ML18038B979
| ML18038B979 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 10/08/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B977 | List: |
| References | |
| 50-259-97-09, 50-259-97-9, 50-260-97-09, 50-260-97-9, 50-296-97-09, 50-296-97-9, NUDOCS 9710230009 | |
| Download: ML18038B979 (62) | |
See also: IR 05000259/1997009
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License
Nos:
50-259.
50-260.
50-296
DPR.-68
Report
Nos:
50-259/97-09,
50-260/97-09.
50-296/97-09
Licensee:
Valley Authority
Facility:
Browns Ferry Nuclear Plant.
Units 1, 2,
8 3
Location:
Corner of Shaw and Browns Ferry Roads
Athens'L
35611
Dates:
August
3 - September
13,
1997
Inspectors:
Approved by:
L. Wert, Senior Resident
Inspector
(SRI)
J. Starefos,
Resident
Inspector
D. Thompson,
Special
Inspections
Inspector
(Sections
S3
~ S6,
S7
~
SB)
P.'aylor,
Project Engineer
C. Patterson,
- Brunswick
(Sections
08. 1,
MB. 1-8.3, E8.2-8.3)
M. Lesser,
Chief
Reactor Projects
Branch
6
Division of Reactor Projects
Enclosure
2
9710230009
971008
ADQCK 05000259
G
0
0
EXECUTIVE SUMMARY
Browns Ferry Nuclear Plant.
Units l. 2,
8 3
NRC Inspection
Report 50-259/97-09,
50-260/97-09,
50-296/97-09
This integrated
inspection included aspects
of licensee operations,
engineering,
maintenance,
and plant support.
The report covers
a six-week
period of resident
inspection
and inspection in the security area
by a
Region II inspector.
0 erations
Initial review of the failure of containment isolation valve 3-FCV-64-34 to
close during
a test raised questions
regarding the operability status of the
valve when it failed to close after the problem was believed to have been
resolved.
Additional review of the sequence
of events
and the specific
failure mechanism is necessary
to determine if a violation of regulatory
requirements
occurred.
(Unresolved
Item 50-296/97-09-06,
Actions for
Containment Isolation Valve, Section 01.1).
During Plant Operations
Review Committee
(PORC) meetings,
the committee
conducted
good reviews of the presented
material.
PORC members
asked probing
uestions
regarding the overall safety of the activities and appropriately
ocused
on whether
the change
represented
an unreviewed safety question or was
prohibited by Technical Specifications.
(Section 07. 1)
Maintenance
The inspectors identified that the licensee
was not properly implementing
procedural
controls over scaffolding in the Unit 2 reactor building.
In some
cases,
scaffolds near safety related
equipment
were not constructed
in
accordance
with limitations in the procedure
or in the requi red engineering
evaluation.
The scaffolding assembly checklist was not being properly
completed.
Some procedural
requirements,
which would be difficult to
complete,
were not being implemented.
No safety systems
were rendered
by the noted deficiencies.
The inspectors
concluded that the
number
and nature of the deficiencies indicate that supervisory personnel
are
not enforcing standards
and failed to ensure that procedural
requi rements
are
satisfactorily met. (Violation 260/97-09-02,
Scaffolding Controls Not Properly
Implemented,
Section M1.1).
The inspectors
identified that the licensee
was conducting functional testing
of snubbers
on safety related
systems with the unit at power.
Technical
specifications state that snubber
functional testing is to be performed during
refueling outages.
Procedural
controls for the testing did not adequately
enforce the
TS requirements.
(Violation 260/97-09-01.
Functional Testing of
While Not in Refueling Outage Conditions.
Section M1.2).
~
Cl
41
Observation of several
selected
maintenance activities indicated that the work
was well planned
and executed.
Specifically,
As Low As Reasonably
Achievable
(ALARA) planning of contingencies
was good with regard to the high radiation
evolution observed.
The prejob brief in preparation for C3 emergency
equipment cooling water
pump work was strong.
(Sections Hl.3-1.5)
En ineerin
Review of residual
heat
removal
system service water
pump inservice testing
data
and methodology indicated that the repeatabi lity and effectiveness
of the
testing could be improved.
Inspection
Followup Item 50-260,296/97-09-07,
RHRSW/EECW
Pump Flow Testing Issues.
(Section El. 1)
The licensee's
actions
regarding pressurization
of portions of the Unit 2
shutdown cooling suction piping were acceptable.
The licensee
pursued the
problem in a reasonable
manner
and the present
conditions
do not represent
an
immediate safety concern.
Licensee
management
has indicated that the intent
is to effectively address
the issue
such that it will not exist once the unit
is returned to power after the refueling outage.
(Section
E2. 1)
Plant
Su
ort
A random review of plans,
records.
reports,
and interviews with appropriate
individuals verified that security plan and procedure
changes
did not decrease
the effectiveness
of the Physical Security Plan.
(Section
S3. 1)
Licensee
management
provided appropriate
and excellent support for the
Physical Security Program.
Examples of the excellent
management
support were
the support in preparation for the Operational
Safeguards
Response
Evaluation
and the excellent maintenance
and engineering
support for the security
equipment.
(Section
S6. 1)
The lic'ensee
evaluated
hardware
and mechanical
problems associated
with
security equipment
and the problems were effectively controlled and managed.
(Section S6.2)
Licensee-conducted
audits were thorough.
complete.
and effective in terms of
uncovering weaknesses
in the security system,
procedures,
and practices.
The
last audit report concluded that the security program was effective and
recommended
appropriate action to improve the effectiveness
of the security
program.
The licensee
had acted appropriately in response
to recommendations
made in the audit report.
(Section S7.1)
High pressure fire protection system flushing was completed according to the
work instructions.
The procedure
was actively utilized and the workers were
knowledgeable of the evolution.
Radio communications
were appropriately
formal and the workers were careful
when draining the system to minimize
overflow of the floor drains.
(Section
F2)
II
Summar
of Plant Status
Re ort Details
Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Unit 2 reduced
power to 83K on August 18,
1997,
due to a water leak in the 2A
high pressure
heater
room.
On August 23,
1997, the
U2C9 coastdown
began with
all rods out, recirculation flow at 100K.
and final feedwater reduction
implemented.
Unit 3 operated
at or near full power with the exception of routine testing
and scheduled
maintenance
During some of the inspections
discussed
in this report, the inspectors
reviewed applicable portions of'he Updated Final Safety Analysis Report
(UFSAR) that related to the areas
inspected.
No deficiencies
were identified
during the reviews.
01
Conduct of Operations
I. 0 er ations
01. 1
Su
ression
Chamber
Standb
Gas
Inboard Isolation Valve
~571707
The inspectors
reviewed licensee actions taken after the suppression
chamber standby
gas inboard isolation valve (3-FCV-64-34) failed to
close during
a surveillance test
on July 26,
1997.
b.
Observations
and Findin s
On July 26.
1997, during surveillance testing.
the licensee identified
that valve 3-FCV-64-34 failed to close when demanded.
This valve is
a
Group 6 containment isolation valve located in piping connected to the
suppression
chamber.
The valve closed during
a subsequent
attempt
and
was cycled several
additional times.
The licensee
began cycling the
valve once every. four hours to ensure continued operability.
The
licensee
submitted
a work request to repair the valve and subsequently
issued
a Technical Operability Evaluation
(TOE) on July 29,
1997.
The
TOE analysis
determined that continued operation,
every four hours. of
the valve was
no longer necessary
and that
CR120 relay 86-64-34 would be
replaced.
In the past,
the
CR120 relays
had been observed to stick in
the energized position if they were energized for a long period of time.
The licensee
concluded that the primary containment isolation system
(PCIS) closure function of the 3-FCV-64-34 valve would not be inhibited
by the problem with the 86-64-34 relay.
TOE 3-97-064-1159,
Revision
0
concluded that valve 3-FCV-64-34 would perform its safety function and
that the system
remained operable.
0
Cl
4l
J
On August 14,
1997 'he 3-FCV-64-34 valve failed to close again
when
tested.
The 86-64-34 relay was replaced
on August 19,
1997,
and post
maintenance testing
was completed satisfactorily.
On August 24.
1997,
the 3-FCV-64-34 valve failed to close during performance of surveillance
testing.
The valve handswitch
was cycled two more times before the
valve closed.
The licensee
determined that the
TOE still applied. there
was not
a PCIS operability concern,
and continued troubleshooting.
On
August 28.
1997, with a contingency work order
planned for immediate
replacement of the solenoid valve associated
with 3-FCV-64-34, another
attempt
was
made to close the 3-FCV-64-34 valve.
The valve took several
seconds to close following operator
action to turn the handswitch to the
close position.
The licensee
declared the valve inoperable
due to slow
closure time and subsequently
replaced the
ASCO solenoid valve which is
used to control the 3-FCV-64-34 valve.
(Section N1.5 of this report
describes
NRC inspection of the replacement activity.)
A failure of the
solenoid valve would affect the ability of the valve to close which is
the
PCIS required position.
After reviewing the sequence
of events
associated
with the valve
failure, the inspectors
questioned
licensee
management
regarding the
valve operability status
on August 24 when it failed to close after the
problem was believed to have been resolved.
Licensee
management
reviewed the event
and concluded that
TS requirements
for
an inoperable
containment isolation valve had not been
met.
The licensee
plans to
submit
a 10CFR50.73 report.
This issue is identified as Unresolved
Item (URI) 50-296/97-09-06,
Actions for Inoperable
Containment Isolation Valve, pending additional
review of details regarding the timeliness of the licensee's
actions.
The licensee is reviewing the cause of the solenoid valve failure.
Preliminary indications are that sticking at the core-plugnut interface
(CPI) may have contributed to the failure.
The licensee
disassembled
the solenoid valve and identified that
a varnish-like substance
existed
at the CPI.
The licensee
plans to remove two additional solenoid valves
used in similar applications in the plant, in addition to the failed
and have
an evaluation performed.
A similar problem
was previously identified in Inspection
Followup Item
( IFI) 260.296/95-
64-10,
Secondary
Containment Ventilation
Failures,
and updated in
NRC Inspection
Report 259,260,296/96-008.
IFI 260,296/95-64-10
remains
open.
c.
Conclusions
The inspectors
concluded that since the licensee
had initially
identified the
CR120 relay as the apparent
cause of the symptoms
and had
replaced the relay, the 3-FCV-64-34 valve should have been declared
when it subsequently
failed. Additional review of the
sequence of events is necessary
to determine if a regulatory violation
occurred.
0
0
01.2
Observation of Assistant Unit 0 erator
Rounds
a.
Sco
e
71707
The inspectors
observed
the Unit 3 Rounds Assistant Unit Operator
(AUO)
while he performed portions of Turbine Building Rounds.
b.
Observations
and Findin s
On August 30,
1997, the inspector
observed
the Unit 3 Rounds Assistant
Unit Operator
(AUO) while he performed portions of Turbine Building
Rounds.
The inspector
noted that, in light of recently identified
scaffold problems,
the
AUO was sensitive to scaffolding in the plant.
The inspector also noted that the
AUO initiated work requests
for
identified problems
and mairitained housekeeping.
07
Quality Assurance in Operations
07. 1
Plant
0 erations
Review Committee Meetin
a.
Ins ection Sco
e
71707
The inspectors
attended
four Plant Operations
Review Committee
(PORC)
meetings.
In addition to assessing
the quality of the reviews, the
inspectors verified that selected
requirements of Technical Specification 6.5. 1 and Site Standard
Practice
SSP-12. 10, Plant
Operations
Review Committee,
were met.
b.
Observations
and Findin s
Each of the meetings
was chai red by the Acting Operations
Manager.
It
was clear that he was in charge of the meetings.
An appropriate
level
of formality was maintained during the meetings.
The committee actively
questioned
individuals presenting
material for review.
The
composition
met the requi rements of TS 6.5. 1.2.a.
Specific items noted:
~
During review of a safety evaluation for use of a temporary
power
supply for the neutron monitoring system during
a battery
replacement,
the
PORC asked detailed questions
regarding the
qualification of the temporary supply.
The evaluation
was not
approved since the presenter
could not answer
several of the
PORC's questions.
e
The
PORC did not approve
a request to delete
Updated Final Safety
Analysis Report
(UFSAR) section
13. 10.2.8 which described
system operational testing.
The
PORC indicated that the
UFSAR description should
be revised to reflect the proper testing
criteria if the current description is inaccurate,
but the section
should not be deleted.
0
08
08.1
08.2
~
The
PORC did not approve
a proposed
design
change associated
with
the main steam relief valve automatic actuation logic since there
were too many items remaining
as
"open" in the proposed
modification.
o
The
PORC chairman
ensured that only authorized
personnel
were
present
when an issue involving safeguards
information was
discussed.
~
The
PORC reviewed
"A" level Problem Evaluation Report 960204.
UFSAR Issues.
The
PORC requested
that the presenters
return with
stronger explanations of the underlying issues
and corrective
actions.
Conclusions
The inspectors
concluded that the
PORC conducted
adequate
reviews of the
presented
material.
PORC members
asked probing questions
regarding the
overall safety of the activity and focused
on whether the change
represented
an unreviewed safety question or was prohibited by Technical
Specifications.
Miscellaneous
Operations
Issues
(92901)
Closed
Licensee
Event
Re ort
Unit 3 Scram
Following Loss Of Reactor
Feedpump
3C.
This event was discussed
in
Inspection
Report 96-04.
The cause of the scram
was due to low reactor
water level caused
by loss of the
3C reactor
feedpump resulting from
improperly aligned oil valves.
A personnel
error occurred while
aligning the feedpump oil tank to the purification system.
The oil tank
was drained causing the feedpump to trip.
The plant design is such that
a loss of a single reactor
feedpump
can
be compensated
for by increased
output of the other
two reactor
feedpumps
in combination with an
automatic
run back of the reactor recirculation
system
pumps.
In this
case reverse flow occurred through the
3C reactor
feedpump line due to
a damaged
discharge
The damage to the check valve was also
discussed
in Inspection Report 96-04 with long term resolution of this
problem tracked
by Inspection
Followup Item 296/96-04-04 that remains
open.
Personnel
corrective action was taken with the operator
responsible for the valve misalignment.
The inspector
reviewed the
Inspection
Report
and
LER.
All issues
had been previously discussed
or
tracked.
This
LER is closed.
Closed
Violation 296/96-12-01,
Failure to Ensure Proper Position of
EDG Aux Board
Room Exhaust
Fans.
This violation addressed
instances
in
which
NRC inspectors
found the switches for the Unit 3
EDG auxiliary
board
room exhaust
fans not positioned in accordance
with the system
Operating Instruction.
The inspector verified that procedures
0-OI-30F
and 0-GOI-300-1 have been revised to clearly indicate when the fans can
be turned off.
OI-30F states that the fans shall
be operating
when
ambient outside temperature
is 40 degrees
F or above.
Verification of
the Unit 3 exhaust
fans
has also been
added to procedure
O-GOI-300-1.
. Il
4l
0
08.3
The inspectors
have noted
on tours that the fan control switches
have
been'aintained
in the correct position and that the fans were running.
Currently, caution tags are installed
on the Unit 3 fan switches to
ensure that the fans remain energized.
The violation is closed.
CLOSED
Violation 296/96-13-03,
Uncontrolled Locked High Radiation Area
(LHRA).
This violation occurred
on December'7,
1996, while the Unit 3
3Al/3A2 Heater
Room, which is normally posted
as
a
LHRA, was de-posted
to support maintenance activities when extraction steam
was isolated.
The area 'became
a High Radiation Area again
when operations
personnel
inadvertently introduced
a radiation source to the room by manipulating
an extraction
steam valve.
The inspector verified that the latest revision of Operating Instruction
3-0I-6. Feedwater
Heating
and Misc Drains System,
included
a statement
to notify Radcon personnel
prior to making changes
in Feedwater
Heating
System alignments
which could cause
a rise in area radiation levels.
The procedure further required confirmation, to be obtained prior to
performing the alignment, that Radcon
has
implemented appropriate
radiological controls/barriers
for the expected
Heating System
alignment.
In addition, the inspector noted that the licensee
identified 22 Operating Instructions which were also revised to include
the precaution.
The inspector
sampled
seven of the identified
procedures
and verified that the procedures
included the precaution in
the latest revision.
The inspector also verified that Site Standard
Practice
SSP-12.1,
Conduct of Operations
was revised to ensure that
plant radiological personnel
are informed prior to evolutions
or
activities which .have the potential to significantly change radiological
conditions.
The inspector
noted that during the recent Unit 2 feedwater
temperature
reduction,
the licensee
used caution orders to ensure that
Radcon
personnel
were contacted prior to operating heater extraction
steam
isolation valves
so that Radcon could evaluate radiological conditions.
The inspector concluded that the licensee's
actions were adequate.
This
violation is closed.
II. Maintenance
Ml.1
Conduct of Maintenance
Scaffolds
and
Tem orar
Platforms
Ins ection Sco
e
62707
On August 26,
1997, the inspector
examined
20 scaffolds/platforms
located in the Unit 2 reactor bui.lding.
The scaffolds/platforms
were
reviewed with regard to the requirements
in Technical Instruction
O-TI-264, Scaffolds
and Temporary Platforms.
The inspector
focused
on
.verification of proper clearance
between the scaffolds
and safety
related equipment.
~
~
lj
0
b.
Observations
and Findin s
During the course of the revi ew, the inspector identi fied several
specific examples
in which the procedural
guidance
was not being
correctly followed.
Additionally, the inspector noted at least
one
issue in which the procedural
expectations
appeared to be not realistic
and were not being applied.
Several
problems with the procedure
were
also identified.
General
precaution 4.4 and step 7.11.4 of 0-TI-264 require that
areas
around scaffolds which can be used for handholds
or
footholds shall
be posted with caution signs and/or tape to avoid
use
as handholds
or footholds.
The erecting
foreman is supposed to
review and verify this when he signs the permit.
The inspector
did not observe
any such marking of potential
handholds or
footholds.
In the case of scaffold 2575-02,
a conduit going into
junction box 73-0111
was bent slightly and appeared
to have been
stepped
on.
These procedural
requi rements apparently
are related
to commitments
made to the
NRC as part of Licensee
Event Report
260/89-006.
In that event,
personnel
climbed on a reactor
protection system breaker
cabinet to access
a scaffold.
Appendix
H (Scaffold/Temporary Platform Erection Checklist) of 0-
TI-264 references
steps 2.6.7
and 2.7.6 of Appendix L (Seismic
Qualifications of Scaffolding and Platforms in Class I
Structures).
There is currently no step 2.6.7 in Appendix L and
step 2.7.6 does not address
clearance
issues.
It appeared that
the correct reference
would be step 2.7.7.
Numerous
examples
were noted in which the Appendix
H checklist
indicated that the clearance
requirements
of Appendix L were met
but
a Site Engineering evaluation
(Appendix N) was completed to
address
deviations
from the clearance criteria.
The inspector
noted several
indications that the Appendix
N checklists
were not
being completed in a diligent manner.
Section 2.7.7 of the TI states
that if the clearance
requirements
can not physically be achieved,
Site Engineering evaluation
and
approval shall
be obtained
and documented
on Appendix
N prior to
erecting the portion of the scaffold in which the clearance
cannot
be achieved.
The inspector noted that actual practice is to
complete the site engineering evaluation in parallel with or after
the scaffold is built.
While no scaffolds were found with expired tags,
the inspector
noted that the expiration dates
were often set far past expected
end of work activities.
For example.
most of the refueling outage
scaffolds
had expiration dates of December
31,
1997. Apparently,
the scaffolds are being tagged this way due to a perception that
there
may be delays in removing all the scaffolds following the
outage.
45
The inspector
noted that in several
cases.
scaf'folds were built
with unnecessarily
small clear ances to safety related
equipment.
In most cases.
the deviations
were addressed
in site engineering
evaluations
as required.
However. larger clearances
could have
been physically achieved
and there did not appear to be
a need for
such close proximity to safety systems
(examples
included plating
located less than one inch from core spray
and
HPCI piping and
scaffolding very close to recirculation seal
pressure
sensing
lines).
The inspector
found
a scaffold board wired across
the stairwell in
the northwest corner
room.
While the board did not contain
a
formal scaffold permit,
an August 22 note was attached
indicating
that Operations
and Fire Protection personnel
had approved its
placement for use
on Sunday.
The board
had not been
removed after
Inservice Inspection activities were completed.
The inspector
immediately reported the issue to the Unit 2 control
room and the
board was
removed.
The inspector also discussed
Assistant Unit
Operator sensitivity to such issues with the Operations
manager.
Scaffold 2322 did not have the minimum clearance
stated in the
Appendix
N evaluation.
The inspector noted that
some scaffolding
tubing was very close to the torus
on one end with the other end
contacting
a concrete wall.
The engineering evaluation stated
that members pointed at the torus should have at least
4 inches of
clearance
from the torus.
This issue
was immediately reported to
the Unit 2 supervisor
and the scaffold was
removed later that
evening.
Problem Evaluation Report
(PER) 971339 was initiated.
The scaffold had been erected
in February
1997 for work completed
some time ago.
Additionally, the Appendix
M checklist was not
filled out for this scaffold.
Scaffold 2720 did not have
a field engineer
review documented
on
the 'tag.
Step 7. 11.8 of the TI appeared
to require this. Scaffold
2733 had no expiration date
on the tag.
Scaffold 2575 was located very close to residual
heat
removal
piping and instrument tubing associated
with HPCI and
recirculation
pumps.
A ladder for egress
was located'very close
to 2-LPNL-925-00078.
The site engineering evaluation did not
address all the clearance
deviations noted.
The inspector
noted
that conduit going to junction box 73-0111 appeared
to have
been
bent
as
a result of being stepped
on.
The conduit was located in
the path between the ladder to the scaffold.
Scaffold 2657 had three spray cans sitting on it that could have
fallen off. Additionally, the site engineering evaluation stated
that
a 1/2 inch minimum clearance
should be maintained.
'However,
some parts of the scaffold were closer than that to plant
equipment.
0
0
o
The inspector did not identify any of the scaffolds located
such
that it would adversely affect the operation of valves or
electrical
equipment.
However, in several
cases,
the
2 feet
minimum clearance
(stated in the TI) from a valve handwheel
was
not met and Operations
concurrence of the deviation was not
documented.
The inspector noted that the scaffold inspections
were consistently
completed
and documented
as required
by the TI.
On the evening of August 27, the Unit 2 support
AUO identified that
scaffolding had been erected (earlier that day) such that it was
blocking air flow between the room cooler and the 2A residual
heat
removal
pump.
The scaffolding boards
were removed
and
PER 971350 was
initiated.
The deficiencies
noted
above
appear
related to two causes.
There are
weaknesses
in portions of the procedural
guidance for scaffolding
erection,
and supervisory
personnel
are not ensuring that procedural
requirements
are satisfactorily met.
Violation 296/96-04-07,
Failure to Follow Procedural
Requirements
for
the Installation of Scaffolding,
was issued in May 1996.
The violation
had been
caused
by scaffolding constructed
too close to the switch for
an emergency diesel
generator field flash breaker.
This was the second
time that
a field flash breaker
had been inadvertently operated
during
egress
from a scaffold.
Corrective actions to the first instance
included requi ring verification and documentation that the three foot
clearance
requi rement
was met in the 0-TI-248 checklist
(Appendix M).
Corrective actions for the second incident included counseling of
scaffolding craft personnel
on the clearance
requi rements.
The
inspection
conducted this period indicated that the Appendix
M checklist
is not being rigorously completed.
Several of the above noted problems
involve noncompliance with the Appendix
M checklist.
The number of 'deficiencies indicate that involved maintenance
supervisors
are not enforcing high standards
of performance.
There have
been other
incidents within the last year at Browns Ferry involving
problems with oversight
and accountability
on the part of maintenance
supervision.
In May 1997, the
NRC identified problems with
implementation of Foreign Material Exclusion procedures.
In August 1996,
NRC inspectors identified poor oversight of painting activities
on the
Unit 3 emergency diesel
generators.
The licensee
has identified
examples of similar issues.
The deficiencies identified above are
a violation of TS 6.8. l.l.a, in
that procedures
for performing maintenance
that can affect safety
related
equipment
were not implemented correctly.
This issue is
identified as Violation 260/97-09-02,
Scaffolding Controls Not Properly
Implemented.
0
0
0
Conclusions
The inspectors identified that the licensee
was not properly
implementing procedural
controls over scaffolding.
In some cases',
scaffolds
near
safety related equipment
were not constructed
in
accordance
with limitations in the procedure
or in the required
engineering evaluation.
The scaffolding assembly checklist was not
being properly completed.
Some procedural
requi rements,
which would be
difficult to complete,
were not being implemented.
No safety systems
were rendered
by the noted deficiencies.
The inspectors
concluded that the number
and nature of the deficiencies indicate that
supervisory personnel
are not enforcing standards
and failed to ensure
that procedural
requirements
are satisfactorily met.
Functional Testin
of Snubbers
Ins ection Sco
e
62707
61726
The inspectors
noted that the licensee
was performing functional testing
of safety system snubbers
as
a pre-outage activity. The inspectors
reviewed the applicable regulatory requirements,
procedures.
and work
instructions.
Observations
and Findin s
On September
9,
1997, the inspectors
noted that the licensee
had
removed
a mechanical
(2-SNUB-063-5001)
associated
with the Unit 2
(SLC) system from service to perform functional
testing.
The inspector
was aware that the Unit 2 SLC system
had been
removed
from service
on September
7 for planned maintenance
and returned
to service
on September
8.
The detailed work schedule
for the
inoperability period (referred to as
a fragnet by the licensee)
did not
include th'e snubber testing.
During the snubber work, the licensee
entered
a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limiting condition for operation
and referenced
TS 3.6.H.l.
This practice
had been
implemented for snubber testing prior
to recent refueling outages
at Browns Ferry.
associated
with
the Unit 2 core. spray
and residual
heat
removal
systems
had also been
tested prior to this outage.
The inspector
reviewed Work Order
(WO) 96-015749 which contained the
work instructions
for the testing.
The inspector noted that the
contained
statements
which indicated that the work was to be performed
as
a shutdown activity.
Technical Specification (TS) 4.6.H, which addresses
functional testing
of snubbers,
states that "During each refueling outage,
a representative
-sample of 10 percent of the total of each type of safety-related
in use in the plant shall
be functionally tested either in
place or in a bench test."
Additionally, the TS bases
states that
operability tests shall
be performed during refueling outages,
at approximately
18-month intervals.
The inspector concluded that the
current
Browns Ferry TS directed that functional testing of snubbers
was
4~
0
Hl.3
10
to be performed while the unit was shutdown.
The inspector
immediately
informed maintenance
management.
Mechanical
snubber testing is performed in accordance
with Procedure
2-
SI-4.6.H-2A, Functional testing of Mechanical
(Revision 4).
The
inspector
reviewed the procedure.
Sections
1.2.2.2
and 1.3. 1 contain
statements
which indicate that the testing is to be performed in a
refueling outage.
However, sections
1.3.2 and 3.2.8 indicate that the
procedure
can be performed in other than outage conditions for snubbers
outside the drywell.
The inspector
concluded that the procedure did not
exclude functional testing at times other than
an outage.
Later on September
9, the licensee
informed the inspectors that
a review
had been completed
and it was determined that
TS requirements
had not
been
met regarding the snubber testing.
The licensee's
review
identified 1980 guidance
from the
NRC indicating that the TS for
. functional testing of snubbers
should indicate that the testing is to be
performed while shutdown.
The Browns Ferry TS for snubber testing
was
revised in 1982.
The licensee
indicated that
a
10 CFR 50.73 report
would be made addressing
the issues.
At the September
10,
1997,
Management
Review Committee meeting,
Problem
Evaluation Report
(PER) 971406 was reviewed.
The
PER addressed
the
snubber testing issue
and was assigned to Operations for resolution.
Snubber functional testing
was stopped.
Discussions with plant
management
indicated that the licensee
was reviewing other maintenance
activities to ensure that no similar TS noncompliances
existed.
Plant
management
also indicated to the inspector that the
PER resolution would
address
the issue of the
WO being worked at power although it was coded
as
a shutdown activity.
Functional testing of snubbers
at other than refueling outage conditions
is
a violation of TS 4.6.H.
This is identified as Violation 260/97-09-
01, Functional Testing of Snubbers
While Not in Refueling Outage
Conditions.
Conclusions
The current
Browns Ferry TS indicates that .functional testing of
is to be performed in a shutdown condition.
The licensee
was
conducting the testing with the unit at power and on snubbers
for
systems
required to be operable.
Procedural
controls for the testing
did not enforce the TS requirements.
Hain Steam Line Tunnel
Tem erature
Switch Test Heatin
Coil Ad ustment
Sco
e
62707
The inspector
observed
maintenance activities to adjust the test 'heating
coil associated
with main steam line tunnel temperature
switch (TS)
3-TS-1-29C.
0
b.
Observations
and Findin s
11
During testing
on August 22,
1997,
a test deficiency was identified on
3-TS-1-29C when the temperature
switch failed to actuate
during the
performance of surveillance instruction 3-SI-4..2.A-f(A2), Hain Steam
Line Tunnel
High Temperature
Functional Test.
Channel
A2.
Temperature
switch 3-TS-1-29C was declared
The licensee
determined that
the test heating coil. used to actuate the temperature
switch.
needed to
be adjusted to move the coil closer to the switch.
On August 26,
1997.
~ the inspector
observed troubleshooting activities to adjust the test
heating coi 1 on temperature
switch 3-TS-1-29C.
The inspector attended
the prejob brief for the coil adjustment
conducted in the control
room.
Since this evolution was considered
high
risk, the group discussed
that no other testing would be performed which
could cause
a half scram while the activities were being accomplished.
The group discussed
that there would be
a possibility of a half scram if
the temperature
switch is loose when the coil adjustment
was
made
even
though there
was no indication that the switch was loose.
The team
considered
numerous
aspects of the job and the potential for problems to
the extent that responders
would be dressed
and available to immediately
attend to an injury in the high radiation area.
The inspector
considered that the licensee
was well prepared
for this task.
The inspector
observed the coil adjustment
from the video camera set
up
in the main steam tunnel.
The Instrument Haintenance technician
performed the adjustment
as planned
and swiftly with consideration
for
the high radiation area that was entered.
Following completion of the coil adjustment,
the licensee
performed
surveillance instruction 3-SI-4.2.A-8FT(A2), Hain Steam Line Tunnel
High
Temperature
Functional Test,
Channel
A2, to meet the surveillance test
interval requirement
and to post maintenance test the temperature
switch.
The temperature
switch actuated
when the test pushbutton
was
depressed
the fourth time.
The procedure
allows the test pushbutton to
be depressed
additional times to ensure that the temperature
switch
temperature
is raised
above the setpoint.
The inspector
noted that the
procedure
performance
appeared to be slightly cumbersome.
The Unit
Operator identified some potential
enhancements
which he indicated would
be submitted
on
a procedure validation review checklist.
The
temperature
switch was declared
on August 26,
1997.
C3
EECW Pum
Im eller Ad ustment
Sco
e
62707
The inspector
observed
maintenance activities to reset the
pump impeller
clearance
on the
C3 Emergency
Equipment Cooling Mater
(EECW)
pump.
0
0
II
M8.2
M8.3
13
The emergency diesel
generator auto-started
as designed.
This
LER is
closed.
Closed
'Licensee
Event
Re ort
Main Steam Isolation
Valves
Leak Rate
Exceeded
the Local
Leak Rate Test Acceptance Criteria
Due to Internal
Component
Wear.
This
LER was submitted
as
a voluntary
LER for information only.
On March 23 and 24,
1996, during
a Unit
refueling outage the "A" and
"C" inboard main steam isolation valves
(MSIVs) had
a leakage that exceeded
the local leak rate acceptance
criteria of 11.5 standard
cubic feet per
hour
(SCFH).
The as-found
leakage
was 18.7
SCFH and 32.0
SCFH respectively.
The cause of the
leakage
was determined to be misalignment of the valve mating seats
caused
by internal
component
wear.
The "A" MSIV was changed to a long-
nosed
poppet to provide
a guidance
mechanism to improve the alignment
on
the mating seats.
The valve was retested with a 6. 1 SCFH as-left
leakage.
Only one long-nosed
poppet
was available
and the "C" MSIV was
repaired
by lapping and cleaning.
The "C" MSIV was retested with a 1.51
SCFH as-lef't leakage.
The inspector
reviewed the
LER and Technical
Specification
(TS) surveillance
requirement 4.7.A.2.i concerning
leakage.
The TS only requi res that the valves
be tested
once each
refueling outage.
If leakage
exceeds
11.5 SCFH, the valves
must be
repaired
and retested until the leakage
meets the acceptance criteria.
The inspector concluded that the licensee's
actions were in compliance
with the TS.
This issue
has
been
a generic problem at Boiling Water
Reactors.
The licensee
referenced
previous
LERs concerning this problem
in this
LER.
This
LER is closed.
Closed
Licensee
Event
Re ort
All Eight Plant
Unexpectedly Auto-Started
From A Spurious
High Drywell Pressure
Signal.
This event
was discussed
in Inspection
Report 96-04.
This event occurred during installation of wiring for the
digital feedwater modification.
A fault was introduced into the
Emergency
Core Cooling System
(ECCS) logic while preparing
wires for
termination in panel
2-9-81.
The fault caused
a spurious, high drywell
pressure
signal in the logic, which in combination with the existing low
reactor
pressure
condition in Unit 2 resulted in the Engineered
Safety
Feature actuation.
The licensee
determined the root cause
was
inadequate
work planning.
The work plan was originally approved to be
worked with panel
2-9-81 deenergized.
The work plan was subsequently
revised to work with the panel
energized.
The inspector
reviewed the licensee's
incident investigation report for
PER 960378.
The licensee
determined that as the outage schedule
firmed
up the panel would remained energized
during the work.
This would allow
the panel
work to proceed while maintaining
ECCS equipment
and their
initiation logic available for requi red testing.
Revisions
were made
to the work plan to delete the requirement for a clearance/isolation
and
a note was
added to perform the work "hot."
The work plan was never
sent
back to planning for review.
At the time of the event the
electrician
was working alone inside the energized cabinet.
As part of
the corrective action the licensee
was to change the administrative
process for reviewing and rescoping of workplans
when revisions are
il~
Ik
Observations
and Findin s
12
On September
1,
1997, the licensee identified that the
C3
EECW pump flow
data taken during quarterly surveillance testing
was below the minimum
flow limit and the
pump was declared
The licensee
prepared
a work order
(WO) 97-008664-000 to adjust the impeller clearance.
On
September
3,
1997, the inspector
observed the maintenance
crew pre-job
briefing and associated
work.
The brief was well conducted with focus
on right train and component:
personnel
safety issues
were addressed;
general
housekeeping
and foreign material exclusion
(FME) was discussed;
and specifics of the step text work order were reviewed.
The mechanical
maintenance
workers conducted
the job using portions of
MCI-0-023-PMP002,
Emergency
Equipment Cooling Water
and Residual
Heat
Removal Service Water
Pump (Byron Jackson
Type KX) Disassembly,
Inspection.
Rework and Reassembly.
The workers were knowledgeable of
the task
and the equipment.
Re lacement of 3-FCV-64-34 Solenoid Valve
Sco
e
62707
The inspector
observed
the replacement of the solenoid valve in the
control,circuit for the 3-FCV-64-34 valve.
The licensee
determined that
the failure of the 3-FCV-64-34 valve to close
upon
demand
was due to the
solenoid valve in the control circuit not operating properly.
Observations
and Findin s
On August 28,
1997, the inspector
observed the replacement of the
ASCO
solenoid valve used to control the 3-FCV-64-34 valve.
The repair
evolution was well planned
as
a contingency if testing concluded that
the
ASCO solenoid valve was the cause of the 3-FCV-64-34 valve fai lures.
The inspector did not identify problems with the maintenance
work.
Conclusion
The inspector
concluded that the maintenance
work observed
during the
inspection period was generally well planned
and worked.
The inspector
considered that ALARA planning of contingencies
was good with regard to
the high radiation evolution observed.
A strong prejob brief was
evident in preparation for C3 emergency
equipment cooling water
pump
work.
Miscellaneous
Maintenance
Issues
(62707,
92902)
Closed
Licensee
Event
Re ort
An Emergency Diesel
Generator Auto-Started
Due To Undervoltage Condition As A Result of
Personnel
Error.
This item was previously discussed
in Inspection
Report 96-04.
The inspector
reviewed the
LER and the description of the
event was the same
as in the Inspection Report.
This event
was caused
by a personnel
error.
Personnel
involved in the test were disciplined.
ll
0
0
14
made.
Upon further review, the licensee
determined that the existing
procedural
requi rements
were adequate
and did not require revision.
Site Standard
Practice.
SSP 6.2
~ Maintenance
Management
System,
requires
under step 3.5.2 that revisions to workplans
be sent to planning for
review.
This was not followed.
Since the procedure for contro1 of
workplans
was not followed this was
a violation of 10 CFR 50 Appendix B,
Criterion
V for failure to follow procedure.
This non-repetitive
licensee identified and corrected violation is being treated
as
a Non-
Cited Violation (NCV), consistent with Section VII.B.1 of the
NRC
Enforcement
Po1ic
.
(NCV 50-260,296/97-09-04,
Failure to Follow
Procedure for Workplan Revision).
The inspector concluded that the incident investigation report was
thorough
and comprehensive.
This
LER is closed.
H8.4
0 en
Ins ection Followu
Item
IFI
296/96-08-03
Unit 3 Main Steam
Isolation Valve (HSIV) Circuitry Failures.
Inspection
Reports
96-05 and
96-08 describe
NRC review of several
MSIV limit switch fai lures
and the
licensee's
corrective actions which included installation of temporary
modifications.
The inspector
reviewed Revision
2 of Problem Evaluation
Report
(PER) 96-0083.
During the most recent Unit 3 refueling outage,
the problem was traced to damaged insulation
on conductors in Conax
conduit assemblies
and the situation was corrected.
It was concluded
that the Kapton insulation
on the conductors
was
damaged
because
heat
shrink polyolefin tubing had not been installed
on the inboard
conductors
during installation.
The
PER noted that
NRC Information Notice (IN) 88-89 addressed
this concern.
The inspector
reviewed the
IN
and noted that it specifically addressed
the use of the polyolefin
.tubing to mechanically protect Kapton insulation.
The licensee
attributed the fai lure to install the heat shrink to a lack of specific
guidance in work and vendor documents
and workers not understanding
some
of the instructions.
Similar maintenance activities have
been completed
in the past properly.
The licensee
implemented corrective actions to
ensure workers will understand
the importance of installing the heat
shrink on the inboard conductors.
The licensee
determined that
a total
of 69 similar seals exist on Unit 3 and has selected
10 percent
(7) of
these seals to inspect during the upcoming outage to determine if heat
shrink was applied to the inboard conductors.
No similar failures have
occurred
on Unit 2.
Pending results of those inspections,
the IFI
remains
open.
,
H8.5
Closed
Violation 296/96-04-07,
Failure to Follow Procedural
Requirements
for Installation of Scaffolding.
Section Hl. 1 describes
NRC inspection of scaffolds in the Unit 2 reactor building.
Numerous
deficiencies
were identified and cited as Violation 260/97-09-02.
Additional reviews of scaffolding controls will be performed
as followup
to Violation 260/97-09-02.
Violation 296/96-04-07 is closed.
0
0
Cl
15
El
Conduct of Engineering
III. En ineerin
El. 1
C.
E2
E2.1
RHRSW/EECW
Pum
Flow Test Data
Used for In-Service Testin
Trendin
Sco
e
37551
61726
The inspector
questioned
flow data
used to support In-Service Test
trending
on the residual
heat
removal service water and emergency
equipment cooling water
(EECW) pumps.
Observations
and Findin s
The 1-icensee
performs
a quarterly flow test
by adjusting discharge
pressure to 135 psig and reading
mV from an input to a flow modifier.
The
mV reading is then
used in a calculation to determine the flow in
gpm.
The
C3
EECW pump trend curve shows what appear to be comparable
test results for flow over several
quarterly tests until the
September
1,
1997, test which shows that the
pump is in the inoperable
range
due to low flow:
A recent decrease
in flow during testing of the
83
EECW pump again represents
potential
inaccuracies
in pump testing
methodology.
The
B3
EECW pump was replaced with a new stainless
steel
impeller
and tested with flow very near the original baseline.
Twelve
days later, the
pump flow tested
approximately
200 gpm lower and put the
pump in the alert range which requi red increased
frequency testing.
Based
upon review of the examples identified and discussion with the
licensee,
the inspectors
determined that
pump testing allowed
inaccuracies
in the flow determination.
The licensee indicated that
they would pursue
more repetitive methods of obtaining
mV data for the
flow calculation.
Conclusions
Based
upon review, of the examples identified and after discussion with
the licensee,
the inspectors
concluded that the
pump testing
was limited
in its repeatabi lity.
The inspectors will review the licensee's
actions
under Inspection Followup Item (IFI) 50-260,296/97-09-07,
RHRSW/EECW
Pump Flow Testing Issues.
Engineering Support of. Facilities and Equipment
Pressurization
of Shutdown Coolin
Suction
Pi in
Sco
e
37551
71707
The inspectors
reviewed
and monitored the licensee's
actions
regarding
pressurization
of portions of the Unit 2 shutdown cooling suction
,piping.
Apparently,
a very small
amount of reactor coolant leakage
past
the shutdown cooling isolation valves
(2-74-47 and 48) was causing the
suction piping to pressurize to above
100 psig.
0
II
16
b.
Observations
and Findin s
In August, the licensee
became
aware that
a slow pressurization of
portions of the shutdown cooling
(SDC) suction piping outside the
containment isolation valves
was occurring.
Annunciator 2-XA-55-3E,
window 32,"RHR SYS I/II DISCH OR SD CLG HDR PRESS
HIGH" began to alarm
once every several
hours.
The annunciator
was alarming due to pressure
switch PS-74-93 sensing
100
sig.
This pressure
switch senses
shutdown cooling piping pressure
etween the outboard
SDC suction containment isolation valve and
suction isolation valves located near the
RHR pumps.
The control
room
operators
complied with the alarm response
procedure which included
actions
per section 8.30 of Operating Instruction OI-74 alarm response
procedure.
These actions
included venting/draining the line from inside
the drywell access
area to reduce the pressure.
There is
a relief valve
(74-659) located
on the line which is set to relieve pressure
at
150
psig.
Due to the potential safety significance of the condition. the
inspectors
monitored the licensee's
actions closely.
The licensee classified the issue
as
an .operator work around
and
repetitive alarm issue.
Significant engineering
and management
attention
was applied to investigation of the condition.
The inspectors
met with licensee
management
and engineers
several
times during the
report period.
Since the licensee's
leakage estimate via calculation
appears
to be well within local leakrate testing limits. the inspectors
focused
on verification that the licensee
was adequately
pursuing the
problems while plant conditions were such that the leak was present.
Completed
and planned actions discussed
included:
After assuring that procedures
would cause the
SDC suction. piping
to be refilled prior to it being placed in service,
the licensee
revi'sed section 8.30 of OI-74 such that
a larger volume of the
suction line was drained in response to the annunciator.
The
drain point was
moved to a fuel pool cooling system connection in
the corner
room above the
RHR pumps.
This increased
the interval
between draining evolutions
from several
hours to several
days.
The inspectors
walked down the revised procedure
flowpath and
identified no significant problems.
The licensee
confirmed that the Unit 2 SDC suction relief valve
(74-659)
had
a
150 psig setpoint
and was tested satisfactorily in
1993.
The licensee
also intends to test'the relief valve during
the upcoming refueling outage.
Controlled drawings indicate that
the
SDC piping is rated for 150 psig outside the containment
isolation valves.
Engineers
obtained temperature
measurements
on the piping and
conducted
other diagnostic reviews.
Previous local leakrate
testing of the 74-47 valve (outboard isolation) indicated that the
leakage
was
0 standard
cubic feet per hour.
The acceptable
0
Ih
17
leakrate of the 74-47 by Appendix J requirements
would be
a small
fraction of a gallon per minute of water (20 standard
cubic feet
per hour air).
The 74-47 also fulfills a pressure
isolation
function.
Acceptable leakrate for that function (1/2 capacity of
relief valve) would be 10.5 gpm,
The licensee's
estimate of the
resent leakrate
was done by calculation
and indicated that it is
ess
than these limits.
The licensee ini'tiated
a Work Order to apply additional torque to
the handwheel of valve 74-47 to seat the valve better.
The torque
will be limited to ensure that the motor operator will still
operate that valve if needed.
The additional torquing had not
been
implemented at the close of the inspection period since the
revised draining method significantly increased
the time intervals
between
increased
pressure
indications.
During the outage.
the
torque switch setting of the 74-47 valve is scheduled to be
increased
as
a Generic Letter 89-10 enhancement.
The licensee'iscussed
the issue with similar facilities in order
to determine available
means of resolution.
Technical
Support developed
a resolution plan which includes
installation of pressure
recording instrumentation
and additional
temperature
measurements.
Refueling outage contingencies
being
considered
include
a modification to install
a controlled leakoff
line which could be used to port leakage
back to the torus.
c.
Conclusions
The inspectors
concluded that the licensee
was pursuing the problem in a
reasonable
manner
and the present conditions
do not represent
an
immediate safety concern.
Licensee
management
has indicated that the
intent is to effectively address
the issue
such that it will not exist
once the unit is returned to power after the refueling outage.
E8
Hiscellaneous
Engineering
Issues
(92903)
E8. 1
Closed
LER 296/96-004-01
and
Loss of the Emergency
Core Cooling Systems
(ECCS)
Division I and Division II Instrumentation
Renders
ECCS Equipment
These four LERs addressed
fai lures of the
ECCS inverters
which occurred in 1996 due to failures of silicone rectifiers
and
a
shorted
commutation capac'itor.
Inspection
Followup Item (IFI) 296/96-
08-02,
ECCS Inverter Failures,
addressed
these
problems.
Detailed
inspector
review and closeout of the IFI is addressed
in Section
E8.1 of
Inspection Report 97-07.
The LERs are closed.
E8.2
Closed
Licensee
Event
Re ort
Unit 3 Scram
On Low
Reactor
Water Level
Due To Failure Of The Steam
Packing Exhauster
Bypass
Flow Control Valve.
This event was discussed
in Inspection Report 96-
05.
The initiating event for this scram was the valve shaft failure of
the steam packing exhauster
bypass
flow control. valve, 3-FCV-2-190.
The
il
0
0
18
valve failed close causing
reduced
condensate
flow and tripping of
and condensate
booster
pumps.
This resulted in low reactor
water level
and
a reactor
The cause of the valve failure was due
to a material defect in a notched sensitive
area.
The licensee
replaced
the air operated
valve with a manual
valve following the event.
The
inspector
reviewed the Inspection Report
and
LER.
The inspector
looked
at the valve in the plant .and the valve had been replaced with a motor
operated
valve.
This
LER is closed.
Closed
Licensee
Event
Re orts
LERs
260/96-004-00
260/96-004-01
260/96-008-00
260/96-008-01
and 260/95-003-02
Main Steam Safety/Relief
Valves
Exceeded the Technical Specifications
Required Setpoint Limit as
a Result of Oisc/Seat
Bonding.
All of these
LERs concern the same issue
of setpoint tolerance drift.
Setpoint drift is
a generic concern in
Boiling Water Reactors
using Target
Rock Two-Stage Safety Relief Valves
(SRVs).
The cause
has
been attributed to corrosion bonding of the
pilot disc/seat
interface resulting in drifting of the
SRV setpoints.
The licensee
had previously implemented
a
BWR Owners Group
recommendation
for 3 of the
13 SRVs.
This recommendation
was to replace
the
SRV cartridges with cartridges that have
a platinum alloyed ste11ite
pilot disc.
However, test results
showed that the
SRVs with the
platinum alloyed stellite discs experienced
setpoint drift comparable to
the
Therefore the licensee is continuing with
long 'term corrective action to resolve this issue.
The licensee's
analysis for a limiting pressurization
concluded that even if
four SRVs completely failed to open
and the remainder operated
at ten
percent
above setpoint
a safety limit would not be exceeded.
Although
the conditions reported in the
LERs were conditions outside Technical
Specification they were bounded
by analysis.
concerning the same issue for Unit 3, the licensee
discussed
installing
pressure
switch actuation for the SRVs.
This modification has
successfully
been installed at another facility.
This modification is
planned for Unit 2 during the next refueling outage.
Additiona] actions
are being evaluated, in connection with the Boiling Water Reactors
Owners
Group.
remains
open to track final resolution of this
issue.
The previous
LERs are closed.
Closed
Unresolved
Item 260/97-07-04
Failure of Fuel
Pool Cooling
Pump.
This item addressed
the failure of the
2B fuel pool cooling pump
due to cavitation.
IR 97-07 describes
NRC review of the event.
The
inspector
reviewed
Problem Evaluation Report
(PER) 970946 which
addressed
this issue.
The inspector
concluded that the licensee's
corrective actions sufficiently addressed all the deficiencies
associated
with the incident.
The inspector questioned
the scheduled
completion dates
(August 1999) for Site Engineering to issue design
changes to prevent fuel pool cooling pump cavitation when the
demineralizer
bypass
valves
opened.
Subsequently,
the inspector
was
informed that management
intends to implement the design
changes
sometime after the Unit 2 refueling outage,
most likely during the late
fall or winter months.
As noted in IR 97-07, the system engineer
and
his supervisor failed to initiate a
PER on the cavitation problem when
19
are that
a
PER be initiated on such
an incident.
This non-repetitive,
licensee
identi fied and corrected violati on is being treated
as
a Non-
Cited Violation (NCV), consistent with Section VII.B.1 of the
NRC
Enforcement Polic
.
NCV 260/97-09-05,
Failure of Fuel
Pool Cooling
Pump.
The unresolved
item is closed.
E8.5
Closed
Unresolved
Item URI 50-260/97-08-02
Incorrect Oil Used in Two
EDGs.
The URI addressed
the failure of the licensee to promptly
identify that zinc additive oil had been put in the
2A EDG.
This
failure led to the incorrect oil also being put into the
2D
approximately four months later.
The immediate corrective actions to
drain and refill the oil in the
2A and
2D EDGs were discussed
in NRC IR
97-08.
After replacing the oil. the zinc content values for the two
EDGs were substantially
decreased;
however, the zinc content
was still
above the required level. Subsequent
actions
included partially draining
'nd refilling the
ZA and
2D EDGs in an attempt to decrease
the zinc
content further.
The licensee is actively pursuing the higher than
allowed zinc levels.
In March 1997,
problem evaluation report
(PER 970563)
was initiated to
address
a third party audit finding that "engineering
component testing
program weaknesses
could delay resolution of known equipment
problems
and result in equipment
problems not being identified prior to failure."
This included that "the lubricating oil analysis results
are not
reviewed or trended...as
an aid in predicting equipment performance."
Corrective actions for the identified problem are not complete.
On September
11,
1997. the licensee briefed the inspector
on current
plans to upgrade the program to track lube oil samples.
The Plan of the
Day meeting materials will have
a status of the oil samples
once per
week.
The licensee
has also
named
a point of contact
on site for the
lube oil analysis
program.
Currently, the licensee is using chemistry
instruction (CI) CI-130, Diesel
Fuel
and Lube Oil Monitoring Program, to
implement 'the lube oil program;
however, the licensee
plans to
incorporate
lube oil guidance into Technical Instruction (TI) TI-230.
Additional planned corrective actions include establishing criteria for
each
component which will be incorporated into the procedure
and
. personnel
training in performing evaluation of lube oil analysis
results.
The corrective actions are planned for implementation
by
December
19,
1997.
The inspector concluded that the planned corrective
actions are adequate.
This non-repetitive licensee identified and corrected violation is being
treated
as
a Non-Cited Violation (NCV), consistent with Section VII.B.1
of the
NRC Enforcement Polic
.
The fai lure of the licensee to identify
that zinc additive oil had been put in the
2A EDG which led to the
incorrect oil also being put into the
2D
EDG approximately four months
later is identified as Non-Cited Violation (NCV) 50-260/97-09-03,
Incorrect Oil Used in Two EDGs.
0
S3
S3.1
20
IV. Plant
Su
ort'ecurity
and Safeguards
Procedures
and Documentation
Securit
Pro
ram Plans
Ins ection Sco
e
81700
The inspector
reviewed appropriate
chapters of the licensee's
Physical
Security Plan
(PSP)
and Safeguards
Contingency
Plan
(SCP),
Revision 1,
dated
October
19,
1995; Revision 2, dated February
29,
1996: Revision 3,
dated
May 13,
1996.
The inspector
also reviewed Revision 21, dated
April 14,
1995,
and Revision 22. dated
December
28,
1995, of the
Security Personnel
Training and Qualification (T&Q) Plan
and security
procedures
as listed in paragraph
S3.1(b).
Observations
and Findin s
Review of the changes
submitted to the
NRC in Revision l. 2,
and 3, of
the .PSP
and Revisions
21 and 22 of the
T&Q Plan for approval verified
that the
and
T&Q changes
as submitted were in compliance with the
requi rements of 10 CFR 50.54(p).
The
PSP changes
were mostly
administrative in nature with the exception of Revision 3, of the
which deleted the security requi rements
during the security upgr ade
project.
The
PSP changes
were well written and did not require any
additional clarification.
Physical Security Instruction Hanual
(PSIH),
Section
105,
was reviewed
and considered
acceptable
as guidance to
implement the l.icensee's
compensatory
measures
for inoperative active
vehicle barriers.
The procedure
required that inoperative active
barriers
be compensated
for within 10 minutes.
Section
105. of the PSIH
guidance stated that "a vehicle of at least
3 tons or higher be provided
in front of a non-functioning active vehicle barrier."
Additionally,
the inspector
reviewed
PSIH. Section
105, Security Testing
and
Haintenance
and found the licensee
had included the proper testing
and
maintenance
requi rements.
Conclusion
A random review,of plans,
records,
reports,
and interviews with
appropriate individuals verified that security plan and procedures
changes
did not decrease
the effectiveness
of the
PSP.
The inspector
reviewed Revision 1, 2,
and 3. to the
and Revision
21 and
22 of the
T&Q Plan and concluded that the
and
T&Q Plan changes
as submitted,
met the requirements of'0 CFR 50.54(p).
There were no violations of
regulatory requi rements
noted in this area.
il
0
0
S6
S6.1
21
Security
Or ganization
and Administration
Mana ement
Su
ort
Ins ection Sco
e
81700
The inspector
evaluated
the degree of the licensee's
management
support
to the Physical Security Program.
Based
on the requirements
contained
in the
PSP,
the inspector
reviewed the licensee's
Safeguards
Event Log
(SEL) entries.
This review was to determine if the licensee
appropriately assigned,
analyzed,
and set priorities for corrective
action for the reports
and log entries,
and whether the corrective
action taken
was technically adequate
and timely.
Observations
and Findin s
The licensee
had an on-si.te physical protection system
and security
organization.
Their objective was to provide assurance
against
an
unreasonable
risk to public health
and safety.
The security
organization
and physical protection system were designed to protect
against the design basis threat of radiological sabotage
as stated in
10 CFR 73. 1(a).
A proprietary security force provided site security for
the licensee.
At least
one full-time manager of the security
organization
was always on-site.
This individual had the authority to
di rect the physical protection activities of the organization.
The
management
system included
a mechanism
for establishing,
maintaining,
and enforcing written security procedures.
Licensee
management
exhibited
an awareness
and favorable attitude toward physical protection
requirements.
This was evident by the support that security was
provided in preparation for the Operational
Safeguards
Response
'valuation
(OSRE) which was successfully
completed
on May 8,
1997,
and
the continued outstanding
maintenance
and engineering
support to
maintain
and enhance security equipment.
The review of the SELs as of June
1997 indicated the following:
EVENTS
4th Quarter
'96
.
2nd Quarter
'97
1st Quarter
'97
Human Errors
Hardware Systems
Other Events
TOTALS
12 (11K)
97
(88%)
109 (100K)
03 (5C)
54 (95K)
57 (100K)
15 (17K)
74 (83K)
89 (100K)
Each quarter
had an excellent Trending Summary report that was provided
to site management.
4I
22
There were no long term compensatory
measures
in effect at the time of
the inspection.
Review of previous
compensatory
measures
indicated that
the licensee
had 2219 hours0.0257 days <br />0.616 hours <br />0.00367 weeks <br />8.443295e-4 months <br /> of compensatory
measures
in FY 1996.
Most
of the compensatory
measures
were in support of planned
outage of
equipment to support operations.
Review of the outstanding security
work-orders revealed the following:
~
0 High Priority orders
~
0 Medium Priority
~
19 Low Priority
Of the
19 outstanding security work-orders.
none involve regulatory
requirements.
Conclusion
The inspector
found that licensee
management
provided appropriate
and
excellent support for the Physical Security Program.
Examples of the
excellent
management
support were the support in preparation for the
OSRE and the continued engineering
and maintenance
support to maintain
the security equipment in a high state of readiness.
Additionally, as
'another
enhancement
the licensee is installing
a lightning dissipation
system to greatly eliminate lightning from striking the security
and
plant monitoring equipment.
There were no violations of regulatory
requirements
noted in this area.
Effectiveness of Mana ement Control
Ins ection Sco
e
81700
The inspector
evaluated
the adequacy of the licensee's
controls for
identifying, resolving
and preventing
problems
by reviewing such areas
as corrective action systems,
root cause
analyses,
and self-assessment
in the area of physical security.
Also, this inspection
was to
determine whether there were strengths
or weaknesses
in the licensee's
controls for the identification and resolution of the reviewed issues
that could enhance
or degrade plant operations
or safety.
Observations
and Findin s
To determine the adequacy of the above,
the inspector
reviewed the
,
licensee's
SEL entries.
This review was to determine if the licensee
appropriately assigned,
analyzed,
and set priorities for corrective
action for the reports
and log entries,
and whether the corrective
action taken
was technically adequate
and timely.
The root cause
analyses,
corrective actions,
and self-assessments.
as
mentioned in Paragraph
S6. 1,
above
and in Paragraph
S7. 1 below, were
reviewed
and found appropriate
and adequate.
II
Conclusion
23
S7
S7.1
The inspector
concluded that the licensee
evaluated the non-human
errors,
hardware
and mechanical
problems
and they were effectively
controlled and managed.
Quality Assurance in Security and Safeguards Activities
Audits and Corrective Actions
Ins ection Sco
e
81700
Based
on the commitments of the
PSP, the inspector evaluated
the
licensee's
audit program
and corrective action system.
This also
ensured
compliance with the requi rement for an'nnual
audit of the
security
and contingency programs.
During the inspection,
a small
representative
sample of the problems identified by audits
was evaluated
by the inspector to determine whether review and analysis
were
appropriately assigned,
analyzed,
and prioritized for corrective action
and whether the corrective action taken
was technically adequate
and
performed in a timely manner.
Observations
and Findin s
The licensee's
program commitments
included auditing its security
program,
including the Safeguards
Contingency Plan, at least every
12
months.
The audit included
a review of routine and contingency security
procedures
and practices.
This review evaluated
the effectiveness
of
the physical protection system testing
and maintenance
program.
This
annual audit was completed
on January
30,
1997.
and the results
are
documented in audit report SSA-9617.
The audit report was sent to the
site Vice President
and Corporate
Management.
Reports of audits were
available for inspection at the plant for a period of three years.
The
auditors concluded that the security program continued to meet the
regulatory requi rements.
In addition to the annual audits.
the licensee
had conducted audits of specific security practices
and the audit
findings were documented
in NA-BF-97-01, dated January
27,
1997;
NA-BF-97-11, dated February 25,
1997;
NA-BF-97-23, dated
March 31,
1997;
NA-BF-97-35, dated
May 6,
1997;
and NA-BF-97-46, dated June 3.
1997.
Conclusion
Licensee-conducted
audits were thorough,
complete,
and effective in
terms of uncovering weaknesses
in the security system,
procedures,
and
practices.
The last audit report concluded that the security program
was effective.
The licensee
had acted appropriately in response to
recommendations
made in the audit report.
The inspector determined that
audit items were reviewed. appropriately assigned,
analyzed,
and
prioritized for corrective action.
The corrective actions taken were
technically adequate
and performed in a timely manner
.
There were no
violations of regulatory requirements
noted in this area.
0
0
S.8
S8.1
S8.2
F2
24
Miscellaneous Security and Safeguards
Issues
(92904)
CLOSED
VIO 50-259 260 296/96-07-01,
Failure to Properly Search
Packages
Entering the Protected
Area.
The inspector
reviewed the
licensee's
lesson plan,
personnel
and package
search
enhancement,
and
the attendance
roster
and determined that all personnel
had been
retrained in proper search
procedures
as
a result of the incident.
The
inspector
reviewed search
procedures
during the inspection
and concluded
that 'personnel
were searching
packages
and containers
as required.
The
corrective action is considered
adequate
to close this violation.
CLOSED
IFI 50-259
260 296/96-07-02,
Lighting Glare Prevents
Adequate
Assessment
at the Intake Structure.
The licensee's
corrective actions
included re-positioning
and refocusing of cameras
25a
and 25b.
and hoods
were placed
on the cameras to prevent rain from landing on the lens
and
to shield direct light from the cameras.
Also. the light bulbs
on the
handrail
were changed to non-glare bulbs,
and the lens on'the high mast
lights were repositioned to reduce glare.
The inspector determined that
the corrective actions were adequate to close this IFI.
Status of Fire Protection Facilities and Equipment
Ins ection Sco
e
71750
62707
The inspector
observed
performance of section 7.2.8 of O-SI-4.11.8.1.C.
High Pressure
Fire Protection
System Flushes.
This section
addressed
portions of the Unit 2 reactor building preaction sprinkler system.
In
addition to assessing
the conduct of the test,
the inspector
examined
the strainer basket to determine if excessive quantities of corrosion
products or other materials
were entering the fire protection system.
Observations
and Findin s
The work was completed according to the work instructions.
The procedure
was actively uti1ized and the workers were knowledgeable of the
evolution.
Radio communications
were appropriately formal.
The workers
were careful
when draining the system to minimize overflow of the floor
drain.
Second party and independent verification were performed in
accordance
with requirements.
The workers were cautious
when re-opening
isolation valves.
The procedure directed that fire protection water be flushed (from the
outside loop header
into the reactor building and through the strainer)
for at least
10 minutes.
The strainer basket
was then inspected.
The
inspector
observed that the strainer contained only a thin film of
minute particles which could be easily wiped off.
There was not any
accumulati.on of corrosion products or other river materials in the
strainer or housing.
This indicated that the licensee's
processes
for
the raw water fire protection system are adequately protecting the
system.
IR 97-07 described
programmatic
review of the licensee's
program to,maintain the reliability of the fire protection
raw cooling
water
system.
0
25
R4
Staff Knowledge and Performance
in Radiological Controls
and Chemistry
R4. 1
Hi
h Radiation Area Doors
a.
Ins ection Sco
e
71750
During the inspection period, the inspectors verified that locked high
radiation areas
were maintained in accordance
with the licensee's
procedural
guidance.
b.
Observations
and Findin s
During tours of the facility, the inspectors
checked
numerous
locked
doors to verify that the doors were maintained
locked.
No problems were identified.
V.
Mana ement Meetin s
Xl
Exit Meeting Summary
The resident inspectors
presented
inspection findings and results to
licensee
management
on September
17,
1997.
Other formal meetings to
discuss
report issues
were conducted
on August
15 and September
8.
The licensee
acknowledged
the findings presented.
Proprietary
information is not included in this inspection report.
Licensee
PARTIAL LIST OF PERSONS
CONTACTED
T. Abney, Licensing Manager
,J. Brazell, Site Security Manager
R.
Coleman, Acting Radiological Control
Manager
J.
Corey, Radiological Controls
and Chemistry Manager
T. Cornelius,
Emergency
Preparedness
and Planning
C. Crane, Site Vice President,
Browns Ferry
R.
Greenman,
Training Manager
J.
Johnson,
Site (juality Assurance
Manager
R. Jones,
Assistant Plant Manager
S.
Kane, Acting Site Licensing Supervisor
G. Little, Acting Operations
Manager
D. Nye, Site Engineering
Manager
K. Singer,
Plant Manager
J. Schlessel,
Acting Maintenance
Manager
0
0
IP 37550:
IP 37551:
IP 40500:
IP 62707:
IP 61726:
IP 71707:
IP 71750:
IP 73756:
IP 81502:
IP 81700:
IP 92901:
IP 92902:
IP 92903:
IP 93702:
26
INSPECTION
PROCEDURES
USED
Engineering
Onsite Engineering
Licensee Self-Assessments
Maintenance
Observations
Surveillance Observations
Plant Operations
Plant Support Activities
Inservice Testing of Pumps
and Valves
Fitness
For Duty Program
Physical Security Program for Power
Reactors
Followup-Plant Operations
Followup-Maintenance
Followup-Engineering
Prompt Onsite Response to Events at Operating
Power Reactors
ITEMS OPENED
DISCUSSED
AND CLOSED
OPENED
~T
e
Item Number
50-260/97-09-01
50-260/97-09-02
50-260/97-09-03
Status
Open
Open
Closed
Descri tion and Reference
Functional Testing of Snubbers
While
Not in Refueling Out.age Conditions
(Section Hl.2)
Scaffolding Controls not Properly
Implemented
(Section Hl.l)
Incorrect Oil Used in Two EOGs
(Section E8.5)
50-260/97-09-05
Closed
50-296/97-09-06
Open
IFI
50-260,296/97-09-07
Open
50-260,296/97-09-04
Closed
Failure to Follow Procedure for
Workplan Revision (Section H8.3)
Failure of Fuel
Pool Cooling
Pump
(Section E8.4)
Actions for Inoperable
Containment
Isolation Valve (Section Ol. 1)
RHRSW/EECW
Pump Flow Testing Issues
(Section El. 1)
DISCUSSED
T~e
Item Number
IFI
296/96-08-03
Status
Open
Descri tion and Reference
Unit 3 Hain Steam Isolation Valve
(MSIV) Circuitry Failures
(Section
M8.4)
il~
0'
27
0
~T
e
Item Number
'ER
296/96-002-00
296/96-12-01
296/96-13-03
LER
260/96-002-00
50-296/96-04-07
LER
296/96-004-01
LER
296/96-006-00
LER
260/96-004-00
260/96-004-01
260/96-008-00
260'/96-008-01
260/95-003-02
Status
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Descri tion and Reference
Unit 3 Scram Following Loss Of
Reactor
Feedpump
3C (Section 08. 1)
Failure to Ensure
Proper Position of
EDG Aux Board
Room Exhaust'ans
(Section 08.2)
Uncontrolled Locked High Radiation
Area
(LHRA) (Section 08.3)
An Emergency Diesel Generator Auto-
Started
Due To Under voltage
Condition As A Result of Personnel
Error (Section M8.1)
Main Steam Isolation Valves Leak
Rate
Exceeded
the Local Leak Rate
Test Acceptance Criteria due to
Internal
Component
Wear (Section
M8.2)
All Eight Plant
Emergency Diesel
Generators
Unexpectedly Auto-Started
From A Spurious
High Drywell
Pressure
Signal
(Section M8.3)
Failure to Follow Procedural
Requirements
for Installation of
Scaffolding (Section
M8.5)
Loss of the Emergency
Core Cooling
Systems
(ECCS) Division I and
Division II Instrumentation
Renders
Equipment, Inoperable
(Section
E8.1)
Unit 3 Scram
On Low Reactor Water
Level
Due To Failure Of The Steam
Packing
Exhauster
Bypass
Flow
Control Valve (Section E8.2)
Main Steam Safety/Relief Valves
Exceeded
the
TS Required Setpoint
Limit as
a Result of Disc/Seat
Bonding (Section E8.3)
(
0
260/97-07-04
Closed
260/97-08-02
Closed
IFI
259,Z60,Z96/96-07-02
Closed
259,260,296/96-07-01
. Closed'8
Failure of Fuel
Pool Cooling
Pump
(Section E8.4)
Incorrect Oil Used in Two EDGs
(Section E8.5)
Failure to properly search
packages
(Section S8.1)
Lighting glare hampered
assessment
at intake structure
(Section S8.2)
ik~
il~