,
in part,
"To maintain active status,
the licensee shall actively perform the functions of an operator or
senior operator
on
a minimum of seven 8-hour or five 12-hour shifts per
calendar
quarter ." It was determined that
some of the operators
were
not actively performing the functions of operators
or senior
operators
as defined in 10 CFR 55.4 during shifts which were credited
towards
maintaining active license status to satisfy the requirements of
For example,
operators
were given credit for
performing the functions of the shift technical advisor,
which was not
a
position requiring
a license.
As
a result. certain operators
were
performing the functions of active licensed operator or senior operators
12
while their license
was in an inactive status.
Failure to fulfillthe
minimum shift crew requirements
is
a violation of TS 6.2.2.a
(50-259.260 '96/98-02-01).
The licensee
promptly removed the operators
and senior operators with
from licensed positions
on the watch list, and
implemented detailed procedures
to properly control
and document
operator license activation/reactivation to meet the requirements
of'0
CFR 55.53(e)
and (f). "Conditions of Licenses."
Conclusions
The inspectors
concluded that the licensed operator requalification
program was adequate with respect to the examination question
sampling
process,
remediation training. operating examination content validity.
and feedback of plant events
and incidents into the training curricula.
However, the written examinations
contained questions of marginal
discriminatory value.
and therefore,
did not fully meet the standards
established
in NUREG-1021,
Interim Revision 8.
The licensed operator
activation/reactivation
process
was incorrectly
implemented resulting in operator licenses
being certified active when,
in fact, they were not.
As a results
on several
occasions
the licensee
did not fulfillthe TS-requi red minimum shift crew requirements
for
actively licensed operators while the plant was in operation.
A
violation was identified by the inspectors for failure to comply with
This was identified as violation 259,260,296/98-02-01,
Failure to Meet Minimum Shift Crew Requirements.
Observation of Simulator Trainin
Ins ection Sco
e
71707
Two of the resident
inspectors
observed
several
control
room simulator
training sessions
for licensed senior
and reactor operators.
In
accordance
with Inspection
Manual
71707 'he effectiveness
of the
observed training was assessed.
The resident
inspectors
were assisted
by two Region II Operator
Licensing Branch inspectors.
Observations
and Findin s
The inspectors
observed three sessions.
with one being the
same scenario
presented
to two different crews of operators.
The scenarios
included
extensive
use of the Emergency Operating
Procedures
(EOPs)
and were
challenging in their overall complexity.
In all of the. scenarios,
the
crew successfully
recognized the major events. utilized response
procedures,
and stabilized the unit.
The inspectors
observed that the operators
were knowledgeable
regarding
details of plant equipment
performance. 'or example,
response
to
alarming annunciators
in the initial phases of the scenarios
was prompt
and aggressive.
On several
occasions,
based
on their experience,
the
13
reactor operators
proposed
sound
recommendations
to the Senior Reactor
Operators
(SROs) well in advance of required procedural
actions
The inspectors
observed that the operators rigidly adhered to management
expectations
regarding three way communications early in the scenarios,
but with increasing intensity of conditions.
the communications
were not
as consistent.
Overall. the Unit Supervisors
adequately briefed the
operators
at appropriate intervals during the'cenarios.
However, there
were
a few occasions
in which the briefings were not effective.
The inspectors
observed the training critique sessions
for the sessions.
The inspectors
noted that several
errors or performance
issues
were not
thoroughly addressed
during the critiques.
The inspectors
observed that
a board operator failed to detect that
a emergency diesel
generator
had
not started during two separate
checks of the 4kV shutdown board
indications.
While this was addressed
during the critique, the fact
that it was detected
on
a subsequent
check
was the focus rather
than'mproving
future performance.
In several
instances,
operators
volunteered
areas
in which their performance
needed
improvement
and the
training instructor did not sufficiently highlight the deficiency.
It
appeared to the inspectors that the training personnel
were not
consistently enforcing high standards
of proficiency during the critique
sessions.
Additionally, management
expectations
regarding self-checking
were not being rigidly enforced.
In the critiques.
the Shift Manager
was relied upon to provide the
majority of input regarding
crew performance.
It appeared to the
inspectors that it would be difficult for the Shift Manager
. during
complex plant conditions'o fully participate in the training and
identify all problems.
These observations
were discussed
with the
BFN Training Manager
and
Operations Training Manager.
On March 31,
1998, the senior resident
inspector
reviewed the Institute
of Nuclear
Power Operations
(INPO) Accreditation Evaluation Report dated
February 26,'1998.
The National Nuclear Accreditation Board renewed the
accreditation of six BFN training programs.
No major adverse
concerns
were identified in the report.
The inspectors
noted that the report
contained
some negative observations
involving poor identification and
addressing
of individual operator
performance
problems during simulator
critique sessions.
,c.
Conclusions
In several
observed control
room simulator training scenarios,
the crew
successfully
recognized the major events. utilized response
procedures,
and stabilized the unit.
In general
operator performance
issues
such
as
use of procedures
and communications
were addressed:
however,
management
expectations
for self-checking were not consistently
emphasized.
Ouring observation of the critique sessions,
the
inspectors
noted several
examples
which indicated that the training
08
08.1
Ml.l
14
personnel
were not consistently enforcing high standards
of overall
proficiency.
Miscellaneous
Operations
Issues
(92901)
Closed
Licensee
Event
Re ort
LER
50-296/97-005-00:
When
a Valve was
Malfunctioning,
an
LCO was not Entered.
This event
was discussed
in IR
97-09 and
IR 97-10.
Violation 296/97-10-03,
Failure to Complete
TS
Action for Inoperable Containment Isolation Valve was issued.
No new
issues
were identified in the LER.
This
LER is closed.
II. Haintenance
Conduct of Maintenance
Standb
Gas Treatment
S stem Filter Leak Testin
Ins ection Sco
e
61726
71707
On Harch 19.
1998,
one of the resident inspectors
observed
the
performance of portions of Surveillance Instruction O-SI-4.7.B.4,
Standby
Gas Treatment
(SBGT) System In-place Leak Test, of High
Efficiency Particulate Air
(HEPA) Filter Banks
on the "C" train of
SBGT.
The test is intended to implement the requirements of Technical Specification 4.7.B.2.b
when performed with other tests.
Observations
and Findin s
Portions of O-SI-4.7.B.4 had been successfully
performed during the
previous
day.
Dioctylphthalate
(DOP) testing of the upstream
filter in the "C" train of SBGT had been completed.
Beginning at Step
7.13, the procedure
involved
DOP testing of the downstream
HEPA filter.
DOP testing of the downstream
HEPA filter had been unsuccessfully
attempted
during the previous evening shi.ft.
Discussions with workers
indicated that the testing
was not successful
because
incorrect ports
on
the
SBGT train'had
been used.
The inspector
noted that the maintenance
workers
had ensured that the prerequisites
for the'testing
had been
completed before attempting the test again.
For the test,
a
DOP generator is used to inject
DOP solution into the
filter train upstream of the filter to be tested.
Test equipment is
used to determine the leakage of the
HEPA filters by measuring
how much
of the
DOP is removed
by the filter assembly.
The inspector
observed
several
unsuccessful
attempts to perform the testing of the downstream
filter.
The following observations
were made:
The ports for the testing
(DOP injection point and sensing points
for the monitoring equipment)
were not labeled to match the
procedure.
The equipment for the sensing lines for the
DOP test equipment
was
not standardized.
A copper tubing extension
was constructed
by
15
skill of the craft -on the spot" and used for the "upstream"
sensing line.
This extension
and its placement
in the train was
revised in attempts to obtain
a valid test.
~
At least
one attempt
was unsuccessful
because
the
DOP generator
did not have sufficient
DOP liquid loaded into it.
Although a
sightglass
is available,
the worker s were not familiar with what
the level should be.
The procedure did not address this subject.
~
After several
attempts.
a second
DOP generator
was obtained
and
both generators
were used to inject
DOP into the system
simultaneously.
The procedure did not indicate
how to ensure that
sufficient
DOP was injected into the system.
The inspector
noted
that step
9 of the test equipment procedure stated that the actual
upstream concentration of DOP would be indicated but no minimum
value or typical value was known.
The inspector noted that the
concentration visually appeared
low.
~
The workers were familiar with the operation of the TDA-2G
analyzer
used to measure
DOP concentrations
in the filter train.
They actively utilized Attachment
2 of the Surveillance
Instruction (SI) which provided step
by step guidance
on how to
operate the equipment.
~
The workers immediately recognized
unexpected test equipment
responses
and were not willing to accept
performance that did not
match the description in the procedure.
~
After about
4 attempts,
the maintenance
workers contacted
a system
engineer for assistance.
After several
more attempts
and
additional engineering
involvement, the
procedure
was revised to
utilize a different upstream injection port and the ports were re-
labeled.
Subsequently,
the test was completed.
~
Torquing of the
DOP injection port cover
was not addressed
in the
DOP test procedure.
The cover
was re-installed but it was not
torqued.
The inspectors
noted that other
SBGT procedures
had
torquing requirements
for this cover.
The system engineer
acknow'ledged
the inconsistency
and
PER 980503 was initiated.
Skill of the craft was heavily relied upon to complete this testing.
Equipment
was not standardized
and labeling was not good.
The
procedure, if implemented strictly as written'ould not be used to
successfully
perform the test (the injection point was apparently too
close to the filter).
Consequently.
the inoperability of the "C" train
of SBGT was extended at least
18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />
beyond the scheduled
maintenance
period.
TS require that written procedures
be established
and
maintained for surveillance testing of safety related equipment.
NRC
'nspection
Report 97-08 describes
NRC observation of other
SBGT testing.
The inspector
had noted reliance
on skill of the craft to satisfactorily
complete that testing
as well. but the major focus
had been issues
involving orientation of an instrument probe.
~ ~
16
On March 24. the inspector
reviewed the vendor manual for the
generator
used in the test.
The generator
was
a Air Techniques
TDA-6A
Aerosol Generator.
The inspector identified that the manual
indicated
that the generator capacity
was for systems
up to 500 cfm
(cubic feet
per minute).
Since the flowrates in the
SBGT systems
are
much higher.
(9.000 cfm) the inspector
questioned
the system engineer
about the
generator.
Section 5.3.5.2 of the
UFSAR describes
SBGT system'esting.
The
UFSAR specifically states that the aerosol
generator is capable of
supplying sufficient
DOP to test for leaks using the 9,000 cfm design
flow of one
SBGT train.
Subsequently.
the system engineer
confirmed
that the incorrect
DOP generator
had been
used for the testing.
Step
5.1 of O-SI-4.7.B.4 lists the equipment to be used
as
a Air Technique
.
generator
Model TDA-5A or equivalent.
The TDA-6A is not equivalent to
the TDA-5A model.
The incorrect model
DOP generator
was used for DOP
testing of all the
SBGT systems
and the Control
Room Emergency
Ventilation (CREV) system.
PER 980507
was initiated to address
the
issue.
TS -6.8. 1.1.c requires that written procedures
shall
be
established.
implemented.
and maintained for surveillance
and test
activities of safety-related
equipment.
Section 5. 1 of Surveillance
Instruction O-SI-4.7.B.4,
Standby
Gas Treatment
System In-Place
Leak
Test of High Efficiency Particulate Air Filter Banks,
and Section 5. 1 of
Surveillance Instruction O-SI-4.7.E.2.A, Control
Room Emergency
Ventilation System In Place
Leak Test, specifically state that an Air
Techniques
Incorporated
Model TDA-5A (or equivalent) Dioctylphthalate
(DOP) generator is to be used for the tests.
This deficiency is
identified as Violation 259,260,296/98-02-02,
Failure to Follow High
Efficiency Particulate Air Filter Testing Procedures.
Preliminary analysis
by engineering
indicated that the testing,
although
not performed in accordance
with the
recommended
methodology,
was
a
valid test of the filters.
Licensee
management
directed that the proper
capacity
DOP generators
be obtained
and the testing
be performed again
as
soon
as practical.
Larger capacity
DOP generators
were expeditiously
obtained
and the testing
was subsequently
performed again
on the
and
CREV systems.
The inspector
observed that extensive engineering
involvement was necessary
to complete the testing.'he
licensee
determined that the smaller
DOP generators
had been
used for testing of
the
SBGT and
CREV filters for at least the previously performed test
prior to the most recent.
The licensee
provided
a summary of an evaluation of using the lower
capacity
DOP generator
on the surveillance test.
The evaluation
indicated that the
DOP concentration
was sufficient to ensure that with
.005 percent penetration of the filter the downstream
DOP levels would
be within the sensitivity of the Model TDA-2G penetrometer.
The
evaluation stated that the 100 micrograms
per liter at 150
CFM generator
capacity correlated to 1.6 micrograms per liter upstream of the filters
at 9,000
CFM in the
SBGT trains.
The inspector noted that the
evaluation
assumed
uniform dispersal
of the aerosol
upstream of the
filter.
17
The inspector
reviewed portions of American National Standard Institute
(ANSI) N510-1975. Testing of Nuclear Air-Cleaning Systems.
TS 3.7.B.2
states that
DOP testing of the filters will be performed in accordance
with ANSI N510-1975.
The inspector noted that Section 10.4 of the
standard
stated that
DOP generator
capacity shall
be specified in the
test procedure
and shall
be sufficient to produce reliable penetrometer
readings at system penetrations
as low as 0.005 percent.
The inspector
had observed during the test that the
DOP did not appear to be well
mixed with the air flow prior to traveling through the
HEPA filter.
The
inspector
noted that Section
9 of ANSI N510-1975 specifically states
that an air-aerosol
mixing uniformity test is necessary.
This test is
used to verify that the
DOP injection and sample ports are located
such
that proper
mixing of the challenge
aerosol
in the air approaching
the
filter. occurs.
On April 6,
1998. the inspector
asked for the results of
the testing to ensure the proper ports were used.
On April 9,
1998, the
BFN Vice President
discussed
the status of the
issues with the Senior Resident
Inspector
(SRI).
At that time, the
licensee
was searching for the
SBGT systems
aerosol
uniformity test
data.
Licensee indicated that the test
was possibly completed
under
a
previous specification.
Documentation for the
CREV system distribution
test
was found and licensee
subsequently
informed the inspector that the
latest
DOP testing of the
CREV system matched the configuration used in
that test.
As of April 9. plant management
did not consider the plant
in a nonconforming status.
Management
concluded that the most recent
HEPA testing
done had been satisfactorily completed.
Essentially,
the
justification was that so much
DOP was injected that it must have been
distributed adequately.
The inspector
discussed
with plant management
the regulatory concern that it was not clear that the latest testing
was
adequate.
The SRI also discussed
status of issues with Region II
management.
On Apri 1 10,
1998, the licensee
developed
Technical Instruction TI-370
which provided instructions for performing aerosol
dispersion uniformity
testing
and
A manifold of plastic pipe was
constructed for DOP injection and sampling in accordance
with NUCON
drawings
and instructions.
The manifold was installed into the filter
train for dispersion of DOP prior to the downstream
HEPA filter.
A
NUCON representative
advised the licensee
on details of testing
and ANSI
N510-1975 requirements.
The SRI observed
most of the testing
on "A"
SBGT train.
The SRI observed
assembly of the manifold and inspected
both
HEPA filter banks.
The filters appeared
to be in good condition
and properly mounted.
By visual examination through
a port. the
inspectors
observed that there
seemed
be more even dispersion of DOP
upstream of the downstream
HEPA than during previous testing.
On April
12,
1998, the licensee
completed testing per TI-370 on all three
trains.
The results indicated that all the
HEPA filters had acceptable
efficiency and there
was not excessive
bypass
flow.
TS 3.7.B.2.a
requires that testing of the filters be performed in
accordance
with ANSI N510-1975.
The procedure
was not adequate
to
ensure that the leak testing of the downstream filters was conducted in
18
accordance
with the ANSI Standard.
The subsequent
testing confirmed
that the dispersion of the aerosol
for testing of the upstream
filters was adequate
using the previous test method.
The
UFSAR and
TS
state that both filters are to be tested in accordance with the ANSI
standard.
This issue is identified as Violation 259,260,296/98-02-03,
Inadequate
Testing of Downstream Standby
Gas Treatment
HEPA Filter.
Conclusions
The licensee did not initially perform an aggressive
review of the
inspector's
concern that
SBGT testing relied upon the skill of the
maintenance craft to work around procedural
obstacles.
The
NRC
identified that the model of DOP generator
used for testing of the
and
CREV systems
was not equivalent to that model required
by the
procedure.
A violation was identified for failure to follow testing
procedures.
(Violation 259,260,296/98-02-02.
Failure to Follow High
Efficiency Particulate Air Filter Testing Procedures).
Additional
NRC
review identified that the procedure for testing the
SBGT downstream
filter did not meet the requirements of ANSI N510-1975 as required by
TS.
( Violation 259,260,296/98-02-03.
Inadequate
Testing of Downstream
Standby
Gas Treatment
HEPA Filter).
Hi h Pressure
Coolant In ection
Exhaust Line Ru ture Disc
Preventive
Maintenance
Ins ection Sco
e
62707
One of the resident
inspectors
observed portions of the work activities
involved in replacement of the HPCI exhaust line rupture disc
assemblies.
The inspector also observed
portions of the American
Society of Mechanical
Engineering
(ASME) Section
XI inspection of the
removed disc assemblies.
Findin s and Observations
The preventive maintenance
was performed in accordance with Work Order
(WO) 97-004682-000
and Mechanical
Preventive
Maintenance
Instruction
MPI-0-073-TRB001,
HPCI Turbine Preventive Maintenance.
Section 7.5 of
the MPI, HPCI Turbine Exhaust
Rupture Disc Replacement,
contained
appropriate
guidance to properly perform the work.
The inspector
verified that the work instructions incorporated
guidance
included in
the vendor reference
manual;
BfN-VTD-F103-0050, Installation and
Maintenance
Instructions for Fike Rupture Disc Assemblies.
The
inspector also reviewed documentation
and the nameplates
on the new disc
assemblies
to verify that the replacement
discs were the correct
pressure
value.
The inspector
observed that maintenance
personnel
were
careful to adhere to cleanliness
requirements
during handling of the
'ssemblies.
Technical
Instruction TI-362, Inservice testing
Program of Pumps
and
Valves, sets forth the details of the
BFN inservice testing program.
The inner
HPCI system rupture discs are listed to be visually inspected
19
in accordance
with Surveillance Instruction 2-SI-3.2. 19. Inspection of
ASHE Section
XI Rupture Discs.
The inspector
observed portions of the
performance of the inspection.
Step 6.3 of 2-SI-3.2. 19 describes
criteria for the "as-found
condition of the disc.
The inspector
noted
that the engineer
was performing the inspection for cracks,
dents,
or
excessive
corrosion
by visually examining the exterior surface of the
vacuum support
component of the disc assembly.
The disc assemblies
consist of a vacuum support piece.
two rupture discs'nd
a dust cover
spot welded together in an assembly.
Host of the rupture disc material
.
is not visible behind the vacuum support piece.
The inspector
asked if
the assemblies
were disassembled
so that an examination of the rupture
disc material could be performed.
Subsequently,
the licensee
disassembled
and
removed the inner disc assembly
and identified that the
rupture disc material
had pitting, indications of corrosion,
and
some
cracking.
Although the holes were very smally through wall penetrations
existed in both of the discs.
The observed conditions failed the as-
found criteria in 2-SI-3.2. 19.
At the close of the report period. the
licensee
was performing
a closer
review of the degradation.
The process utilized to determine the as-found conditions of the discs
was not adequate
since the disc material itself was not examined.
Degradation of the disc material
was significant since the rupture
setpoint could be adversely affected.
Additionally, the inspector noted
that drawing 2-4E812-1-ISI depicts the inner disc assembly
as the ASHE,
code class 2'oundary.
Through wall defects of such components
are
degradations
and should
be evaluated.
The licensee
examined the rupture discs for the Unit 3 HPCI system
on
April 14,
1998,
and identified that no degradation
was present.
Additionally, the licensee
noted that the Unit 3 disc assembly contained
only one disc instead of the two thinner material discs
found in the
Unit 2 assembly.
At the close of the inspection period. the licensee
was reviewing this issue with the vendor.
The RCIC system discs are
provided by the
same manufacturer
but are smaller and
may not be similar
in details of assembly.
The inspector
noted that Section 1.3.4.2 of ANSI/ASHE ON-1 states that
classes
2 and
3 nonreclosing
pressure relief devices shall
be replaced
every five years unless historical data indicates
a requi rement for more
frequent replacement.
The vendor manual
contained
a statement
recommending that the discs
be replaced
every year under normal
operating conditions.
Licensee engineers
indicated to the inspector
that this was interpreted to apply to systems
which are normally
operating.
not systems
operated for very short time periods.
Surveillance testing of the HPCI system
had been completed
satisfactorily previous to the replacement of the disc.
Normal
exhaust line pressures
are well below the rupture setpoint of the disc.
It appeared that the licensee's
actions were in compliance with
ANSI/ASHE OH-1 requirements
for periodic replacement of the discs.
The
major concern is that the degraded condition would not have been
'
20
identified and evaluated.
Violation 260/98-02-04.
Failure to Identi fy
Degraded
HPCI Rupture Discs addresses
this issue.
Conclusions
Periodic replacement of the High Pressure
Coolant Injection System
turbine exhaust
rupture disc assembly
was performed satisfactorily
except that the as-found inspection process
was not adequate
to identify
that the disc material
was degraded.
The licensee did not identify the
degradation until the inspector
questioned
the inspection
method.
(Violation 260/98-02-04,
Failure to Identify Degraded
HPCI Rupture
Discs).
Fix-It-Now Team Observations
Ins ection Sco
e
62707
The resident inspector
observed
Fix-It-Now (FIN) team work to ensure
that'the work was performed within specific procedural
guidelines.
Specifically, the inspectors
focussed
on implementation of Site Standard
Practice SSP-lZ.3,
Equipment Clearance
Procedure for the performance of
work not under the control of a clearance.
Observations
and Findin s
On March 2,'998,
an inspector
observed the FIN team's troubleshooting
efforts to determine the cause of the refuel
zone supply outboard
isolation damper,
2-HS-064-0005. failing to indicate full closed
when
the fan was
removed from service.
The troubleshooting effort was well
controlled with control
room operators
aware of the FIN team's
planned
activities and involved in the damper manipulation.
FIN crew
troubleshooting
determined that the associated
limit switch, 2-LS-064-
0005,
needed to be replaced.
The FIN crew stopped troubleshooting
activities and
a Work Order
(WO) was developed to address
the limit
switch problem.
On March 12,
1998.
an inspector observed
the FIN team troubleshooting
a
problem with the
3B Steam Packing Exhauster
Breaker.
The
troubleshooting
was conducted in accordance
with Work Order
(WO)
98-002759-000.
A thorough briefing was held prior to the work.
The FIN
team
SRO actively supervised
the work.
The troubleshooting
involved
opening electrical
breaker
enclosures
and monitoring equipment
performance
as control switches
were operated.
The workers utilized
proper caution regarding the proximity to energized electrical
equipment.
At the conclusion of the troubleshooting efforts, the work
was stopped
pending additional
maintenance
planning.
On March 24.
1998.
an inspector
observed portions of FIN crew
maintenance activities to repair
3C2 waterbox screen
linkages.
The
maintenance
work was performed with the breaker
handswitch for the
normal
power supply to the Condenser
Tube Cleaning
System
3C2 in the off
position with an Assistant Unit Operator 'stationed in the area to ensure
21
the system
was not energized.
The work performed required maintenance
personnel
to replace portions of the linkage between the motor operator
and the screen
mechanism.
Discussions with the licensee
indicated that
this work would not be performed with the motor operator energized
due
to the risk to personnel
safety.
Site Standard
Practice,
SSP-12.3,
Equipment Clearance
Procedure,
described the performance of work not under the control of a clearance.
The observation of work on March 24, could not be directly correlated to
the exceptions
allowed by the procedure.
The inspector discussed
the
observations
with the Operations
Superintendent.
Subsequent
discussions
with licensee
management
confirmed the FIN team practice of using
operations
personnel,
in some cases,
to ensure that the component
was
maintained in the safe position instead of using
a clearance to
reposition the component.
The licensee is reviewing the procedure to
determine if this is acceptable
implementation of the procedure
and
management
expectations.
Pending
NRC review of the licensee's
evaluation, this item is identified as Inspection Follow-up Item (IFI)
260,296/98-02-05.
Use of Personnel
in Place of Equipment Clearances.
The inspector also reviewed the evaluation associated
with a problem
evaluation report which was associated
with work that the FIN team
performed.
Problem Evaluation Report
(PER)
980035 described
work that
was being performed
on the sewage lift station
and resulted in a sewage
overflow.
Work was performed
on the lift station in the absence
of
individuals from the Environmental
Section
who were familiar with the
lift station operating controls.
The lift station
was apparently left
with the controls in a configuration which did not allow the remaining
pump to operate automatically at some time during or following the
Clearance
replacement.
The inspector concluded that deficiencies in
this incident did not involve an inappropriate decision to perform
maintenance without a clearance.
Conclusions
The inspector questioned
the procedural
guidance
and implementation
regarding the use of personnel.
in some cases,
to ensure that
a
component
was maintained in the safe position instead of using
a
clearance.
Licensee
management
is reviewing the practice to determine
if procedural
guidance is appropriate
and management
expectations. were
met.
Additional
NRC review of the licensee's
evaluation is necessary
( Inspection Follow-up Item ( IFI) 260,296/98-02-05,
Use of Personnel
in
Place of Equipment Clearances.)
Residual
Heat
Removal Service Water
Pum
Re lacement
Ins ection Sco
e
62707
One of the resident
inspectors
reviewed work associated
with the
C3
Residual
Heat
Removal Service Water
(RHRSW)
pump replacement
and the
C2
RHRSW pump strainer
replacement.
The inspector
reviewed selected
vendor
and licensee
documentation to verify that activities were acceptable.
b.
Observations
and Findin s
22
M8
M8.1
The inspector
reviewed completed work order
(WO) packages
for
98-002355-000
and 98-002013-001
and noted minor documentation
discrepancies.
The licensee
immediately addressed
discrepancies
associated
with WO 98-002355-000
and documented
the issues
in problem
evaluation report
(PER) 98-003901-000.
The inspector
observed
replacement of the
C2
RHRSW pump into position in
the
pump foundation hole and noted that workers were careful
and
appropriately attentive to the activity.
Following removal of the
C3
RHRSW pump head to transfer it to the new
replacement
pump. the inspector noted that significant shaft wear was
apparent
on the old pump shaft in the area of the
pump packing.
A
problem evaluation report
(PER 980521)
was initiated to address
the
wear.
The licensee also removed the packing from the
C2
RHRSW pump for
inspection of the shaft.
The inspector noted that although
some wear
was evident, it was substantially less than that identified on the
C3
pump.
The wear on the
C2
RHRSW pump was determined to be acceptable
and
the
pump was reinstalled.
While reviewing vendor documentation.
the inspector
questioned
a
statement
in the vendor.'s bolt torquing procedure
(BFN-VTD-8580-0160).
The vendor manual stated that all external bolting on subassemblies
or
pumps shipped
assembled,
must be retorqued to specified values before
installation.
The inspector noted that this requirement
was not
included in the work order step text for the
C3
RHRSW pump which was to
be replaced.
The licensee
contacted
the vendor who subsequently
issued
a letter to the licensee
documenting that if the pump has not been
disassembled,
there was
no need to retorque the bolting prior to
installation.
The inspector verified that the stainless
suction strainer.
which
replaced
a carbon steel strainer
on the
C2 and
C3
RHRSW pumps,
was
described
as
an option in the material of construction section of the
vendor technical
manual
(BFN-VTD-.8580-0180).
In addition, the inspector
reviewed design
change notice V39888A which evaluated
the change of
material to stainless
steel.
No problems were identified.
Conclusions
Major maintenance activities on two residual
heat
removal service water
pumps were conducted well.
Placement of the
pump assemblies
was
performed carefully and actions to address
shaft wear were good.
Miscellaneous
Maintenance
Issues
(62707,
92902)
Closed
Licensee
Event
Re ort
LER
260/97-004-00:
Technical
Specification Survei llances
Were Not Performed
During Refueling Outage
Time frames.
This
LER addresses
two examples
in which surveillance
C
23
testing which TS required to be performed "during
a refueling outage"
was performed with the unit at power.
Violation 260/97-09-01,
Functional Testing of Snubbers
While not in'Refueling Outage
addressed
the first example
and remains
open pending
NRC review of corrective
actions.
The other
example involved suppression
chamber to reactor
building vacuum breakers
and was identified by the licensee.
The
licensee
reviewed other
TS testing requirements
and found no other
examples of improperly scheduled testing.
The
LER concluded that
testing of the components
at power did not adversely affect plant
safety.
The
LER is closed.
Additional
NRC review of corrective actions
will be performed for closure of the violation.
H8.2
Closed
Licensee
Event
Re ort
LER
260/97-008-00:
Hain Steam Safety
Valves Exceeded
Technical Specification
(TS) Required Setpoint Limit as
a Result of Pilot Valve Disc/Seat
Bonding and
Closed
Licensee
Event
Re ort
LER
296/97-003-00:
Hain Steam Safety
Valves Exceeded
Technical Specification
(TS) Required Setpoint Limit as
a Result of Disc/Seat
Bonding.
These
LERs address test results obtained
in March 1997 and
December
1997 which indicated that 5 of the
13 Unit 2
valves
and
11 of the
13 Unit 3 valves failed to meet .the
TS setpoint
tolerance of +/- 11 psia.
Some valves lifted below the setpoint
tolerance.
while others were above the allowed setpoints.
Prior to
plant operation,
the Safety Relief Valve (SRV) pilot valve cartridges
were replaced with newly certified cartridges.
The cause
was attributed
to the generic problem of corrosion bonding at the pilot valve disc/seat
interface
on two stage Target
Rock valves.
There has
been
numerous
previous
LERs for such conditions at
BFN.
The issue is still under
review by the Boiling Water Reactor
Owner Group
(BWROG)
SRV Drift Fix
Development
Committee
and the manufacturer.
BFN continues to
participate in the
BWROG evaluation for a permanent solution to the
problem.
Some of the failed pilot cartridges
were of the satellite disc
material
and
some were of the platinum-satellite material.
BFN has
installed modifications which minimize the effects of setpoint drift
by'lectrically
actuating the
SRVs through use of a pressure
switch.
Additionally, BFN has requested
a TS revision to allow the setpoint to
be +/- 3 percent.
The
LERs addressed
the safety consequences
of the
setpoint drift and concluded that
TS safety limits would not have been
exceeded
during operational
events.
The resident inspectors
have also
.discussed
the
BFN safety valve performance with Nuclear Reactor
Regulation
(NRR) personnel
tasked with monitoring the generic corrosion
bonding issue to ensure that the licensee is completing expected
actions.
.These
LERs are closed.
M8.3
Closed
Violation 260 296/96-10-02:
Inadequate
Supervisory Oversight of
EDG Painting Activities.
The licensee's
response
to the violation.
dated
December
6,
1996, stated that the deficiencies
were caused
by
failures to meet
management
expectations
regarding oversight of a
maintenance activity.
The painting was stopped after the issues
were
identified and increased
supervisory attention
was provided prior to
continuation of the painting.
A specific "Painting Expectations"
I
24
document
was issued
as
a Maintenance Night Order.
The resident
inspectors
have been closely monitoring the effectiveness
of supervisory
oversight during the
12 year maintenance activities
on the
EDGs.
Inspection Reports
97-12 and 98-01 contain descriptions of inspection
observations.
The inspectors
have noted that maintenance
supervision
has
been consistently actively involved in the work.
During observations
of
the work, the
inspectors
have noted the performance of selected
requirements
set forth in the "Painting Expectations-
paper.
Through reviews of Cause Determination Evaluations
(CDEs) to address
Maintenance
Rule requirements for a containment isolation valve failure;
the inspectors
noted that deficient painting was involved in that issue.
On December 16,,1996,
valve 3-FCV-64-34 failed to close within the
required time during testing.
Problem Evaluation Report
(PER) 961716
was initiated.
The
PER was
a "C" level
and was closed to Work Request
(WR) 96-008224.
The inspectors
noted that the description of work
performed
on the
WR indicated that paint had been applied incorrectly to
a seal
over
a vent valve.
,The
WR indicated that the paint was removed
to restore the valve to proper operation.
After additional
review, the
inspectors
concluded that the primary cause of this instance of
misapplied paint was probably not a lack of overall supervision.
In
this specific case, it was not so obvious that the paint should not have
be applied to the particular part.
The inspectors
discussed this issue
with Nuclear Assurance
personnel
from a perspective of the corrective
action program.
In this case.
operability of a containment isolation
valve was adversely affected
by a deficiency related to that cited in an
NRC Notice of Violation several
months earlier.
This was difficult to
detect since the
PER was closed to the
WR as permitted
by the corrective
action program and only the
WR description described
the causal
factors.
Appendix
C of SSP-3.4,
Corrective Action Program.
sets forth criterion
for issues that represent
Level
8 PERs.
The criteria does not
explicitly require
a containment isolation valve failure to be
classified
as
a Level
8 PER..
In response to the inspector's
observations,
Nuclear
Assurance
and management
evaluated
methods to
review effectiveness of corrective actions for
NRC violations.
The inspectors
concluded that overall maintenance
supervision including
painting activities have also been strong in recent months.
No other
issues
involving misapplication of paint have
been identified.
The
violation is closed.
Closed
Licensee
Event
Re ort
LER
260/97-001-00:
Reactor
Scram as
a
Result of Personnel
Error During Surveillance
Testing.
This event
was
discussed
in IR 97-05.
Inspection Follow-up Item 260/97-05-04 'purious
Main Steam Isolation Valve Closure
on Turbine Trip. was opened to review
high steam flow instrumentation
issues.
Violation 260 '96/97-05-02,
Failure to Implement Maintenance
Procedures.
was issued
and addressed
the personnel
error which initiated the event.
No new issues
were
identified in -the LER.
This
LER is closed.
~ 4
25
III. En ineerin
Conduct of Engineering
10 CFR 50.59 Safet
Evaluation Pro
ram
Ins ection Sco
e
37001
The inspectors
performed
a programmatic
review of the licensee's
10 CFR 50.59 procedures
and training requirements
in order to verify compliance
with the regulations
An evaluation of the
licensee's
performance
in implementing the requirements of Section 50.59
was also performed to assess
the licensee's
resolution of safety issues
related to change.
tests or experiments.
Observations
and Findin s
Procedure
SPP-9.4,
10 CFR 50.59 Evaluations of Changes,
Tests
and
Experiments,
Revision
0
~ established
requirements for review and
evaluation of changes
as required
by 10 CFR 50.59.
The requirements
specified included performing; 1)
a nuclear safety test or Safety
Assessment
and 2)
a licensing test or screening
review and safety
evaluation.
The procedure
assigned
responsibility to line managers
for
assigning qualified preparers
and reviewers for performing safety
assessments,
screening
reviews.
and safety evaluations
consistent with
the complexity and scope of the proposed activity.
Section 3.3,
Qualification and Training of Personnel.
further assigned responsibility
to the Manager of Nuclear Training for administering the
training program and identified personnel
who are required to be
trained.
The inspector
reviewed lesson plan
EGT 024.007, Qualified 50.59 Preparer
Training,
and determined that it provided specialized
engineering
training in preparing
10 CFR 50.59 Safety Evaluations.
The inspector
also reviewed the "Nuclear Employee Training System
(NETS)
-
LCG 1064.
50.59 Preparer List" dated
March 23,
1998,
and chose
a random selection
of nineteen
10 CFR 50.59 Qualified Reviewers.
These persons
selected
were verified to have completed the training course
requirements.
Based
on objective evidence
reviewed the inspector
concluded that the
Qualified 50.59 Preparer Training met ANSI-3. 1-1981,
concerning
maintaining minimum qualification in operating
and support organizations
appropriate for safe
and efficient operation of Browns Ferry.
Technical Specification
(TS) Section 6.5. 1.6.f assigns
responsibility to
the Plant Operations
Review Committee
(PORC) for review of safety
evaluations
completed
under the provisions of 10 CFR 50.59.
This
responsibility
has
been delegated to the Nuclear Safety Review board
(NSRB)
- Safety Assessment/Safety
Evaluation Subcommittee.
The
NSRB has
identified deficiencies with safety assessments
and safety evaluations
during their reviews.
Because of these recurring problems
an
Report Briefing was prepared to bring these
problems to the attention of
all Qualified 50.59 Preparers.
The briefing package
contained
a summary
26
of problems identified by the
NSRB in addition to problems identified by
other reviewers.
Information contained in the briefing package
was used
as lessons
learned in order to facilitate improving performance
in
preparation
and review of 10 CFR 50.59 safety evaluations.
Based
on
objective evidence
reviewed the inspector
concluded,
that the licensee
has
used lessons
learned
and taken actions for improving the preparation
of 10 CFR 50.59 Safety Evaluations.
The inspector
reviewed six 10 CFR 50.59 safety evaluations
chosen at
random from the licensee'.s
1997 Annual Operating Report submittal.
Five
safety evaluations
were determined to be technically adequate
and
demonstrated
consistency
between the design
changes
and information in
the
The safety evaluation prepared for plant modifications
DCN
No. T30200A,
was identified as being deficient, in that the
incorrectly stated the scope to include the changes to FSAR Table 7.8-2.
Plant modification
OCN No. T30200A, "Issue Unit 2 and
Common Syst'm
NESSDs,"
was approved
on April 28,
1994, in order to issue Unit 2 and
common Nuclear Engineering Setpoint
and Scaling
Documents
(NESSOs).
The
scope of the plant modification stated that the
NESSDs were revised to
reflect minor changes
in their parent calculations.
The total
number of
NESSDs within the scope of the design
change notice also included
NESSDs
that were associated
with earlier issued
DCNs and
NESSDs that were
required for Units 3 restart.
An attachment
"A" to the plant
modifications package
gave detailed information concerning
what had been
changed
by the
NESSDs including implementation
requi rements.
Safety Evaluation
No.
FDCN 940015 Revision 0. dated
June
14,
1994,
was prepared for design
change notice
OCN no.
T30200A.
This safety
evaluation stated that the setpoint
and scaling
changes
issued with the
DCN impacted
FSAR Table 7.8-2.
Based
on review of the safety evaluation
the inspector determined that the following Regulatory Guide 1.97 Post
Accident Monitoring instruments
were impacted.
~
Orywell Pressure
Indication/Recorder
~
Drywell Temperature
Indication
Orywell Temperature
Recorder
~
Suppression
Chamber Water Level Indication (Narrow/Wide Range)
~
Post-accident
Containment
High Level Radiation
Recorder
~
Hydrogen Analyzer
(Normal/PAM).
.
Suppression
Chamber Water Temperature
Indication
FSAR Table 7.8-2.
sheets
1 and
2 was revised to show the range
column of
the as-installed
instrumentation.
Additionally. the Set Trip Point
column was revised to remove the alarm setpoint
values. of the various
instruments
and describe only the trip functions.
Based
on review of-
27
Safety Evaluation
No.
FDCN 940015:
the inspector
determined that
an
evaluation of the changes
to the instruments
ranges
against the
requirements of Regulatory Guide 1.97 had not been performed
by this
SER.
Additionally, review of the instrument loops listed on Attachment
"A" of the design
change notice revealed that the Post-accident
'onitoring instruments
were not within the scope
DCN No. T30200A.
On April 24.
1998,
TVA licensing was informed that objective evidence
indicated that the installation of PAM instruments
and subsequent
changes
to the
UFSAR were accomplished
by a plant modification other
than
DCN No. T30200A.
Pending
NRC review of the other design
change
notice and
10 CFR 50.59 safety evaluation this is identified as IFI 50-
260,296/98-02-06.
Review
DCN and Safety Evaluation for FSAR Table 7.8-2
Changes.
Conclusions
The inspector
concluded that the licensee's
gualified 50.59 Preparer
Training met ANSI-3. 1-1981.
concerning maintaining minimum qualification
in operating
and support organizations
appropriate
for 'safe
and
efficient operation of Browns Ferry.
The licensee
has
used lessons
learned
and taken actions
for improving the preparation of 10 CFR 50.59
Safety Evaluations.
Of the six 10 CFR 50.59 safety evaluations
chosen
for review, five were determined to be technically adequate
and
demonstrated
consistency
between the design
changes
and information in
the
One safety evaluation
had
a minor deficiency, in that the
SER incorrectly stated the scope of the change.
IV. Plant
Su
ort
Radiological Protection
and Chemistry
(RP8C) Controls
Postin
of Notices to Workers
Ins ection
Sco
e
71750
A resident
inspector
reviewed the licensee's
posting of notices to
workers requi red by 10 CFR 19. 11.
Observations
and Findin s
The inspector verified that the required notices
were posted at all
security checkpoints to the protected
area.
The Materials Procurement
Center
and the Administration Building located outside the protected
area
were also checked.
The inspector
found that
some of the required
information was not posted at these locations.'owever,
as allowed by
10 CFR 19. 11, the licensee
posted
a notice that described
the documents
and stated that the documents
were available to be inspected
in the
Technical
Information Center.
The inspector verified that the required
documents
were available in the
Technical
Information Centers
The inspector interviewed Technical
~ y,
28
Information Center
personnel
and found them to be knowledgeable of the
documents
and their locations (e.g..
operating license
and amendments,
code of federal regulations).
c.
Conclusions
The licensee properly'osted, required notices to workers
as required
by
10 CFR 19. 11.
Technical
Information Center personnel
were knowledgeable
of the locations of documents
required to be available to workers.
V. Hang ement Meetin s
X1
Exit Heeting Summary
The resident
inspector
presented
inspection findings and results to
licensee
management
on April 20,
1998.
The licensee
provided
some
dissenting
comments
regarding the issue in Section H1.2.
The licensee
stated that the
ASHE code requirements
had been met for inspection of
the rupture disc.
Other meetings to discuss
report issues
were
conducted during the report period including formal meetings with plant
management
on March 6 and April 3.
1998.
Subsequently,
additional
discussion of the issues
in Section 05. 1 were discussed
by telephone
with the inspector
and regional
management.
The licensee
acknowledged
the findings presented.
Proprietary information is not included in this
inspection report.
PARTIAL LIST OF PERSONS
CONTACTED
Licensee
T. Abney, Licensing Manager
J. Brazell, Site Security Manager
R. Casey.
Manager.
Access Authorization/Fitness for Duty
R. Champion,
Operations Training Manager
R. Coleman, Acting Radiological Control Manager
J.
Corey, Radiological Controls
and Chemistry Manager
C. Crane, Site Vice President,
Browns Ferry
R. Greenman,
Training Manager
J.
Johnson.
Site Quality Assurance
Manager
R. Jones.
Assistant Plant Manager
R. Moll. System Engineering
Manager
G. Little. Operations
Manager
D. Nye, Site Engineering
Manager
D. Olive. Operations
Superintendent
J.
Shaw,
Design Engineering
Manager
K. Singer,
Plant Manager
J. Schlessel,
Maintenance
Manager
IP 37001:
IP 37551:
IP 40500:
IP 62707:
IP 61726:
IP 71001:
IP 71707:
IP 71750:
IP 73756:
IP 81502:
IP 82701:
IP 83750:
IP 84750:
IP 86750:
IP 92901:
IP 92902:
IP 92903:
IP 93702:
29
INSPECTION PROCEDURES
USED
10 CFR 50.59 Safety Evaluation
Program
Onsite Engineering
Licensee
Self-Assessments
Maintenance
Observations
Surveillance
Observations
Licensed Operator Requalification
Program Evaluation
Plant Operations
Plant Support Activities
Inservice Testing of Pumps
and Valves
Fitness
For Duty Program
Operational
Status of the Emergency
Preparedness
Program
Occupational
Radiation
Exposure
Radioactive
Waste Treatment.
and Effluent and Environmental
Monitoring
Solid Radioactive
Waste
Management
and Transportation
Of
Radioactive Materials
Follow-up-Plant Operations
Follow-up-Maintenance
Follow-up-Engineering
Prompt Onsite
Response to Events
ITEMS OPENED
DISCUSSED
AND CLOSED
OPENED
~T
e
Item Number
Status
259,260,296/98-02-01
Open
259,260,296/98-02-02
Open
259,260,296/98-02-03
Open
Descri tion and Reference
Failure to meet minimum shift crew
requirements
(Section 05. 1).
Failure to Follow High Efficiency
Particulate Air Filter Testing
Procedures
(Section Hl.1).
Inadequate
Testing of Downstream
Standby
Gas Treatment
HEPA Filter
(Section Hl.l) .
260/98-02-04
IFI
260,296/98-02-05
IFI
260, 296/98-02-06
Open
Open
Open
Failure to Identify Degraded
Rupture Discs (Section H1.2).
Use of Personnel
in Place of
Equipment Clearances
(Section M1.3).
Review
DCN and Safety Evaluation for
FSAR Table 7.8-Z Changes
(EA No. 98-
241) (Section E1.1).
CLOSED
~T
e
Item Number
LER
260/97-004-00
LER
296/97-003-00
260. 296/96-10-02
Status
Closed
Closed
Closed
Closed
Closed
Closed
30
Descri tion and Reference
When
a Valve was Malfunctioning'n
LCO was not Entered
(Section 08. 1).
Technical
Speci fi cation
Suryeillances
Were Not Performed
During Refueling Outage
Time frames
(Section M8.1).
Main Steam Safety Valves Exceeded
Technical Specification
(TS)
Required Setpoint Limit as
a Result
of Pilot Valve Disc/Seat
Bonding
(Section H8.2).
Hain Steam Safety Valves Exceeded
Technical Specification
(TS)
Required Setpoint Limit as
a Result
of Disc/Seat
Bonding (Section M8.2).
Inadequate
Supervisory Oversight of
EDG Painting Activities (Section
M8.3).
Reactor
Scram as
a Result of
Personnel
Error During Surveillance
Testing (Section H8.4).
ig