ML18037A803
| ML18037A803 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 03/14/1994 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18037A801 | List: |
| References | |
| 50-259-94-01, 50-259-94-1, 50-260-94-01, 50-260-94-1, 50-296-94-01, 50-296-94-1, NUDOCS 9403280149 | |
| Download: ML18037A803 (42) | |
See also: IR 05000259/1994001
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report Nos.:
50-259/94-01,
50-260/94-01,
and 50-296/94-01
Licensee:
Valley Authority
-6N 38A Lookout Place
1101 Market Street
Chattanooga,
TN
37402-2801
Docket Nos.:
50-259,
50-260,
and 50-296
License Nos.:
and
Facility Name:
Browns Ferry Units 1,
2,
and
3
Inspector:
Inspection at Browns Ferry Site near
Decatur,
I
Inspection
Conduct
- January
15 - February
18,
1994
J Jb'AC>A~~
.i attersp
,
enior
ess
ent
nspector
r
ate
Soigne
Accompanied
by:
J.
Hunday,
Resident
Inspector
R. Husser,
Resident
Inspector
G. Schnebli,
Resident
Inspector
Approved by:
au
s
Rea to
OJe t
, Section
4A
Division of
e
tor Projects
g/
a
e
cygne
SUMMARY
Scope:
This routine resident
inspection
included surveillance observation,
mainte-
nance observation,
operational
safety verification, modifications, Unit 3
restart activities, fire protection, self assessment,
and action
on previous
inspection findings.
One hour of backshift coverage
was routinely worked during the work week.
Deep backshift inspections
were conducted
on January
20,
21,
23,
and February
2,
12,
13,
1994.
9~ g 801p9 94031
ADOCK 050
8
0
Results:
In the area of surveillance,
a violation was identified by an NRC,inspector
during the review of a completed containment visual inspection surveillance,
paragraph
2.
Three elevations
were not inspected
due to refueling operations
in progress.
The licensee's
review of the surveillance
by several
groups did
not detect the problem.
The licensee
conducted
an analysis for operability
and initiated an incident investigation of the problem.
In the area -of maintenance
(modification),
a violation was identified by an
NRC inspector concerning the upgrade of an offsite power source in the
paragraph
5.
Mork plans being used did not contain the proper
signatures
for numerous
items.
The work was being performed
by customer
service
group craft that were not trained
on work plans.
There
was
no quality
control
involvement with the modification and only a contractor field engineer
providing supervision.'he
licensee
stopped
the job and provided training to
the craft on work plans.
In the area of plant support,
a violation was identified by the licensee for a
missed fire watch for an inoperable
carbon dioxide system,
paragraph
7.
A
similar event occurred
on June 4,
1993,
when
a required firewatch was relieved
prior to the system being declared
In th'e area of engineering,
a violation was identified with two examples of
design errors concerning
Appendix
R, paragraph
7.
The first example
was that
power supply cables for both reactor water cleanup
system containment isola-
tion valves were routed in the
same fire zone without adequate
separation.
The second
example
was that
a fault in the power supply to
a raw cooling water
pump was not adequately
separated
to prevent propagation to
a shutdown board.
Both of the issues
are being covered
by compensatory fire watches
but will
require extensive plant modification during the next refueling outage to
correct.
In the area of engineering/technical
support,
a violation with two examples
was identified by an
NRC inspector for failing to make the required
and 50.73 reports,
paragraph
8.
The first example
was that two trains
of the standby
gas treatment
system were inoperable
and could have prevented
the fulfillment of a safety function.
The second
example
was that two
Appendix
R design errors resulted
in the plant being outside the design basis.
In the area of surveillance,
a noncited violation was identified for
an
inadvertent
emergency
equipment cooling water
pump motor start during
a
surveillance,
paragraph
2.
The licensee
made
a 4-hour notification and
initiated
an incident investigation of this event.
A second party check
was
not performed adequately
to prevent the installation of jumpers
on
a wrong
relay.
In the area of plant support,
an unresolved
item was identified concerning
an
undocumented
modification to the diesel
driven fire pump that prevented
the
automatic start function, paragraph
5.
The 'licensee initiated an incident
investigation of this event.
IP
P'
In the area of operations,
routine control of plant evolutions
such
as
backfilling reactor water level reference'egs
and response
to equipment
failures were good.
These evolutions are conducted
in
a controlled cautious
manner.
Upgrades to focus
on operable
and
common equipment in the Unit I
control area
was good.
In the area of radiological controls,
a weakness
was noted in the implementa-
tion of the use of digital alarming dosimeters,
paragraph
4.
Personnel
were
not familiar with how to properly wear the dosimeters
or the purpose of the
alarm.
REPORT DETAILS
Persons
Contacted
Licensee
Employees:
0. Zeringue,
Senior Vice President,
Nuclear Operations
- R. Machon, Plant Manager
J. Rupert,
Engineering
and Modifications Manager
T. Shriver,
Licensing
and qua]ity Assurance
Manager
D. Nye, Recovery Manager
E. Preston,
Operations
Manager
~J.
Haddox,
Engineering
Manager
- H. Bajestani,
Technical
Support
Manager
- A. Sorrell, Chemistry
and Radiological Controls Manager
- C. Crane,
Maintenance
Manager
P. Salas,
Licensing Manager
- R. Wells, Compliance
Manager
- J. Corey, Radiological
Control Manager
J. Brazell, Site Security Manager
Other licensee
employees
o'r contractors
contacted
included licensed
reactor operators,
auxiliary operators,
craftsmen,
technicians,
and
public safety officers;
and quality assurance,
design,
and engineering
personnel.
NRC Personnel:
P. Kellogg, Section Chief
- C. Patterson,
Senior
Resident
Inspector
- J. Hunday,
Resident
Inspector
- R. Husser,
Resident
Inspector
G. Schnebli,
Resident
Inspector
- Attended exit interview
and initialisms used throughout this report ate listed in the
last paragraph.
Surveillance Observation
(61726)
The inspectors
observed
and/or reviewed the performance of required SIs.
The inspections
included reviews of the SIs for technical
adequacy
and
conformance
to TS, verification of test instrument calibration,
observa-
tions of the conduct of testing,
confirmation of proper removal
from
service
and return to service of systems,
and reviews of test data.
The
inspectors
also verified that
LCOs were met, testing
was accomplished
by
2'ualified
personnel,
and the SIs were completed within the required
frequency.
The following SIs were reviewed during this reporting
pet iod:
a.
b.
RCIC Turbine Exhaust
Rupture Disc High Pressure
Calibration
On February
1,
1994,
the inspector witnessed
the performance of
portions of 2-SI-4.2.B-34{A) and 2-SI-4.2.B-34{C), Reactor
Core
Isolation Cooling System Turbine Exhaust
Rupture Disc High Pres-
sure Calibration for the 2-PS-71-11A
and 2-PS-71-11C,
respective-
ly.
These switches
sense
pressure
in the rupture disc volume and
isolate the
RCIC steam supply valves
on increased
pressure.
This
surveillance, verifies the switches
are in calibration
and satis-
fies the requirements
of TS Table 4.2.B.
The inspector verified
the test
equipment
being used
was appropriate for the job, the
procedure
was the most current revision,
and the instruments
were
removed
from service,
tested,
and returned to service within the
time allowed by the
LCO.
The inspector also reviewed the complet-
ed procedure
and noted
no discrepancies..
In addition, 2-SI-4.2.B-
40A,
RCIC System
Logic Functional Test,
was reviewed
by the
inspector to verify that all components
of the turbine exhaust
rupture disc pressure
high isolation logic were being tested.
While performing this review the inspector
noted errors
on RCIC
.logic drawings
2-45E626-1
and 2-45E626-2.
These discrepancies
were of minor significance but were brought to the attention of
the system engineer for his review and validation.
The system
engineer initiated
PDD 94-055 to correct the ei rors.
No other
discrepancies
were noted.
Inadvertent Start of EECW
Pump
On February 4,
1994, during the performance of O-SI-4.2.B-67,
Service Water Initiation Logic,
A3
EECW pump inadvertently start-
ed.
During this portion of the SI jumpers
are installed to
prevent automatic starting of RHRSW pumps
on simulated 'low RCW
.
system pressure.
The jumpers should
have
been placed
on relay
SSCRA but were installed
on
a relay labeled
SPARE.
The inspector
reviewed the SI procedure
and the procedure
step
was required to
be second party checked.
The inspector toured the 4kV Shutdown
Board
3EA in the
DG building where the relays are located.
The
two relays
are clearly marked with an identification label under-
neath
each relay on the front of the panel.
The jumpers
are
'laced
on the back of the panel.
The
SSCRA relay is located
directly above the
SPARE relay.
The licensee
made
a 4-hour notification per
and
Incident Investigation II-8-94-05 was initiated for the event.
Since there
have
been
no similar violations during the past
two
years, this violation of procedural
compliance
meets
the criteria
for a licensee identified violation.
It, will be identified as
NCV 259,
260,
296/94-01-01,
Inadequate
Second
Party Check.
This
violation will not be subject to enforcement
action because
the
licensee's
efforts in identifying and correcting the violation met
the criteria specified in Section VII.B of the Enforcement Policy.
Containment
During the first quarter of 1991,
TVA's Nuclear guality Audit and
Evaluation Department
performed
an audit of Service
Level I
Protective
Coating
Programs for all TVA nuclear plants.
This
inspection effort reviews the results of the audit
and corrective
actions
as they relate to the Browns Ferry Nuclear Plant.
Two
findings were identified by the audit team at Browns Ferry.
The first and more significant issue dealt with the failure to
identify the addition of uncontrolled coatings into the Unit 2
containment for evaluation
and possible inclusion in the uncon-
trolled coatings log.
Additionally, nuclear engineering
had
failed to identify all uncontrolled coatings in the log during
initial baseline
walkdowns.
'As
a result of these findings, the
licensee
reperformed
a baseline
evaluation
of- the containment to
identify all uncontrolled coatings.
This 'effort resulted
in the
issuance of a revised
containment
coating log.
Numerous
items
were identified with uncontrolled coatings with thicknesses
greater
than
3 mils.
The majority of the items identified with
coatings greater
than
3 mi1s were
sanded
and feathered
down to
a
dry film thickness of less than or equal to 3 mils.
This work was
performed in accordance
with work order 91-27917-00.
Items with
uncontrolled coatings of 3 mils or less
were accepted
as is based
on Detroit Edison Report
No. DECO-12-2191,
Revision
4 (June
1985),
"Enrico Fermi Atomic Power Plant Unit No.
2 - Evaluation of
Containment Coatings."
This report concludes that coatings with a
dry film thickness of 3 mils or less
are too thin to form debris
that might contribute to strainer blockage.
This position has
been
accepted
by the
NRC.
The inspector
reviewed the updated unqualified containment coat-
ings log which is documented
under guality Information Re-
quest/Release
gIRMTBBFN88025,
Rev.
4.
This document
also provides
the unqualified containment
coatings evaluation.
All unqualified
containment coatings,
including those with a dry film thickness of
less
than
3 mils, are included in the log.
The total allowable
unqualified coatings
(with a dry film thickness of greater
than
3
mils) is
157 square
feet..
This amount of coating,
which might
flake off during
an accident,
would not block
pump strainers
enough to affect the net positive suction
head requirements
of the
RHR and core spray
pumps.
Currently,
Browns Ferry's uncontrolled
containment
coating log lists approximately
78 square feet of
coating with a dry film thickness of greater
than
3 mils.
This
amount is well within the
157 square foot limit.
Additional corrective actions for this matter involved revising
HAI-5.3,.(a Hodification and Addition Work Instruction Procedure),
Protective Coatings,
to control all Service
Level I protective
at the site.
All personnel
associated
with writing and
planning of work plans (modifications)
and work orders
(mainte-
nance)
were informed of the requirements
of MAI-5.3.
Additional-
ly,
a special
work step
was inserted into the work plan logic in
(SSP-9.3,
Plant Modifications and Design
Change Control,) to
require all material
being installed inside primary containment to
be coated with Level I coatings or evaluated
per MAI-5.3.
Like-
wise,
SSP-6.2,
Maintenance
Management
System,
was revised to
require that all painted material
being installed inside primary
containment
be evaluated
per MAI-5.3.
These actions
were reviewed
by the inspector
and found to be acceptable.
The second
issue identified by the audit team dealt with protec-
tive coating failures in the Unit 2 drywell.
Numerous
areas of
lack of adhesion
and delamination of coatings
were noted
on
various elevations
and azimuth locations within the drywell.
These
items were dispositioned
in accordance
with
WO 90-08921-00
by removing the coatings
not properly adhering to the base surfac-
es.
Procedure
MAI-5.3, Protective Coatings,
and
TS 4.7.A.2.K,
requires that the drywell surfaces
be inspected
each
18 months for
structural integrity and condition of coatings.
This inspection
provides
adequate'measures
to ensure
containment
remain
in an acceptable
condition.
On January
27,
1994,
as
a part of this inspection effort, the
inspector
reviewed completed surveillance
records for O-SI-4.7.A.-
2.K, Primary Containment
Drywell Surface Visual Inspection,
which
was performed during the Unit 2 Cycle
6 refueling outage.
The SI
was performed April 28,
1993.
The review indicated that visual
inspections
required
by steps 7.6.2, 7.6.3,
and 7.6.4 were not
completed for the upper three elevations
(604', 616',
and 633') in
the Unit 2 drywell.
These
inspections
involved visually verifying
that
no structural
damage,
displacement,
or deterioration existed
in relation to piping connectors,
supports,
struc-
tural supports,
platform steel,
duct hangers,
concrete walls, the
steel liner; and the cable trays.
The data sheet
associated
with
the inspection
indicated that only the lower three elevations
(550', 563',
and 584') were inspected
due to ongoing fuel loading.
The inspector
brought this matter to the attention of the licens-
ee.
The licensee
promptly reviewed the matter for operability and
potential
non-conformance
to technical specifications.
The
licensee
determined that sufficient evidence existed to reasonably
conclude that the surveillance criteria were met or would have
been
met based
on other inspections
performed.
These
inspections
include the
ASME Section
XI Inservice Hydrostatic Test
and the
Drywell Closeout inspection
performed in accordance
with 2-SI-3.3
and 2-GOI-200-2 respectively.
The inspector reviewed the license-
e's analysis
and concluded
no immediate safety concern existed.
The failure to fully complete
SI O-SI-4.7.A.2.K, is
a violation of
TS 4.7.A.2.K.
The significance of this matter is further com-
pounded
by the fact that the results
(data) for the test in
question
were reviewed
by a senior reactor operator,
mechanical
maintenance
supervisor,
and cognizant
system engineer. without the
deficiency being discovered.
The licensee
is currently conducting
an incident investigation
on this situation.
This matter will be
tracked
as
VIO 260/94-01-02,
Failure to Proper ly Perform Contain-
ment Visual Inspection Surveillance.
Two violations were identified in the Surveillance Observation
area.
3.
Haintenance
Observation
(62703)
Plant maintenance activities were observed
and/or reviewed for selected
safety-related
systems
and components
to ascertain that they were
conducted
in accordance
with requirements.
The following items were
considered
during these
reviews:
LCOs maintained,
use of approved
procedures,
functional testing and/or calibrations
were performed prior
to returning components
or systems to service,
gC records maintained,
activities accomplished
by qualified personnel,
use of properly
certified parts
and materials,
proper
use of clearance
procedures,
and
implementation of radiological controls
as required.
Work documents
were reviewed to determine
the status of outstanding jobs
and to- assure
that priority was assigned
to safety-related
equipment
maintenance
which might affect plant safety.
The inspectors
observed
the following maintenance
activities during this reporting period:
a
~
Diesel Generator
1D Haintenance
On January
18,
1994, the inspector witnessed
portions, of an
inspection of the
1D
DG cylinder liners.
The inspection
was being
conducted
in response
to a Part
10CFR21-0067 report which
identified
a cracking problem with two particular models of
cylinder liners
on
EHD DGs.
Browns Ferry has the model
referred to in the report,
however, this inspection
determined
that they do not have the model cylinder liners identified as
defective.
The inspector witnessed
the inspection,
conducted
in
accordance
with
WO 94-00459-03,
and noted
no concerns.
On January
25,
1994,
the
3D
DG was inspected
and
on February 7,
1994, the
3A
DG was inspected with neither having the model liner identified.
An inspection of the remaining
DGs cylinder liners will be
conducted
as they are
removed
from service for scheduled
routine
maintenance.
b.
Reactor Mater Level Instrument Backfill
On January
25,
1994,
the inspector
observed
maintenance
personnel
backfill the
A side reactor water level instrument reference
leg.
Prior to the backfill the A side instruments
indicated
two to
three
inches higher than the
B side instruments.
Following the
maintenance
the
B side instruments
indicated approximately two
inches higher than the
A side.
The craft performed the work using
WO 93-14451-00.
The inspector verified the proper authorizations
0
E
were obtained,
HIITE was appropriate,
and the
WO was being followed
as written.
No discrepancies
were noted.
- On January
26,
1994, the licensee
determined that the
B side level
instrument reference
leg also
needed backfilling.
Prior to
performing the work the
B side instruments
indicated approximately
two inches higher than the
A side instruments.
After the
maintenance
the
B side instruments
indicated approximately
one
inch lower than the
A side instruments,
which satisfies
the
acceptance
criteria of site procedures.
Engineering
and
Operations
were satisfied with these results.
The inspector
reviewed the controlling
WO 93-15059-00
and noted
no
discrepancies.
On February
14, 1994,.the
A side reactor water level instrument
reference
leg was again backfilled.
Before the backfill, the
A
side instruments
indicated approximately three inches higher than
the.B instruments.
Following the backfill, the
A side instruments
indicated approximately
one inch higher than the
B instruments.
While slight leaks
from three water level instruments
were
identified as contributing to the problem, the system engineer
stated that backfilling will probably
be required approximately
every 45 days.
The inspector witnessed
the process
and found no
discrepancies.
On February
17,
1994,
the wide range 'A'eactor water level
instrument reference
leg was backfilled.
The work was performed
in accordance
with
WO 94-00037-01,
which contained
step
by step
instructions detailing the evolution.
The licensee
determined
that in order for the work to be performed
on line and in a safe
manner,
three
TS instruments
would have to be removed
from service
and appropriate
LCOs entered.
A pre-job briefing was conducted
by
the system engineer to ensure that all involved personnel
knew
their individual responsibilities
as well as the entire "backfill
team."
Prior to the backfill, the 'A'ide instrumentation
indicated
water level exceeded
the 'B'ide instrumentation
by approximately
four inches.
The inspectors
observed
the evolution from both the
control
room and in the field.
The work was performed in
'accordance
with procedures
and progressed
in a timely and safe
manner.
Following the backfill, the 'A'nd '8'nstruments
indicated approximately within one inch of each other.
No
discrepancies
were identified.
Previous discussion of backfilling and the modification for
resolution of these
problems
by NRC Bulletin 93-03 is discussed
in
IR 93-39.
C.
7
ECCS Inverter Failure
On February
14,
1994,
the Division II ECCS
ATU Inverter failed as
a result of a blown fuse.
The inverter supplied
power to the ATUs
which provide auto start functions for safety related
systems.
The loss of this inverter placed the plant in an
LCO requiring the
unit to be in Hot Standby in six hours
and Cold Shutdown in the
fol'lowing thirty hours unless corrective
measures
are taken
sooner.
Approximately two hours into the event the fuse was
replaced,
however, it was then identified that
an electronic card
which controls the inverter output frequency
was also defective.
The card
was replaced
and the system satisfactorily returned to
service approximately
one hour later.
The
LCO was exited without
a plant shutdown
commencing.
A one hour report to the
NRC was
made,
in accordance
with 10 CFR 50.72, to report the inoperability
of the
HPCI system
and to give the general
status of the plant.
The licensee will followup with a thirty day report.
The licensee
intends to send the fuse
and electronic card to the vendor for
analysis
in an effort to determine
the cause of the failure.
The
inspector
observed
the troubleshooting,
maintenance,
and post
maintenance
test activities
and noted
no discrepancies.
No violations or deviations
were identified in the Haintenance
Observation
area.
Operational
Safety Verification (71707)
The
NRC inspectors
followed the overall plant status
and
any significant
safety matters related to plant operations.
Daily discussions
were held
with plant management
and various
members of the plant operating staff.
The inspectors
made routine visits to the control
rooms.
Inspection
observations
included instrument readings,
setpoints
and recordings,
status of operating
systems,
status
and alignments of emergency
standby
systems,
verification of onsite
and offsite power supplies,
emergency
power sources
available for automatic operation,
the purpose of
temporary tags
on equipment controls
and switches,
annunciator alarm,
status,
adherence
to procedures,
adherence
to LCOs, nuclear instruments
operability, temporary alterations
in effect, daily journals
and logs,
stack monitor recorder traces,
and control
room manning.
This
inspection activity also included
numerous
informal discussions
with
operators
and supervisors.
General
plant tours were conducted.
Portions of the turbine buildings,
each reactor building,
and general
plant areas
were visited.
Observations
included valve position
and system alignment,
and
hanger conditions,
containment isolation alignments,
instrument
readings,'ousekeeping,
power supply
and breaker alignments,
radiation
and contaminated
area controls,
tag controls
on equipment,
work
activities in progress,
and radiological protection controls.
Informal
.discussions
were held with selected
plant personnel
in their functional
areas
during these tours.
Unit Status
Unit 2 operated continually without any significant problem during
this period.
At the end of the period the unit had
been online
for 260 days.
Minor water level indication variations occurred
discussed
in this report.
f
Control
Room Operations
During routine tours of the control
room the inspector noticed
several
improvements to the Unit
1 control
room.
Although there
are
no plans to return the unit to operation,
some
common
and
other equipment
can
be operated
from the control boards.
The
number of hold order tags
has greatly been
reduced
as the system
status
on
some
systems
are
no longer controlled.
The new type
pump motor hand switch handles
were put on for the
RHRSW pumps.
Chart recorders that are
no longer in use
have
a sign placed over
the recorder stating the equipment is out of service.
Other
enhancements
were
made to upgrade the appearance
of Unit
1 control
room and focus operator attention
on the remaining operable
and
common equipment.
Control
Bay Tour
During
a routine tour of the control building and electrical
board
room containing
4160 volt shutdown
board
C on February
8,
1994,
the inspector identified the following concerns:
1.)
A circuit breaker for compartment
8A on 480 volt board
2A
was in the off position
and did not have an'dentification
label similar to the other breakers.
This was reviewed
and
, determined
to be
a spare
breaker
compartment.
The licensee
put
a note in the plant night orders for operators
to be
more aware of labeling problems.
2.)
Next to the control
room abandonment
procedure
storage
cabinet,
with a locking tab in place,
was
a controlled copy
of the procedure,
2-AOI-100-2 dated
October
19,
1993,
revision 21, in another
green storage
cabinet.
The
inspector determined that the latest revision of the
procedure
was revision
24 dated
December
15,
1993.
The
stor'age
cabinet with the locking tab was opened
and the
correct
copy of the procedure
was in place.
The licensee
removed the copy with the out of date revision.
The
inspector discussed
with the licensee that old copies
should
be shredded,
tom in half, or identified by some other means
to insure they are not used.
3.)
WR C160866 tag dated
December
3,
1993,
was to fill in or
seal
a partial penetration for an opening in the floor.
The
licensee
removed this seal
and determined it was being
monitored
by a compensatory fire watch.
Words were
added to
the tag to identify the action.
4.)
A fire alarm had
sounded
around 7:00 a.m.
and the fire truck
responded,
however, there
was
no log entry in the
ASOS or
SOS control
room logs.
SSP-12. 1,
Conduct of Operations,
under section
3. 11.3,
Information to be Recorded, lists
medical/fire emergencies
as items to be recorded.
Operations
management
reviewed this and determined that
an
entry was
made in the Unit
1 operators
log and
a late entry
was
added to the
SOS log.
The event occurred
around shift
turnover time and the log entry was overlooked.
Housekeeping
On January
24,
1994, during
a routine tour of the cable spreading
room the inspector noticed
a decline in housekeeping
standards.
The inspector entered
the Unit
1 and
2 room through door 533
and
noticed the following next to the entrance
door:
Sign for phone fallen to the floor
Caution sign for C02 fallen to the floor
A padlock locked around
a cable in a cable tray
Broken glass
on the floor.
Conduit fittings under
a ventilation duct
General
area dusty
Graffiti on exit security card reader
These findings were discussed
with plant management.
After the
concerns
were again raised
on February 4,
1994,
items were
promptly corrected.
REX System
Problems
In IR 93-39 the inspector discussed
problems with reliability of
the
REX system.
The licensee
compared
the TLD dose for the fourth
quarter to the Merlin Gerin
(MG) 'digital alarming dosimeters
(DADs).
The
MG dose was'0X lower than TLDs.
The licensee
initiated
a radiological
awareness
report,94-006, to address
the
issue.
Additionally, on February
1,
1994,
a site'bulletin
was
issued alerting personnel
that
a possible contributor for the
disagreement
was in the way the
MG dosimeter
was worn.
It will
only report
75K of the dose'f the face of the device is toward
the body.
Also, the inspector identified that
DADs would beep while wearing
them but display
no exposure.
This was discussed
with
radiological controls manager.
Apparently
some
DADs were set to
beep at 0. 1 mr/hr instead of
1 mr/hr.
There
was general
confusion
among technicians
and plant workers
as to the purpose of the
beeps.
These
issues
are further discussed
in
health physics
inspection report 94-05
0
0
10
f.
Secondary
Containment Interlocks
As previously discussed
in IR 50-259,260,296/93-45,
a problem had
been
noted with the operation of the secondary
containment
interlocks between
the Unit 1/2 reactor buildings
and the turbine
building which resulted
in monentary violations of secondary
containment.
In response
to this matter,
the licensee initiated
a
design
change to modify the interlocks.
During the inspection
period,
work commenced
in accordance
with DCN W13294 to modify the
Unit 1/2 reactor building to turbine building interlocks.
Current
plans
are that these
new interlocks will be operational
on March
15.
The work on the Unit 3 reactor building to turbine building
interlocks is schedule
to. commence
on March
15 and complete
on
April 21.
The inspectors will continue to monitor the licensees
progress
in this area.
No violations or deviations
were identified in the Operational
Safety
Verification area.
Modifications (37700,
37828)
The inspectors
maintained
cognizance of modification activities.
This
included reviews of scheduling
and work control, routine meetings,
and
observations
of field activities.
Throughout the observation of
modifications being performed in the field gC inspectors
were observed
monitoring and documented verification at work activities.
On February 3,
1994, the inspector
observed modification activities
associated
with the capacitor
bank.
This modification will correct the
existing relaying
scheme
which does not meet
TVA standards,
remove
compacitors that contain
PCB's,
and will increase
the
HVAR capacity
needed to support plant voltage during an accident
when offsite power is
supplied
from the
161
kv system.
Work P'lans
WP0762-93
and 0765-93 were
reviewed with the following discrepancies
noted:
a
~
WP 0762-93
-
The clearance
number
had not been entered
and
documented
as established.
b.
WP0765-93
Housekeeping
inspections
were not documented
as
having been
performed since January
1,
1994.
Modifications and SSS/Unit
ASOS authorizations
had not been obtained prior to commencing work.
Pre-job briefings were not documented
as having
been performed.
Work control group notification'p'rior to
commencement
of work was not documented
as
having been performed.
11
The clearance
number
had not been entered
and
documented
as established.
WTE ID numbers
were entered without work being
performed,
four examples.
Mire terminations
were made with NTE but the
HRTE IDs were not documented,
two examples.
Cable meggering
completed but not signed
by the
craft performing the work.
After it was
identified by the inspector,
the craft signed
and backdated
each
step with the dates it was
performed.
These discrepancies
were brought to the attention of licensee
management
whereupon all capacitor
bank modification wor k was stopped.
Discussions
with the craft performing the modification indicated that they did not
understand
the work plan process
and their responsibilities
associated
with completing that process.
It was determined that this type of
training was never afforded these individuals.
The licen'see
provided
this training to the craft personnel
and following its successful
completion allowed the work to restart.
In addition,
the inspector
noted that neither
TVA nor gC provided
any
direct supervis'ion or quality control measures
for this modification.
A
SWEC field engineer
was responsible
for, coordination of the work
activities.
Although the modification has
been
ongoing for
approximatley
3 months,
these
problems
had only recently
been identified
by the
SWEC engineer
but had not yet been brought to the attention of
licensee
management.
SSP 6. 1, Conduct Of Maintenance,
Step 3.4. 1, states that all personnel
shall
be indoctrinated in the importance of procedural
compliance
and
what steps
should
be taken if the task cannot
be performed
by the
procedure
as written.
Failure to'obtain the required signatures
and
data
as required
by the work plans is
a violation of this requirement
and will be tracked
as
VIO 259,
260, 296/94-01-03,
Failure To Follow
Procedure
on Capacitor
Bank Modifications.
One violation was identified in the modifications area.
Unit 3 Restart Activities
(30702,
37828,
61726,
62703,
71707)
The inspector
reviewed
and observed
the licensee's
activities involved
with the Unit 3 restart.
This included. reviews of procedures,
post-job
activities,
and completed field work; observation of pre-job field work,
in-progress field work,
and gA/gC activities;
attendance
at restart
craft level, progress
meetings,
restart
program meetings,
and management
meetings;
and periodic discussions
with both
TVA and contractor
personnel,
skilled craftsmen,
supervisors,
managers
and executives.
12
During this inspection period the resident
inspectors
commenced
holding
weekly meetings with licensee
management
responsible for the Unit 3
restart effort.
The meetings
were instituted to keep the resident
inspectors
informed of the current Unit 3 status
in regards to schedule
adherence
and major work accomplished.
a
~
System
SPOC's
The purpose of SPOC process
is to provide
a systematic
method for
evaluating
items
and issues
which potentially affect the ability
of Unit 3 systems
and Unit 3 portion of common systems
to perform
as designed.
This process
determines
the status of each
item/issue
and assures
completion of those which affect syst'm
return to operation for Unit 3 restart.
For each. system
evaluated,
the
SPOC process
may be accomplished
in two phases.
Phase
I SPOC addresses
the Restart Test
Program testing milestone
if that milestone exists for the system,
and establishes
system
status
control
by the Operations
department.
Phase II SPOC
addresses
System Return to Operation in preparation for the
declaration of system operability.
Each
phase
ensures
that open
items/issues
which potentially affect the phase
are either
completed,
or reviewed
and satisfactorily dispositioned.
The
process
does not declare
system operability.
Rather, it is used
to support
a declaration of system operability which is made after
other requirements for operability are satisfied (e.g.,
support
systems
available,
performance of Surveillance Instructions,
etc.).
System 027,
Condenser Circulating Water System
During the initial startup of 3C
CCW pump
on November
18,
1993,
smoke
was observed, issuing from the packing stuffing box of the
pump
and
pump vibration was increasing noticeably.
The. licensee
'ecured
the
pump
and
commenced
troubleshooting activities which
included the following:
1.)
The bearing lube water line to the stuffing box and upper
bearing
was observed
to be at
an elevated
temperature
indicating
a lack of lube water flow.
Lube water flow was
verified available to the
pump by installed plant
instrumentation.
2.)
The lube water supply line to the upper bearing
and stuffing
box was disconnected
and
no water flow was present.
However,
a solid stream of water could be seen flowing
through the supply piping to the lower bearings.
3.)'he
vendor,
Ingersoll-Dresser
Pumps,
was contacted to
provide additional
guidance
as they had just refurbished
the
pumps during this outage.
13
4.)
Bearing lube water flow was elevated to the
maximum rate
available to each
pump
and
no back pressure
was obtained
from the lower bearings to force lube water flow to the
upper bearing
and stuffing box.
Divers were brought in and
they inspected
the lube water piping below the
pump deck.
No leakage
or abnormal
conditions were identified.
5.)
At the vendors
recommendation,
3/4 inch orifices were
installed in the lube water supply line just below the tee
of the branch line supplying lube water to the upper bearing
and stuffing box.
This effort was to provide
a flow
restriction to the lower bearings
which would cause
flow to
the upper bearing
and stuffing box.
However, the orifices
did not 'provide adequate
flow to the
pumps at recommended
flow rates
and only marginal flow at the
maximum supply flow
rate avail able.
6.)
The orifices were removed
and further discussions
were held
with the vendor.
The
3C pump was inspected
using
a
to determine if any components
could have
been
omitted during the rebuild.
No deficiencies
were found.
7.)
At the vendors
recommendation orifices were installed in the
lower two lube water lines to the lower bearings
on the
3B
and
3C pumps.
This effort was to provide sufficient
backpressure
in the supply line to force lube water flow to
the upper bearing
and stuffing box.
8.)
Testing after the orifices were installed
showed that flow
rates to the upper bearing
and stuffing box area
were
acceptable
on the
3B and
3C
CCW pumps.
Based --on the successful
testing of the
3B and
3C
CCM pump,
subsequent
to the modification of the two lower lube water supply
lines,
the licensee will also modify the
3A pump.
The inspectors
will continue to monitor this issue during the Unit 3 testing
phase.
Scaffold Program
The inspectors
reviewed the licensee's
scaffold program which
included procedures,
training, inspections,
and records/
documentation.
The procedure that governs
the installation
and
maintenance
of scaffolding is O-TI-264, Scaffolds
and Temporary
Platforms,
Revision 4, dated January
29,
1993.
This procedure
was
reviewed
in-.depth
and the inspectors
considered it a comprehensive
instruction that ensured
was erected
in a reliable
and
safe
manner
and took into account safety-related
functions of
plant equipment.,
The inspectors
also reviewed the maintenance
training program
and training attendance
records for. scaffolding,
HTS 151, Scaffold Erection,
which covered the requirements
of 0-
TI-264.
14
and platforms installed in Unit 3 Turbine
and Reactor
buildings were walked down by the inspectors
and found to meet the
requirements
of 0-TI-264.
The scaffold was constructed
securely
and the appropriate
tags were. installed.
The scaffold permit tag
and log provides
an up-to-date
record of scaffolding installed in
the plant.
This tag also maintains
a record of inspections
conducted
on scaffolding which will remain erected for an extended
period of time.
Step 7. 11. 14 of 0-TI-264 requires
the responsible
foreman/supervisor
or their designee
to inspect scaffolding in use
every 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />
and document the inspection
on the back of the
scaffold permit tag.
While the inspectors
were in the Unit 3
reactor building they observed this inspection in progress.
When
questioned,
the person
conducting the inspection
was knowledgeable
of the procedure
and the requirements
of the inspection.
In
addition, scaffolding located in noncontaminated
portions of the
RCA are required to be surveyed
by
RADCON prior to use
and at
least
every seven
days thereafter.
This is documented
on
a survey
update
tag which is also attached
to the scaffold.
This tag was
also verified to be in place,
where required,
by the inspectors.
0-TI-264 requires that users of scaffolding visually inspect
scaffold prior to use to ensure
the scaffold is safe
and
has
had
the appropriate
inspections/surveys
performed in the required time
frame.
Abnormal or defective conditions
are to be reported to the
erecting
foreman or
RADCON, as required, for any necessary
corrections
or surveys.
In conclusion,
the inspectors
considered
the licensee's
scaffold
program to be comprehensive.
Unit Separation
1.)
Breaker
Found In Off Position
During
a routine tour on-January
24,
1994, the inspector
identified that
an electrical circuit breaker,
labeled
as
required to support
Uni,t 2 operation,
was in the
open
position.
The breaker
was for reactor building lighting
cabinet
LD-3 (compartment
1A) on 250
VDC reactor
NOVBd 3B.
Circuit breakers
such
as this are identified by a sign
as
required
SSP-12.50,
Unit Separation
For Recovery Activities.
This was discussed
with the Unit 3 operator.
Recent
clearances
were reviewed
and
no reason
was found for the,
breaker to be opened
and it was closed.
2.)
Personnel
Access
The inspector noticed that
a gate separating
Unit 2
operating
space
and Unit 3 in the turbine building was
removed
and contractor personnel
with light blue hardhats
were moving freely in and out of Unit 2.
This was discussed
)
1
l
1k
15
with licensee
management.
The inspector will continue to
monitor these activities
as part of the routine activities.
Fire Protection
'a ~
Hissed'FPP
Required Firewatch
On January
20,
1994, the licensee identified that
a Fire
Protection
Impairment Permit (Att. F) for the Unit 1/2
DG C02
system,
was closed out and the required
compensatory
measure
removed before the system
was returned
to operable status.
Hodification,
DCN F26949A,
was being performed
on the fire
detectors
in the
DG building and the
C02 suppression
system
protecting this area
was valved out and placed under clearance
to
prevent inadvertent actuation.
A firewatch was established
as
required,
however,
on January
19,
1994, at 1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br />,
upon
completion of the field work, the firewatch'was released.
On
January
20,
1994,
at 0015 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />, it was identified that the
C02
storage
tank had not been unisolated
and returned to service.
The
FPP,
section 9.3. 11.D.2, requires that
a firewatch be established
within one hour when the Unit 1/2
DG C02 suppression
system is
removed
from service.
Failure to maintain
a firewatch with the
C02 system
removed
from service is
a violation of these
requirements
and is identified as
VIO 259,
260, 296/94-01-04,
Hissed
FPP Required Firewatch.
A similar event occurred
on June
4,
1993,
when
a required firewatch for the Unit 3
DG C02
suppression
system
was relieved prior to the system being
made
and was identified as IFI 296/93-23-04,
Hissed Appendix
R
Firewatch,
and will be closed
by this report.
Corrective Action
for both events will be established
and tracked
by this violation.
b.
In addition,
the licensee identified during its review of this
.
event that although this
DCN had affected primary'rawings,
a
review by the system engineer
had not been performed.
This is
a
requirement of the licensees
DCN program.
The licensee initiated
BFPER940022 to track this event
and to determine corrective action
to prevent recurrence.
Diesel
Driven Fire
Pump
On January
25,
1994, the
DDFP failed to auto start during the
performance of 0-SI-4. 11.B. I.f, Simulated Automatic And Hanual
Actuation Of The High Pressure
Fire
Pump System.
It was
determined that
an engine lock-out relay was preventing the auto
start.
The local control panel
had been replaced
in October,
1993,
per
DCN V24443A with what was identified as
an identical
replacement.
However, following failure of the auto start it was
determined that the lock-out function had
been defeated
on the old
panel without the drawings being updated.
WR C191069
was
generated
to make the appropriate
physical
changes
to disable
the
lock-out function on the
new panel
and
DCN T28513A was written to
16
C.
'd.
revise the drawings.
BFPER940020
was written to determine
the
.
root cause of the event,
including why the failure of the auto
start feature
was not detected
during the
PHT for DCN V24443A.
This item will be identified as
URI 259,
260, 296/94-01-05,
Diesel
Fire
Pump Auto Start Failure,
pending completion of this
PER.
Appendix
R Safe
Shutdown
Concerns with
1D Raw Cooling
Pump
On December
29,
1993, the licensee
determined that
a fault on
cables
associated
with the
1D
RCW pump could prevent the safe
shutdown of Unit 2 following an Appendix
R event.
The
1D
RCW pump
is not required to achieve
safe
shutdown in the event of an
Appendix
R fire, however, it is powered
from 4KV SDBD A which also
supplies
power to components
that are required during
an Appendix
R event.
If a fault were to occur
on one of the cables
associated
with this
pump, it could propagate
to equipment required to
achieve
safe
shutdown or prevent Appendix
R equipment
from
starting.
The licensee
established
the appropriate
compensatory
measures
and initiated BFPER930183 to resolve the issue.
This
. condition is
a violation of 10 CFR 50 Appendix R, Criterion III,
which requires
cables that could -prevent operation or cause
maloperation of systems
necessary
to achieve
and maintain hot
shutdown
be protected
by appropriate fire barriers or by adequate
separation.
This item is identified as
example
one of VIO
260/94-01-06,
Appendix
R Design Errors.
RWCU Isolation Valves Cable Separation
Pump
From the discussion
in paragraph 9.c.,
an Appendix
R design error
was
made concerning the separation
of cables for the
containment isolation valves.
This is identified as the second
example of violation 260/94-01-06,
Appendix
R Design Errors.
Self Assessment
(40500)
a
0
b.
PORC Meeting
On February 3,
1994,
the inspector attended
a
PORC meeting.
Items
discussed
included revisions to SSP-12.53,
Tracking No. 10,
10 CFR 50.59 Evaluations of Changes,
Tests,
and Experiments,
SSP-3.4,
Tracking No.
10, Corrective Action Program,
2-EOIPM TOC Tracking
No.
12,
EOI Program
Manual Table of Contents,
and O-TI-313,
Engineering
Evaluations for Operability Determination.
All'tems
~
reviewed were approved after making additional minor changes.
The
PORC members
in attendance
satisfied the requirements
of TS 6.5. 1
and SSP-12-10.
No discrepancies
were noted
by the inspector.
Shutdown Risk Assessment
On January,
14,
1994, the inspector
attended
a portion of the
licensee's
meeting to discuss
shutdown risk associated
with a
forced outage
maintenance
schedule.
Representatives
from
17
Operations,
Nuclear Engineering,
Technical
Support,
Operations
Scheduling,
and Haintenance
were in attendance.
The group
reviewed'a
schedule
covering the shutdown from 100 percent
power
to cold shutdown
and then back
up to 100 percent
power.
The
schedule
was broken
down into segments
with each
segment
being
examined for any activities that might negatively impact the
operation of the plant.
The review identified several
maintenance
items that were rescheduled,
such
as,
postponing
as
much work as
possible in radiation areas until after the plant is shutdown to
reduce the amount of radiation dose received.
Another item was
rescheduled.
because it would require maintenance activity in the
control
room during power maneuvers.
The inspector thought the
meeting
was productive
and could result in a decrease
in shutdown
risk.
Failure to Hake Required
and 50.73 Notifications
1.)
Standb
Gas Treatment
S stem Ino erabilit
On January
4,
1994, at 6:34 a.m., with Unit 2 operating at
100 percent
power, the 1/2 'A'G was declared
due to
a fuel oil leak at the engine driven fuel oil pump.
At approximately
4: 15 p.m. that
same day, the timing delay
breaker closing relay for the
3D
DG was discovered with a
'ripped
relay target.
Attempts to reset the relay were
made;
however,
they were unsuccessful.
At 7:40 p.m., the
3D
DG was declared
inoperable (effective at 4: 15 p.m.).
Because
the 1/2 'A'G is the emergency
power supply for the
'A'BGT and the
3D
DG is the emergency
power supply for the
'C'BGT,
TS 1.C.2 requires that both trains of SBGT be
declared
and the Unit be placed in at least hot
standby within six hours
and in at least cold shutdown
within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The lic'ensee
entered this
LCO from 4:15 p.m. until 8:25 p.m.
when the
3D
DG was
repaired
and returned to service.
Browns Ferry was designed with a total of three
SBGT trains.
The design basis
accident for each of the units is
a
concurrent with a
LOSP.
In order to mitigate such
an
accident,
FSAR section 5.3.4. 1 states
that two trains of
SBGT are required to auto-start
in order to maintain
secondary
containment
pressure
j; inch water below
atmospheric
pressure.
With the condition described
above,
and the occurrence
of the design basis accident,
only one
train of SBGT ('B') would have auto started.
'(b)(2)(iii)(D) requires that any event or condition that
alone could have prevented
the fulfillment of the safety
function of a system that is needed to mitigate the
consequences
of an accident
be reported to the
NRC within
four hours via the
ENS.
The licensee failed to make this.
notification as well as the followup 30 day written
notification required
18
2.)
Reportability of this matter is further supported
by NUREG-
1022,
(page
15, 5th paragraph)
which states
that for a
safety'ystem
that includes three or more trains,
the
failure of two or more trains should
be reported if, in the
judgement of the licensee,
the functional capability of the
overall
system
was jeoparized.
This matter is a violation
of 10 CFR 50.72
and
and will be cited
as the
first example of VIO 259,
260, 296/94-01-07,
Failure to Make
Required Notifications.
endix
R Concerns
Paragraph
7 of this report references
two instances
where
the licensee identified problems with proper separation
of
power supply cables.
The first matter dealt with power
supply cables to the redundant
isolation valves being located within twenty feet of each
other
and 'not being adequately
protected
by an appropriate
In the second
instance,
the power supply
cables to the
1D
RCW pump were not adequately
separated
from
the safety related
4KV Shutdown
Board A.
These matters
are
being cited
as violations to
Criterion III.G.2.
In each of these
instances,
the Appendix
R requirements
were
never met resulting in a condition outside of the design
basis of the plant.
10 CFR 50.72 (b)(1)(ii)(B) requires
that any event or condition that results in the nuclear
power plant being in a condition outside of its design basis
be reported to the
NRC within one hour via the
ENS.
Additionally, the licensee is required to report these
matters
in accordance
with 10 CFR 50.73 (a)(2)(ii)(B).
In
both instances,
the licensee failed to make the required
telephonic
and written notifications required
by these
parts.
These matters
are violations af 10 CFR 50.72
and
and will be cited as the second
and third
example of VIO 259,
260, 296/94-01-07,
Failure to Make
Required Notifications.
In both of these
instances
the licensee
conducted
a review of the
events for reportability using
but 'concluded *the
events
were not reportable.
Action on Previous
Inspection
Findings
(92701,
92702)
a
~
(CLOSED) VIO 259,
260, 296/92-29-02,
Failure to Sign Out
a Hold
Order Prior to Performing Work
This issue occurred
due to contractor
problems using the clearance
procedure.
The licensee
conducted
an incident investigation II-B-
92-052,
concerning the problems.
Additional training was
conducted for personnel
holding clearance
authorization.
This
e
b.
C.
19
included
a practical exercise,
requalification examination,
and
was
made part of the annual requalification for these
people.
Additionally, the licensee
implemented
a modification performance
monitoring program that checks
clearances
in the field.
The
inspector
reviewed the -licensee's
closure
package for this item.
During routine tours of the facility additional
problems
have not
been identified in this area.
{CLOSED) IFI 296/93-23-04,
Hissed Appendix
R Firewatch
On June 4,
1993,
an hourly roving firewatch, required
because
the
Unit 3
DG building C02 system
was out of- service,
was relieved
before, the
C02 system
was
made operable.
On June
5,
1993, this
was recognized
and the firewatch was re-established.
Problem
Evaluation Report
BFPER930082
was initiated to track this event.
As stated
in paragraph
7.a,
on January
20,
1994,
a similar event
occured
when the firewatch was relieved from monitoring the Unit
1/2
DG C02 tank before it was
made operable.
Therefore, this item
is being closed out.
Corrective actions will be tracked
by VIO
259/260-94-01-04.
(CLOSED)
URI 260/93-39-01,
Inadequate
Safe
Shutdown
Procedure
Revision
This item was that the licensee
made
112 changes
to the fire
protection safe
shutdown
equipment
compensatory
measures.
Characteristic of the changes
was revising
a requirement to
isolate the
RWCU system in four hours for inoperable
containment
isolation valves'o permit the establishment
of a fire watch after
seven
days.
The licensee
requested
a meeting concerning this
issue.
A meeting
was held on January
27,
1994, to discuss
the
changes.
The question
about
RWCU isolation valves
arose
due to
erroneous
cable reporting information to perform an Appendix
R
analysis.
Later it was determined that cables for both isolation
valves were routed in the. same fire zone.
From the meeting it was determined that the problem with the
isolation valves
was
a design
problem dealing with inadequate
separation.
Thus, section 9.3. 11.6, of the fire protection plan
fire-rated assemblies
was applicable
and required
a fire watch in
one hour.
The problem should not have
been
addressed
by the
appendix
R safe
shutdown
program compensatory
measures
table.
Furthermore,
the changes
made to the compensatory
measures
table
were consistent with other compensatory
measures
dealing with a
loss of an appendix
R function or equipment.
For example,
removal
of a
DG for maintenance
allows
7 days before
a fire watch is
required.
In this case
a loss of an app'endix
R capability would
require
a fire watch, but inoperable
valves must
be isolated in
four hours.
20
I
Although some confusion existed
as to the applicable table for
this analysis
problem, the changes
made to the plan were
consistent
with other changes
previously approved
by the
NRC.
Many of the changes
were containment isolation valves similar to
the
RWCU system
changes.
Accordingly, no violation occurred with
the plan revision
and this
URI is closed.
10.
Exit Interview {30703)
The inspection
scope
and findings were summarized
on February
18, )994,
with those
persons
indicated in paragraph
1 above.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection
findings .listed below.
The licensee
did not identify as proprietary
any
of the material
provided to or reviewed
by the inspectors
during this
inspection.
Dissenting
comments
were not received
from the licensee.
Item Number
Descri tion and Reference
259,
260,
296/94-01-01
260/94-01-02
259,
260, 296/94-01-03
259,
260, 296/94-01-04
259,
260,
296/94-01-05
260/94-01-06
NCV, Inadequate
Second
Party Check,
paragraph
2.
VIO, Failure to Properly Perform
Containment Visual Inspection
Surveillance,'aragraph
2.
VIO, Failure to Follow Procedure
on
Capacitor
Bank Modifications, paragraph
5.
VIO, Hissed Firewatch,
paragraph
7.
URI,
DG Fire
Pump Auto Start Failure,
paragraph
7.
VIO, Appendix
R Design Errors,
paragraph
7.
259,
260,
296/94-01-07
VIO, Failure to Make Required
Notifications, paragraph
S.
Licensee
management
was informed that
1 IFI,
1 URI, and
1 VIO, were
closed.
11.
and Initialisms
AOI
ASOS
ATU
CFR
CO
DA)
Abnormal Operating Instruction
Assistant Shift Operations
Supervisor
'nalog
Trip Unit
Condenser
Circulating Water
Code of Federal
Regulations
Carbon Dioxide
Digital Alarming Dosimeters
I
DCN
.DDFP
II
IR
LCO
LER
METE
HVAR
NRC
PCB
PDD
PER
PS
RCW
SDBD
SOS
~
TS
WP
. Design
Change Notice
Diesel Driven Fire
Pump
Diesel
Generator
Emergency
Core Cooling Sustem
Emergency
Equipment Cooling Water
Emergency Notification System
Fire Protection
Plan
Final Safety Analysis Report
Incident Investigation
Inspection
Report
In Vessel
Visual Inspection
Limiting Condition for Operation
Licensee
Event Report
Loss of Coolant Accident
Loss of Offsite,Power
Measuring
and Test Equipment
Megvar
Nuclear Regulatory
Commission
Poly Chlorinated Biplanyl
Plant Drawing Deficiency
Problem Evaluation Report
Post Modification Test
Plant Operation
Review Committee
Pressure
Switch
Quality Assurance
Quality Control
Reactor
Core Isolation Cooling
Raw Cooling Water
Residual
Heat
Removal
Residual
Heat
Removal Service
Water
Reactor
Water
Cleanup
System
Standby
Gas Treatment
System
Shutdown
Board
Surveillance Instruction
Shift Operations
Supervisor
System Preoperability Checklist
Site Standard
Practice
Shift Support Supervisor
Thermo Luminescent
Dosimeter
Technical Specifications
Valley Authority
Unresolved
Item
Ultrasonic Test
Violation
Work Order
Work Plan
Work Request