ML18033A992
| ML18033A992 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 10/02/1989 |
| From: | Carpenter D, Little W, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18033A989 | List: |
| References | |
| 50-259-89-38, 50-260-89-38, 50-296-89-38, NUDOCS 8910200123 | |
| Download: ML18033A992 (35) | |
See also: IR 05000259/1989038
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-259/89-38,
50-260/89-38,
and 50-296/89-38
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 1, 2, and
3
Inspection
Conducted:
August 16 - September
15,
1989
Inspector
R.
r
nt
,
S
e
anager
Dat
ned
tt
n,
RC Restart
oor snator
Accompanied by:
E. Christnot,
Resident
Inspector
M. Bearden,
Resident Inspector
.
K. Ivey, Resident
Inspector
B.
o
,
oj
En
neer
Approved by:
N. S. Li t
, Sect
on Chief
Inspection
rograms
TVA Projects Division
Da
Date Si
e
gned
SUMMARY
Scope:
This. routine resident inspection
included surveillance observation,.
maintenance
observation,
operational
safety verification, control of licensed
operator
status,
restart
test
program,
modifications,
and
site
management
and
organization.
Results:.
One violation was identified for failure to conduct adequate
PMT,. paragraph
3.
These
examples.
along, with the
PMT problems. identified. in IR 89-27. indicate a
~
~
~
~
~
weakness,
irr PMT.
Considering'he
volume of world activities at the site,.
adequate-
PMT is. an essential
part of the. recovery: effort..
Although: PMTs are.
designated
in MRs, examples
have
been
found where. there
was
no method to ensure
that
PMTs are complete prior to returning. equipment to service.
3910200123
391002
ADOCK 0 000259
0
Housekeeping
and identification of material deficiencies
needs
improvement in
the plant areas
not frequently traveled
(Paragraph
4.).
An unresolved
item
is identified in Paragraph
6 concerning
a
long standing
issue
over the
disposition of Restart Test
Progrgam
TEs.
An unresolved
item concerning
the
control of composite
crews
was identified in paragraph
8.
In the area of site
management
the Technical
Support Superintendent,
Outage
Manager,
and Assistant
Outage
Manager
have all resigned.
The licensee
had
adequate
notice of the
resignations
and is seeking replacements.
A non-cited violation concerning
a failure to conduct
a
JTG meeting
in
accordance
with procedures
was identified in paragraph
6.
REPORT
DETAILS
Persons
Contacted
Licensee
Employees:
- 0. Zeringue, Site Director
G. Campbell, Plant Manager
- R. Smith, Project Engineer
"J. Hutton, Operations
Superintendent
<<A. Sorrell, Maintenance
Superintendent
D. Mims, Technical
Services
Supervisor
G. Turner, Site guality Assurance
Manager
- P. Carier, Site Licensing Manager
- P. Salas,
Acting Compliance Supervisor
J. Corey, Site Radiological
Control Superintendent
R. Tuttle, Site Security Manager
Other
licensee
employees
or
contractors
contacted
included
licensed
reactor operators,
auxiliary operators,. craftsmen,
technicians,
and public
safety officers; and quality assurance,
design,
and engineering
personnel.
NRC'mployees
- D. Carpenter,
Site Manager
- C. Patterson;
Restart Coordinator
- E. Christnot, Resident Inspector
<<M. Bear den, Resident Inspector
<<K. Ivey, Resident
Inspector
B. Long, Project Engineer
- Attended exit intervie~
Acronyms used, throughout this report are listed in the last paragraph.
Surveillance Observation
(61726)
The inspectors
observed
and/or reviewed the SI procedures
discussed
below.
The inspections
consisted
of a review of the SIs for technical
adequacy
and
conformance
to
TS, verification of test
instrument calibration,
observation
of the conduct of the test,
confirmation of proper
removal
from service
and return to service of the system,
and
a review of the test
data.
The inspector also verified that limiting conditions for operation
were met, testing
was
accomplished
by qualified personnel,
and the
were completed at the required frequency.
a.
On; August, 15
1989;. the licensee- ran
a TS required'I
O'-SI-4'.2.8-67'
"RHR Service- Mater Initiation: Logic,." to verify proper operation of
the initiation logic for the
EECW/RHRSW pumps.
Subsequent
licensee
review identified that this SI inhibited the automatic start of all
EEL pumps
which is required
by the safety analysis.
The
EECM pumps
are required
to supply cooling water to the
upon
automatic
aebxation of the
DGs.
Failure to maintain the automatic
pump start
Ametion
made
the
EECM
pumps
and all eight
On
August 24,
1989,
at 7:07 p.m.
(CDT), the
licensee
made
a 4-hour
ace-emergency
ENS report to the
NRC Duty Officer concerning this
event.
This will be followed up by the
NRC in a special
inspection
esmcerning SI's (IR 89-43).
b.
Bemng this reporting period, the licensee verified the control
rod
d'~ice integrity.
This activity involved the
use of
a
general
procedure,
a technical instruction
and
two surveillance instructions
as follows:
2-GOI-100-3
TI-20
2-SI -4.3.B.1. b
Refueling Operations
Control
Rod Drive System Testing
Control
Coupl ing
Integrity
Check
After
Refueling
or Maintenance
0
2-SI-4.10.B
Demonstration
of 'Source
Range'onitoring
System Operability During Core Alterations.
7hz 2-SI-4.3.B.1;b procedure
performe'd'y
the licensee fulfilled the
surveillance requirement to observe that the drive does
not go to the
evertravel
position
when the control
rods
are fully withdrawn the
First time after
each refueling outage
or after maintenance.
The
P-SE-4.10.B
procedure fulfilled the surveillance
requirement that the
SR'hall
be functionally tested
and
checked for neutron
response
prior to making any alterations
to the core.
The licensee
withdrew
arrd inserted
each
control
rod one at
a time during this activity.
%he inspector
observed
the operation
of the control
rods
and the
associated
control
room activity.
No deficiencies
were identified.
c.
%are
inspector
observed
a
scheduled
performance
of
procedure
2-SI-4.4.A.1,
Pump Functional Test.
This SI
$s performed
on
a quarterly frequency to determine
the operability of
the
SLC pumps
and includes
taking suction from the
SLC test tank
and
rezoning
the
pumps.
No deficiencies
were identified during the
performance of this SI.
3.
Naim@avance
Observation
(62703)
Pled
maintenance
activities of selected
safety
related
systems
and
camperreats
were observed/reviewed,
to ascertain if they were conducted. in
acceptance
with. requirements.
The: following'tems were" considered.
during.'his
renew:
the limiting; conditions for operations
were met,. activities
were accomplished-
using
approved
procedures,,
functional testing and/or
calibrations
were performed prior to returning
components
or systems
to
service,
quality control
records
were
maintained,
activities
were
accomplished
by qualified
personnel,
parts
and
materials
used
were
properly certified, proper tagout clearance
procedures
were
adhered to,
Technical
Specification
adherence,
and
radiological
controls
were
implemented
as required.
Maintenance
requests
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/reviewed
the
below listed
maintenance
activities
during this
report period:
a.
Failure to Perform Post Maintenance
Testing
On
August
28,
1989,
the
licensee
identified that
was
not
completed for work performed
on the
"3C"
DG.
The
was
taken
out-of-service
on August 2,
1989, for the
performance
of scheduled
maintenance activities.
MR A-893300
was performed
on August 4, 1989,
to calibrate
the
ASLR; however,
the
PNT identified on the
NR was not
completed
following the work.
The
DG was returned
to service
on
August 10,
1989.
Failure to perform the
PMT was
brought to the
attention of the
SOS
on August 28, 1989.
The licensee
then completed
the
and closed
out the
MR.
The
ASLR functions to keep the
from starting
on
an automatic signal if the operator
has
stopped
the
DG, from running
by using the. emergen'cp fast stop pushbutton
or the
normal operating
handswitch
while an accident
signal is locked in.
Failure of the
ASLR in any
mode
would not inhibit the
DG from
starting
on receipt of an accident signal without operator action.
Other examples
of safety related
equipment
being returned to service
following maintenance
prior to completion of required
PMT occurred
when
the
"D2"
and
"D3"
pumps
were
declared
on
August 16,
and
September
1,
1989 respectively.
In both
cases
the
errors
were not discovered until final review of the
MRs, at that
time the
were
accomplished.
Subsequent
licensee
evaluation
determined
that
the
work was
associated
with non safety
related
components
(alarm
relays)
and
had
not directly
impacted
the
operability of the
RHRSW pumps.
Technical
Specifications
and administrative
procedures
require that
written procedures
be implemented
covering testing of safety related
equipment.
PMI 6.2,
"Conduct of Maintenance,"
requires that
PMT be
performed following corrective
maintenance
activities
and
SDSP 6.7,
"Post Maintenance
Test
Program,"
establishes
the
program to ensure
that
PNT is performed.
The failure to perform required
PMT following
maintenance
activities
is- a. violation of TS 6.8.1.1.c for failure to
implement procedures.
(VIO 259,. 260 296/89-38-01,. Failure to: Conduct
PNT)..
This'icensee
identified" viol'ation is, being: cited'ecause.
of
a'imilar
violation concerning
PMT in IR'9-27.
These
examples
indicate
a
weakness
in the control of
PMT.
Although
PMTs are
designated
on
MRs,
no checks
were performed to insure that the
were completed prior to returning equipment to service.
b.
Flow Test of "2C"
RHR Room Cooler
This test
was
performed
under
a
new technical
instruction
and
821382
on September
14,
1989.
The flow was determined
to be 10,325
cubic feet per minute which was within the acceptance
criteria of
10,000
a
10%.
No deficiencies
were identified.
4.
Operational
Safety Verification (71707)
The inspectors
were
kept informed of 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;
onsite
and offsite
emergency
power
sources
available
for
automatic
operation;
purpose of temporary tags
on equipment controls
and
switches;
alarm status;
adherence
to procedures;
adherence
to
limiting conditions
for
operations;
nucl.ear
instrument
operability;
temporary alterations
in effect;. da~ily 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
positions
and
system
alignment,
and
hanger
conditions,
containment
isolation
alignments,
instrument
readings,
housekeeping,
proper
power supply
and breaker
alignments,
radiation
area
controls,
tag controls
on equipment,
wor k activities
in progress,
and
radiation
protection
controls.
Informal
discussions
were
held with
selected
plant personnel
in their functional areas
during these tours.
a ~
Unit Status
All three units
remained
in an extended
outage
as part of the
8FNP
recovery
plan.
Units
1
and
3 are
defueled
with Unit 2 in cold
shutdown
with fuel
loaded.
Work activities
continued
toward the
restart of Unit 2 in 1990.
The licensee
has identified
a series of
milestones
for returning
groups of systems
to service for restart.
The first milestone,
Condenser
Vacuum
Systems,
was
achieved
on
September
1,
1989 with the exception of some
items.
These
items
dealt mainly with the- closure of engineering
paperwork.
No worlc.
activities have
begun
on Units
1 and 3.
b.
c ~
RPS Circuit Protectors
On August 26, 1989, at 12:17 p.m.
(CDT), Unit 1 received
an automatic
ESF actuation
when
bus
1B was deenergized.
Unit
1 received
a
half-scram;
PCIS groups
2, 3, 6, and 8 isolations;
SBGT trains A, B,
and
C starts;
and actuation of CREV trains
A and
B.
Investigation
into the event revealed that
RPS circuit protectors
1B1 and
1B2 were
tripped.
The licensee identified the cause of the trip to be
set voltage fluctuations
which resulted
in the circuit protectors
sensing
overvoltage
and tripping.
Recurring
problems with circuit
protector trips are
being followed up by the
NRC during reviews of
the
LERs submitted
on the separate
events.
(See
IR 89-40 paragraph
2.g)
Electrical
System
Walkdowns
During this reporting period,
the inspector
walked
down two of the
site electrical
systems.
One system,
the offsite power system,
is
non-safety related
and the other system,
the plant
DC system is both
non-safety related
and safety related.
The purpose of the walkdown
was to verify the as-built equipment status of both systems
in order
to have
a better understanding
of both systems
in case of a station
blackout.
The following drawings
were utilized..for the offsite power
system
walkdown:
45N500
0-15E500-1
3-15E500-3
Switchyard Wiring Diagram Single Line
Units
1 and 2,
Key Diagram of Normal
and Standby
Auxiliary System
Unit 3,
Key Diagram of Normal
and Standby Auxiliary
Power System.
The offsite power system at the
BFN facility consists
of three main
transformers,
500
KV to 20.7
KV, and
two
common station
service
transformers,
161
KV to 4.16
KV.
The site
has
seven
500
KV feeder
lines
and two 161
KV feeder lines.
During plant operations,
the 20.7
KY sides of the three main transformers
are fed from the Units
1 thru
3 generators,
with
a direct tie to
a total of six unit service
transformers,
20.7
KV to 4.16
KV, two UST per main transformer.
The
most significant equipment
arrangement
for the
BFN offsite
power
system is that
each unit generator
has
an output breaker
located
between
the generator
and the respective
mai.n transformer.
With this
type of arrangement
during
a reactor
the output breaker for
the turbine trips. open
and the main transformer
back feeds
from the
500
KY grid system
to the unit transformers.
Consequently,
the
electrical'ystem
has. a bumpless transfer..
0
0
The following drawings
were utilized for the
power
systems
walkdown:
0-45E701-2,
Battery Boards 1,2,3 and 4
0-45E702-1,
45-E702-2
0-45E702-3,
45-E703-1
0-45E703-2,
45-E704
1-45E705,
2-45E706
3-45E707
Turbine'uilding 250 Volt Distribution
0-45E709-1,
3-45E709-2
Shutdown
Boards
250 Volt Batteries
and
Chargers
0-45E786-9,
0-45E786-10
120 Volt DG Batteries
and Chargers
3-45E786-17,
3-45E786-18
The
DC power
system at the
BFN facility consists of six subsystems:
the four 250 volt unit boards with batteries
and chargers;
the three
250 volt Turbine Building Distribution, which receive
power from the
unit boards;
the
250 volt shutdown
boards
control
power system with
batteries
and chargers;
the
120 volt
DG panels
with batteries
and
char gers;
the
two
48 volt annunciator
distribution
systems
with
batteries
and chargers;
and the three
+24 volt -24 volt
DC system
with batteries
and
chargers.
.
The .most significant
equipment
arrangement for the
DC systems
is the versatility of the
250 volt
sections
of the four unit battery boards.
This system
can
be lined
up to feed
normal
and alternate
power to
a variety of systems,
including
DC motors which can provide power to the unit preferred
NG
sets for IKC AC power,
MOVs for the
and to air compressors
in
the
DG starting air systems.
No deficiencies
were identified during
the walkdown.
d.
RHRSW Cable Tray Tunnel
Walkdown
On August 19,
1989,
two
NRC inspectors
toured the
RHRSW Cable Tray
Tunnel.
This tunnel
runs
from the intake structure
underground
to
the turbine building.
The cable trays hold one division of the
pump cables.
RHRSW provides
cooling water from the ultimate heat
sink at
BFNP.
From the
number of deficiencies
identified,
in
general,
the tunnel
area cleanliness
and housekeeping
were considered
unsatisfactory.
The following items were identified:
There were num>rous burnt out light bulbs which required the use
of a flashlight in portions of the tunnel.
None of the bulbs
had protective
guards.
The light bulbs are near
a persons
head
in height
and
some
areas of the tunnel
contained
two to three
inches of water on: the floor..
Water was found in several
cable trays near
an area
where seven
three inch conduit outlets enter the tunnel.
Water was dripping
out of the outlets;
and
a splash
pan
was
inadequate
to prevent
standing water in several
cable trays.
Examples
were found where cables
changed
from one cable tray to
another tray,
and
cables
were found hanging
underneath
cable
trays suspended
by wire ties.
Water in-leakage
was observed at several
grouted
areas
between
sections of the tunnel.
The last
monthly
check
of
two
permanently
mounted fire
extinguishers,
T2 and T3, was performed in May 1989.
guestionable
splicing of several
cables
located in the trays
was
identified.
A junction box or splicing
box was located in the
cable tray, not seismically supported.
There
were several
loose wires, wires cut,
and
abandoned
wires
without any identification.
Several
examples
were clustered at
location 72C4.
Miscellaneous
trash
was identified in several
trays.
A fire hose, of questionable
nature
and material condition,
was
running along the floor of the tunnel in the water.
In the area of the tunnel
near the turbine building entrance
an
open junction box without a cover was observed
in the overhead.
There
was
a
maze of wires dangling outside
and
between
cable
trays at the turbine building entrance.
The magnitude of these
deficiencies
was
discussed
with the Plant
Manager
on August 19,
1989.
The inspector took the Plant Manager
and
members
of his staff
on
a tour of the
area
on August 24,
1989.
During this tour, the inspector observed that steps
had been
taken to
remove the standing water on the floor, improve lighting, update fire
extinguisher inspections,.
and general
housekeeping.
Drywell Walkdown
On August 18,
1989,
two
NRC inspectors
inspected
the Unit 2 drywell.
The general
condition of the drywell was what would be anticipated
for
a unit in
an
outage.
There
was
evidence
of ongoing
work
activities
by the scaffolding,
temporary
power cords,
and rigging
equipment.
A~ few. minor items of concern: were observed..
The upper walkways
had fire extinguishers
standing
up without
being, tied off or being, laid. on their side.
The monthly fire extinguisher
check for fire extinguisher
812
was last performed in June,
1989.
Several yellow hard hats
were abandoned
on the top walkway.
The
licensee
had recently initiated
a program that requires
hard
hats to be used in contaminated
areas.
Personnel
exchange their
hard hat for a yellow one at the area entrance
and are
supposed
to bring the yellow hard hat to the area exit.
Various
sections
of loose
thermal
insulation lying outboard
against the drywell wall.
A light bulb was not covered
by a protective cover similar to
other bulbs in the area.
This was near penetration
2-X-26.
Most of the ventilation outlets
had loose or damaged directional
vanes to direct the air flow.
Other deficiencies
were identified by plant tags
as
problems.
The
plant health
physics staff was
most helpful
and interested
in any
health physics
concerns identified by the inspectors.
The results of
the drywell tour were discussed
with the Plant Manager following the
tour.
f..
Radwaste, Building Walkdown
On September
1,
1989, the inspector toured the radwaste
building due
to
a recent
problem at another facility concerning
routine flooding
of a room containing
55 gallon storage
drums.
Based
on discussions
with a radwaste
supervisor,
no rooms are routinely flooded and there
have
been
no flooding problems in the radwaste building.
Some
are
located
below
ground
level
but are
designed
as
In
general,
housekeeping
in the radwaste building was good.
g.
Control
Room Tour
On
September
7,
1989,
the
NRC inspector
noted
several
items of
concern
during
a tour of the Unit 2 control
room.
These
items were
discussed
with the operations
manager
following the tour
and are
listed below:
The drywell floor drain
sump level
abnormal
was
illuminated because
of an equipment
problem but no maintenance
request
had
been written to correct the problem.
.This alarm
indicates
a
high or low level
in
the* sump
and the actual
condition must
be verified by
a local
in the reactor
building
The operator stated, the alarm. occurs. after the
pump stops, pumping: and: the. level. was. actually lower=
Area
Radiation
Chart
Recorder,
2-RR-90-1,
was
recording
meaningless
information.
The chart
has
a rotating wheel
which
is supposed
to print the
number of the monitor points which is
being recorded.
No numbers
were being printed and only red dots
recorded.
Several
other recorders
with the
same
problem were
2-TR-56-2Y, 2-TR-85-7A, 2-TR-85-7B, 2-TR-85-7C,
and 2-TR-56-3.
Deficiency tags
were
on emergency
equipment.
For example,
an
emergency
battery
powered
lantern
contained
a deficiency tag
dated
6/12/89
stating
that there
was
corrosion
inside
the
lantern.
An emergency
stretcher
cabinet
had three deficiency
tags
hung on it.
The condenser
vacuum
on the main control panel 9-7 was in
units of absolute
pressure
which was inconsistent with the plant
response
procedure
2PA-47-125 which was in inches of
vacuum.
Plant operators
expressed
a concern
regarding
the modification
elevating
the
SOS work station in the control
room.
The work
station
was
being partitioned off with office partitions. which
were not transparent.
From the reactor operators
desk,
these
partitions restricted 'their view of some panels.
These
concerns
were discussed
with the operations
manager following
the tour.
h.
Seals
An inspector
toured
selected
areas
of the plant to observe
the
condition of the fire barrier penetrations,
and requested
to review
the
gC inspection
records for the fire seals
on the wall between
the
Unit 1/Unit 2 reactor
and turbine buildings, near the turnstiles, at
the 565'levation.
The records
were not provided
by the licensee
prior to the
end of the inspections.
Demonstration
by the licensee
that
the
selected
had
been
properly
installed
and
adequately
inspected
by
gC
was identified
as
IFI
89-38-02,
Proper Installation of Fire Seals.
In conclusion,
based
on recent plant tours of the
SBGT room (IR 89-33)
and
cable. tray tunnel,
housekeeping
and identification of material
deficiencies
in areas
not frequently traveled
needs
improvement.
Plant
management
has
been
responsive
to these
concerns
as
observed
by cleanup
crews
in other
areas
such
as
the
condensate
storage
tank pipe gallery
tunnel
and ventilation towers.
General
plant tours
and the tour of the
drywell indicate housekeeping
efforts have
been satisfactory in frequently
traveled areas.
No violation or deviations. were- identified.
10
Control of Licensed Operator
Status
(41701,
71707)
An inspector
reviewed the licensee's
program for control of assignment
of
licensed operators
to Unit 2 control
room duties.
Specifically the review
was conducted
to determine if licensee
controls
were adequate
to prevent
non-licensed
or non-qualified
licensed
operators
from willfully or
inadvertently assuming responsibility for licensed operator watch stations
at
Browns Ferry.
This review resulted
from a recent
event at another
facility where
a
licensed
operator
who
had failed his
most recent
requalification examination
had
assumed
the watch in the control
room as
the operator-at-the-controls.
This event
had
gone undetected
by onshift
management
for approximately
three
hours
due to the lack of current
information in the control
room
and failure to aggressively
implement
existing procedures.
The inspector
held discussions
with
NRC Region II Operator
Licensing
Section
personnel,
TVA Operations
and Training Management
personnel,
and
TVA Operations shift personnel.
Control
room logs
and operations shift
schedules
for the months of July and August 1989 were reviewed along with
lists of qualified licensed
operators
provided both
by
NRC Region II and
TVA's training
department.
The inspector
noted that
the applicable
procedural
requirements
were
contained
in Plant
Manager
Instruction
(PMI) - 12.12,
Conduct
of Operations.
PMI-12.12,
Section
4.6.2.1,
requires
that all
off-going operators
shall
not relinqui sh their
responsibilities
until satisfied. that the. oncoming
operator
is fully
qualified. and/or licensed
to assume
the shift position.
Section 4'.5.12,
requires
that the
oncoming
SOS
make shift assignments
to implement the
weekly shift schedule.
The
program is further
implemented
through
established
policies
and practices
rather than documented
procedures.
The inspector visited the control
room on two backshifts
and requested
the
SOS
demonstrate
the ability to determine
up-to-the-minute
status
of
selected
licensed
personnel.
In both cases
this
was accomplished
by use
of the published weekly shift schedule
which was annotated with codes for
those respective
personnel
that either were not qualified or restricted
in
the
performance
of licensed
duties.
The inspector
noted= that
as part of
the shift relief each
oncoming
SOS reviews the qualifications of oncoming
personnel
at the beginning of the shift and
makes
an operating
log entry
of the
number of available
and
RO licensed
individuals present that
will be part of the relieving crew.
The inspector
reviewed the above
two lists of qualified licensed
operators
and compared that information to the information contained
on the current
weekly operations shift schedule.
The names of 10 licenced operations
and
training, personnel
that the inspector determined
were not qualified due to
recent
exam failures or were otherwise restricted
from licenced duties
were compared
to, the Unit 2 operating
logs. for July and August,, 1989.
No
probTems'ere
identified': during, that. review.
The inspector
noted. that
each
of. these
10; individuals
was. properly reflected. on the current weekly
schedule
as not being qualified.
0
11
Primary responsibility for notification of on-shift
management
of
a
disqualifying event
associated
with
a particular individual appears
to
depend
on the
nature
of the
event.
For example,
for failure of a
requalification
exam,
the training section is responsible for grading the
exam
and direct notification of personnel
assigned
to the training
department,
while the Operations
Supervisor
must notify personnel
in his
section.
For
personnel
assigned
to the
operations
sections,
the
operations
supervisor is notified via telephone
by the Training Section
Supervisor.
Requalification
exams
are normally given
on Fridays of each
cycle training week with the
exams
graded
no later than Tuesday of the
following week.
The Operations
Supervisor is responsible for tracking the active status of
all licensed
personnel.
At Browns Ferry, active status
is maintained
by
working a minimum of seven
8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts or five 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts performing
licensed
duties
per calendar
quarter.
In the
case of requalification
failure or loss of active status,
the operations
supervisor is responsible
for notifying on-shift management
(SOS) that
a particular person
can
no
longer
be
used for licensed
duties.
The notification is to
be
made
immediately
following determination.
This
system
results
in verbal
notification of on-shift management
within the
same
workday with written
notification by way of the following weekly shift schedule
which would
include an update of that individual's status.
The inspector determined that although several
licensed operators
recently
failed, requalification
examinations
there
has
not
been
a significant
impact
on the ability of the licensee
to properly man operating shifts in
the present
mode (shutdown/refuel)
without the use of excessive
overtime.
For* example,
in the present
mode only
1
SRO and
3
RO licenced
personnel
are required
to meet technical
specification
requirements.
There
are
normally at least
2
and
5
on each shift.
There could exist
a
shortage
of licensed
operators,
particularly
SROs with active status,
to
support Unit 2 startup.
Out of 36 licenced
on site only 13 are
maintaining current active status.
The inspector
noted that the licensee's
program appeared
adequate
not only
for providing on-shift management
with current information covering requal
exam failures but also reflects other information useful for the
purpose
of making decisions
concerning
the proper manning of the shift crews.
The
weekly schedule
also contains
information about medical restrictions
and
expired active status.
Additional information is included which provides
the qualification levels of non-licensed
operators
and yearly cumulative
overtime totals for each individual.
No violations or deviations
were
identified.
Restart Test Program
(99030B)
The. inspector. maintained'ognizance
of. ongoing, restart test acti.vities
ant monitored particular activities in detail
as appropriate.
Specific
inspection observations
are discussed
below:
12
a.
RTP Test Exceptions
The
generates
test
exceptions
whenever
difficulties
are
encountered
during the conduct of a restart test.
This activity is
governed
by
SDSP
12.1,
Restart
Test
Program,
Section
6.6,
Test
Exceptions.
The following is stated
in section 6.6.1 of SDSP 12.1:
Test
Exceptions
shall
be
documented
on
a
Test
Exception
Form
(SDSP-94),
inserted
into the test
package,
and
be
indexed
on
Appendix B.
TEs may consist of any of the following items:
(1)
Unexpected
or unusual
data
(2)
Procedural difficulties (not to be used in lieu of change)
(3)
Data outside acceptance
criteria
4)
Damage
or failure
of plant
structures,
systems,
and/or
components
(5)
Operates
in a suspected
adverse
manner
(6)
Inability to signoff a step,
but will be signed off as written
later
(7)
Partial release
by JTG.
Volume 3,
BFN Nuclear Performance
Plan, section 4.6.2.2,
Implementation,
subsection
(3)(a) states:
The
RTP is not
a stand
alone activity.
The licensee
has
been
reluctant to issue
and
process
a condition adverse
to quality
report
(CARR) for TEs that clearly should require
such reports
under
TVA's CA( program.
The tendency
has
been
to identify
problems
and fix them
by investigation,
analysis,
evaluation,
and
sometimes,
resolution of problems identified in the
RTP,
solely under the
TE activity.
This action is not consistent
with the
CA( program that should
cover all plant activities
affecting quality.
These
concerns
have
been
discussed
with
Browns
Ferry managers.
TVA has
stated
that it will provide
CA(Rs in parallel with TEs where conditions warrant
them.
The
NRC staff will continue to monitor this activity.
Under the
Browns Ferry
RTP, it is possible
to satisfactorily
close
out
a test without closing all
TEs against that test.
Those
TEs should
be classified
by their significance
and tracked
on the
SNPL.
However,
the overall
program to provide for the-
appropriate identification, tracking, resolution,
and closure of
the significant
TEs identified in the
RTP should
include the
CA(R.
The
NRC inspector
monitoring the
RTP reviewed
TEs, both
opened
and
closed,, identified during the performance of four RTP procedures.
13
b.
Specific
RTP Test Exceptions
Review
The inspector
reviewed
a total of 84
TEs identified during the
performance of four RTP test procedures
as follows:
(1)
2-BFN-RTP-031A,
Control
Bay
Heating
Ventilating
and
Air
Conditioning System.
The
RTP test
group documented
a total of
ten
as
a result of the performance of this procedure.
The
inspector
noted that TE-08
was left as
an
open
TE due to the
fact that
EMI 60,
Inspection
and Preventative
Maintenance
of
Control
Bay Chillers,
had not been
completed
by the time the
procedure
was
reviewed for closure.
The closure of TE-08 is
dependent
on completing
EMI 60,
which in turn requires
the
completion of
DCN
W0156,
replacement
of temperature
control
valve 0-TCV-67-62.
TE-07, which documented
the fact that the
Unit
1 and
2 Control
Bay chill water
pumps
and the air handling
unit chilled water flows failed to meet acceptance
criteria,
was
reviewed
and
the inspector
noted that this significant test
exception did not result in the generation of a CA(R.
Further
review of the
completed
procedure
indicated
that
TE-07
was
reviewed
by the
RTP group using criteria established
in
SDSP
" 3.13,
Corrective
Actions.
However,
section
6.6,
CARR
Determination,
subsection
D states:
Test deficiencies
which,
by evaluation,
indicate that the
item does. not comply with the license design
basis
or will
affect plant technical
specifications
shall
be placed
on
a
CARR if "accept-as-is"
or "repair"
actions
are
being
considered.
(2)
It should
also
be
noted that
SDSP
3.12,
CSSC
and
non-CSSC
Listing,
attachment
B,
Critical
Structures
System
and
Components,
section
6.0,
Main Control
Bay,
subsection
6.2,
Control
Bay
and
Shutdown
Board
Room Air-Conditioning systems
lists air handling unit and
pumps.
The licensee's
decision not
to use
a
CARR to document this deficiency does not appear to be
consistent
with
the
plant
methodology
for identifying
significant deficiencies.
Additional
review of this
item
indicated that TE-10 was
added to the procedure after
RTP Test
results
were
approved.
TE-10 indicated that TE-07
was
being
closed
out
by
the
use
of
a
Temporary
Alteration,
TACF
0-88-002-031.
This
use of a
TACF to closeout
a significant TE
also
does
not appear
to
be consistent
with plant deficiency
identification and closeout methodology.
2-BFN-RTP-031B, Control
Bay HVAC.
The
RTP test group documented
a total of 28
as
a result of the
performance
of this
procedure
The inspector noted: TEs 24'5~ 26,, and, 28'ere left
as:
open
TEs.
Closeout
of these
TEs,
was,
dependant
on
modifications being completed,
maintenance
or the performance of
technical instructions.
TE-27, which was considered
closed,
was
reviewed
and referenced
a post modification test,
PMT 161,
as
a
method for closing the TE.
A review of PMT 161 indicated that
a
test deficiency,
TD-5,
was
documented
and
addressed
the fact
that
flow balance
criteria
could
not
be
met.
The
TE-27
indicated that
based
on interim approval
of TD-5, the
TE was
considered
closed.
During the
review of this
item,
the
inspector
did not observe
any documentation
that the
TD was
reviewed against baseline
requirements.
This is another
example
of what appears
to be
an activity not in keeping with the plant
identification
and
close
out
of significant
deficiency
methodology.
(3)
2-BFN-RTP-074, Residual
Heat Removal
System.
The
RTP test group
documented
a total of 37 TEs
as
a result of the performance of
this
procedure.
The
inspector
noted that TE-ll and
TE-35
discussed
the discovery of a wiring error between
panels 9-3 to
9-32
and 9-33.
These
TEs resulted
in the initiation of a
CARR
88-0668
which identified
a significant TE. It was also noted
that
08
and
34 also discussed
a wiring error within panel 9-33,
however,,
a
CARR
was
not generated
to, identify this
significant TE.
This inconsistency
is not in keeping with the
plant identification
and
closeout
of significant deficiency
methodology.
I
(4)
2'-BFN-RTP-099,. Reactor Protective
System
The.
RTP Test group
documented
a total of nine TEs as
a result of the performance of
this procedure.
The inspector
noted that
TEs 4, 5,
and
6 were
written to indicate that portions of RTP-099 would be performed
as part of other
RTP procedures,
RTP-001,
Restart
Test
and
RTP-047,
Turbine Generator
Control.
These
TE do not
meet
the criteria for TEs
and should
have
been
processed
as
intent changes
rather than TEs.
The inspector discussed
these observations
with the licensee
and they
indicated that certain activities
by the restart test group were not
in keeping with the
RTP as discussed
in the
NPP Volume I or the
SER.
This is identified
as
URI 259,
260, 296/89-38-03,
Possible
Failure
to Follow the
BFN Program for Identifying and Closing Significant
Test
Exceptions
and
to Control
Procedure
Changes.
Additional
reviews of these test
procedures
indicated that the
RTP test
group
identified several
concerns
involving the
use of uncalibrated volt
meters,
the shorting out of pressure
switches,
equipment
not being
maintained,
and the overall inability to get specific items repaired.
These
items
are
discussed
in the conclusions
and
recommendations
sections
of the
RTP completed
procedures.
The inspector could not
verify- that. any corrective action
had
been initiated by management
as
a. resul't of the RTP'roup observations
and. recommendations
written in the test summaries.
15
c.
Joint Test Group
On August 16, 1989, the inspector attended
a meeting of the JTG.
The
meeting
was convened to approve
new members of the JTG.
The JTG is a
subcommittee
of
and is the review, approval,
and coordinating
body of the Restart Test Program.
The list of membership
was being
expanded
to include
members
from the
Nuclear
Fuels
Department
in
preparation for the
power ascension
testing
program planning.
The
chairman for the meeting
was the Restart Test Manager
who had
been in
licensed operator training for the past
few months.
SDSP 27.4, Revision 4, "Plant Operations
Review Committee," requires
the
JTG chairman to
be the Technical
Support
Superintendent
or
a
designated
member.
members
are designated
in writing by
the Plant
Manager.
The Restart
Test
Manager
was not
a designated
member.
This item was discussed
with the Acting Restart
Test
Manager
who stated
that
up through
Revision
3 of
SDSP
27.4,
the
Restart
Test
Manager or
a designated
member
was
allowed to
chair
JTG meetings.
A draft of
a revision to correct this
was
reviewed immediately after the meeting
by the inspector.
A NCV was identifieg for this,
NCV 259. 260, 296/89-38-04,
Failure to
Conduct
JTG Meeting in Accordance
With Plant Procedure.
requires
that
procedures
shall
be established,
implemented,
and
maintained
covering
the
administrative
procedures
which control
technical
and cross-disciplinary
review.
This
NRC. identified Level
V
violation is
not
being
cited
because
criteria
specified
in
Section
V.A of the
NRC Enforcement
Policy were satisfied.
This
violation will
be
tracked
to
avoid
repetitively
exercising
'enforcement discretion for the
same
issue.
The
JTG meetings
should
be conducted
in accordance
with plant procedures
and
known problems
corrected prior to the meetings.
Another
JTG meeting
was
attended
on
August
23,
1989.
At this
meeting,
the
JTG membership
changes
were resubmitted
because
of the
chairman conflict on August 16,
1989.
This meeting
was chaired
by
the Technical
Support Superintendent.
7.
Modifications (37700,
37828)
The- NRC inspector
reviewed
and observed
the licensee's
activities in the
modifications area.
This included review of procedures;
discussions
with
craft,
gC inspectors,
supervisors
and
managers;
observations
of field
activity; and review of WPs,
DCNs,
and
FCNs.
The review and observation
consisted of the following:
a.
The inspector
reviewed
the following procedures:
flAI 3.2,
Cable
Pul'1'ing; for.. Insulated'ables:
up. tor 15,000'olts
dated June 24:1989;.
and MAI 3.3:,, Cable Terminating; and. Splicing for Cable
Rated. to 15,000
Volts.
The
inspector
noted
that
each-
procedure
had
several
16
attachments.
Each attachment
contained the individual activities
and
attributes
that the craft supervisor
and the
gC inspector
signs
as
being completed.
b.
DCNs and
The
NRC inspector.
reviewed
DCN 0479A,
DCN 0480A, and
FCN P7137.
The
two DCNs dealt with the
and the
ECN dealt with the
AC/DC calculation deficiencies.
Each
DCN/ECN generated
several
MPs.
, Of the
DCN,
ECN,
and
WPs the following reviews
and observations
were
made:
DCN N0479A
WP 2304-88,
This item required
the
replacement
of undersized
cables for 2-FCV-74-52
and 2-FCV-74-104 in the
RHR system.
The
NRC inspector
observed
the electrical craft
and
gC inspector
routing the
replacement
cables
for 2-FCV-74-52 through
cable
trays located in the Unit 2 reactor building.
MP2309-88.
This item required
the replacement
of undersized
cables
for 2-FCV-74-57,
58,
and
59 in the
RHR system.
The
inspector
observed
the electrical
craft
and
gC
inspectors
routing the replacement
cables for 'these
valves
through cable
trays located in Unit 2 reactor building.
All field activities for these
two
WPs were accomplished
in an
organized
manner
according
to
procedures
with cooperation
displayed
between
the craft and
gC inspectors.
DCN MOBOA
0'P
2387-88.
This. item required
the replacement
of cables
to
RHRSM
pumps
B2
and
B3.
This
DCN was
returned
to
PORC for
additional
licensee
reviews.
The review
was
prompted
by the
fact that the replacement
cables
are larger than the old cables
and may have resulted in routing problems.
The
NRC inspector
noted
that
the
MAI procedures
indicate
what
attributes
the
gC inspectors
are to use in monitoring craft activity.
However,
the
gC inspectors
have their own procedures
referred to as.
IPs.
There
appears
to be
some conflict between
what the MAIs direct
the
gC inspectors
to do and what the IPs direct the
gC inspectors
to
do.
The
NRC inspector will followup the
gC inspector activities in a
later inspection.
No: violations or deviations
were identified;
Site Management.
and. Organization
(36301
36800',.
40700)'n
inspector
reviewed the corrective actions
taken at
BFNP in response
to
a violation previously identified at
Sequoyah
Nuclear Plant involving
composi,te
maintenance;
crews.
On March. 14,, 1988 the-
NRG. issue
an
NOV.
17
against
Sequoyah
for
implementing
composite
crews
without
having
established
training
and qualification requirements
for
1)
foremen
and
general
foremen
supervising
personnel
in other crafts,
2)
craftsmen
performing
work outside
of their craft,
and
3)
craftsmen
performing
independent
verificati ons
outside
of their
craft
( Violati on
327,
328/87-78-02).
TVA admitted
the violation and committed to address
the
generic implications of the violation at other sites.
Requirements
for foremen supervising
composite
crews
were
issued
in an
NIZAM guality Notice on July 6, 1988.
The notice required that foremen of
composite
crews
who did not meet the ANSI 18.1-1971
requirement for four
years
experience
in each craft or discipline which they supervised either
be provided direct access
to technical
support in other disciplines or be
given
documented
training equivalent
to the required
experience.
The
requirements
of the
NIZAM guality Notice were
implemented at Browns Ferry
by
PMI 6.2,
"Conduct of Maintenance",
Section 4.2.
PMI 6.2 distinguishes
between
"composite"
and "mixed" maintenance
crews.
Composite
crews contain multiple craft disciplines,
such
as electricians
and mechanical craft,
and are not used at Browns Ferry.
Although
MOVATS
work is performed
by both electrical
and mechanical
craft,
each
group
reports
to their
own foreman
and the task are separated
on the training
matrix
by discipline.
The
procedure
requires
the
foreman
to
have
cross-discipline
equivalency training for properly making work assignments
and to ensure
adequate
understanding
of the scope of work. If the foreman
does, not have. task equivalency'raining'a
craftsman
with the
required qualifications must assist
the foreman in his duties.
Mixed maintenance
crews
are defined
as combinations of the various crafts
within the
mechanical
discipline,
such
as
machinists,
fitters,
and
insulators.
Foremen of mixed maintenance
crews require four years of
experience,
but do not require four years
in each
area
being supervised.
The equivalency training requirements
and lead craftsman provisions
do not
explicitly apply.
The
inspector
was
concerned
that
the
foremen
qualification. policy for mixed
crews
might not
be in accordance
with
ANSI 18.1 and the
NIZAM.
At Sequoyah,
procedure
SgM-70
was
issued to address
the qualifications of
composite
crew members
performing work outside their craft.
No analogous
procedure
was
issued
at Browns Ferry to specifically establish
the method
of operation
and responsibilities
for the
use of composite
maintenance
crews.
BFN management
stated that cross-training
between
craftsmen within
the
general
mechanical
discipline
eliminated
the skill-of-the-craft
concerns
documented
in Sequoyah
IR 327, 328/87-78.
Based
on. interviews
with selected
craftsmen
assigned
to mixed crews,
the inspector
was
concerned
about the validity of this assumption.
The inspector.
determined. that SDSP5:
"Independent
Veri,fication."'
applied; adequately
to composite
crews
in that the procedure- required.
independent
verifications to
be
performed.
by individuals qualified to
perform
the
steps
be'ng
verified.
However,
licensee
management
18
acknowledged
that only one
member of a composite
crew was required to be
qualified to perform each task being worked.
The inspector questioned
how
the independent
verification requirements
of SDSP 3.15 could
be properly
implemented with only one qualified individual assigned
to the work.
The
licensee
responded
that craft from other crews were frequently brought in
to sign the verifications.
Licensee
management
also stated that many of
the independent verifications performed during jobs which are
on the task
matrix require
no expertise
or established
qualifications.
The inspector
identified the area of independent verifications by composite
crews to be
a concern.
Prior to
NRC inspection
327,
328/87'-78,
the
NNRG conducted
an
evaluation of composite maintenance
crews at Browns Ferry and Matts Bar in
response
to allegations
received
by the
NRC and the
BFNP
ECP.
The
NNRG
administered
an oral
questionnaire
to
a
number of craftsmen
who
had
received
waivers of required
OJT in areas
outside of their craft.
The
questionnaire
was
designed
to
measure
the ability of craftsmen
to
independently
perform the waived task.
The
study,
found that
a high
percentage
of those
examined failed to demonstrate
the necessary
level of
knowledge.
Deficiencies
were
also identified in the waiver process
criteria, execution, quality assurance,
and records
handling.
In response
to the
NMRG findings,
BFN plant management
upgraded
the waiver process,
and initiated
a waiver review and validation program which redid a(l the
waivers
and
also
included
a
computer
printout of craftsman
task
qualifications to
be
used for making job assignments.
During, September
1988,. the-
NRC inspect'or
reviewed the Engineering
and. Technical
Training
Section Letters applicable to Training permanently
assigned
mechanical
and
electrical craft,
and
compared
the requirements
of these
procedures
to
The inspector also reviewed
and revised waiver criteria,
reviewed
selected
records,
and
observed
examples
of the waiver review
process
in progress.
No deficiencies
were identified in the material
reviewed.
Subsequent
to Sequoyah
inspection
327, 328/87-78,
the licensee
performed
an evaluation at
Browns Ferry
and
Sequoyah
to determine
what corrective
actions
would be necessary
to resolve the identified deficiencies
in the
training and qualification of composite
crews
and to determine whether
any
rework would be necessary
as
a result of those deficiencies.
Cases
were
identified where
documentation
of training for a particular task
being
performed
did
not exist,
although
this
finding also
applied
to
non-composite
crews.
The study did not identify any rework done
as
a
result of composite
crew deficiencies.
The following recommendations
were
presented
in a licensee
memorandum
dated
December
21, 1988:
Issue
a corporate
standard
on composite= crew operations.
Increase
management
attention to the- training and waiver process,
and
implement improvements
in~ maintenance training
0
19
Administratively limit the use of composite
crews
and ensure
adequate
supervision of composite
crew operations until a procedure similar to
S(Ns
SgM-70,
which defines
composite
crew operations,
can
be
implemented at BFN.
Procedurally
address
the issue of the number of qualified individuals
per
crew required to provide
needed
expertise for the tasks
to be
performed.
The licensee
report also
documented
a concern regarding
compliance of the
qualifications of mixed crew foremen
and general
foremen with ANSI 18.1.
The Plant
Manager
issued
a
memorandum
dated
February
15,
1989,
which
responded
to the recommendations
of the composite
crew report.
As of the
time of the inspection,
the
licensee
had
not
completed
the
actions
specified in the memorandum.
Although significant
progress
toward
procedural
controls of composite
crews
was evident, sufficient information
was not available
during the
inspection to conclusively establish
that qualifications of mixed crews
were adequately
covered
by existing, plant procedures,
and, that procedural
requirements
were
being
acceptably
implemented.
Verification that
adequate
corrective
actions
have
been
completed
at
Browns
Ferry in
response
to
Sequoyah
violation
327,
328/87-78-02
was
identified
as
Unresolved
Ltem 89-38-05
and resolution
is required prior to Unit 2
restart.
No violations or deviations. were identified.
9.
Exit Interview (30703)
The inspection
scope
and findings were
summarized
on September
15,
1989
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
259, 260, 296/89-38-01
259, 260, 296/89-38-02
259,, 260, 296/89-38-03
~0i ti
VIO, Failure to Conduct
PMT, paragraph
3.
IFI, Proper
Installation of Fire
Seals,
paragraph
4.
URI, Possible
Failure to Follow the
Program
for
Identi fying
and
Cl os ing
Significant. Test. Exceptions- and. to; Control
Procedure
Changes
paragraph 6;
20
Item
~cont'd)
259, 260,. 296/89-38-04
259, 260, 296/89-38-05
Descri tion
NCV, Failure
to
Conduct
JTG
Meeting
in
Accordance
With Plant Procedure,
paragraph
6.
URI, Corrective Action on Composite
Crews,
paragraph
8.
ANSI
ASLR
BFNP
CAQR
CFR
CSSC
DCN
GOI
IFI
IR
JTG
KV
LER
NMRG
NIZAM
NRC.
PMI'MT
American National Standards
Institute
Auto Start Lockout Relay
Browns Ferry Nuclear
Power Plant
Condition Adverse to guality Report
Central Daylight Time
Code of Federal
Regulations
Control
Room Emergency Ventilation System
Critical Structures,
Systems,
and
Components
Design
Change Notice
Diesel
Generator
Emergency
Core Cooling Systems
Engineering
Change Notice
Employee
Concerns
Program
Emergency
Equipment Cooling Water
Electrical Maintenance Instruction
Emergency Notification System
Environmental qualification
Engineered
Safety Feature
Final Safety Analysis Report
General
Operating Instructions
Heating, Ventilation,
8 Air Conditioning
Inspector
Followup Item
Inspection
Report
Joint Test Group
Kilovolt
Licensee
Event Report
Motor Generator
Motor Operated
Valve
Maintenance
Request
Non-cited Violation
Nuclear Manager
Review Group
Nuclear Performance
Plan
Nuclear guality Assurance
Manual
Nuclear Regulatory
Commission
PTant Manager Instruction
Post Maintenance/Modification Test
Primary Containment Isolation System
Plant Operations-
Review Committee.
21
SDSP
SMPL
SOS
TACF
TD
TI
TS
UST
VIO'P
Quality Control
Residual
Heat Removal
Residual
Heat Removal
Reactor
Operator
Reactor Protection
System
Restart Test Program
Standby
Gas Treatment
System
Site Director Standard
Practice
Safety Evaluation Report
Surveillance Instruction
Pump
Site Master
Punch List
Shift Operations
Supervisor
Senior Reactor Operator
Source
Range Monitor
Temporary Alteration Change
Form
Temperature
Control Valves
Test Deficiency
Test Exception
Technical Instruction
Technical Specifications
Valley Authority
Unresolved
Item
Unit Service Transformer
Violation,
Work Plan