ML18038B582
| ML18038B582 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/12/1995 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B580 | List: |
| References | |
| 50-259-95-60, 50-260-95-60, 50-296-95-60, NUDOCS 9512190099 | |
| Download: ML18038B582 (98) | |
See also: IR 05000259/1995060
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report Nos.:
50-259/95-60,
50-260/95-60,
and 50-296/95-60
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
Inspection at Browns Ferry Site near Decatur,
Inspection
Conducted:
October
15 - November
18,
1995
1
Inspector:
eonar
.
er
,
,
endor
es>
ent
nspector
J.
Munday, Resident
Inspector
R. Musser,
Resident
Inspector
M. Morgan, Resident
Inspector
Approved by:
ar
.
esser,
rane
se
,
Reactor Projects,
Branch
6
Division of Reactor Projects
lz n./tJ
ate
1gne
SUMMARY
Scope:
This routine resident
inspection
involved inspection on-site in the areas of
operations,
maintenance
and surveillance testing activities, Unit 3 restart
activities including observation of management
assessments
for restart
and
major testing activities,
review of the component
and piece part qualification
system
and review of open items,
including several
Three Mile Island Action
items.
The remainder of NRC open items for restart of Unit 3 were closed.
Several
hours...of. backshift coverage
were routinely worked during most work
weeks.
Deep backshift inspections
were conducted
on November
10,
12 and
18.
p-Q> g~fj,'4;;-
".<<~~a W
95i2i90099 95i2i2
ADOCK 05000259
8
Enclosure
2
'I
i5
Results:
One violation and two noncited violations were identified.
Operations:
One violation was identi.fied involving failure to follow configuration control
procedures.
Unit 3 scram discharge
volume vent and -drain valves were found
incorrectly gagged
open.
A NRC inspector identified that the discharge
volume
high level
scram function was incorrectly bypassed.
Although existing plant
conditions
reduced
the safety significance of both incidents,
these
examples
were significant deficiencies
involving plant configuration.
(VIO 296/95-60-
01, Failure to Follow Config8fation Control Procedures
Resulting in
Misalignment of Scram Discharge
System
Components,
paragraph
2.3)
A noncited violation was identified involving a loss of shutdown cooling flow
on Unit 3.
Fuel
had not yet been
loaded into the core.
Planning
and review
processes
were not conducted
in accordance
with procedural
requirements
during
troubleshooting of reactor protection
system equipment.
(NCV 296/95-60-02,
Loss of Shutdown Cooling Flow, paragraph
2.2)
Final verification of the licensee's
readiness
to load fuel in Unit 3 was
performed through detailed
reviews of selected
important equipment conditions
and confirmation of incorporation of regulatory requirements
into procedures.
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For several
key systems,
all open items were reviewed
and the systems
were
confirmed to be ready for fuel loading.
Maintenance
backlogs
were noted to be
small.
Emergent
equipment
issues
continued to be addressed
appropriately.-
All required TS.surveillances
were completed prior to fuel loading.
Overall
drywell conditions at drywell closeout
were regarded
as very good.
(paragraphs
6.1;I and 6.1.2)
Observation of the Nuclear Safety Review Board
and senior'management
assessment
of the readiness
to restart Unit 3 indicated that
a comprehensive
review was performed
by the groups.
(paragraph
6.1.3)
Maintenance
and Surveillance:
Inspection of completed Unit 3 maintenance
work orders indicated that post
maintenance
testing
and environmental qualification requirements
were being
met.
Documentation of completed
work was adequate.
'(paragraph
3.2. 1)
The Unit 3 containment
integrated
leak rate test,
diesel
generator
load
acceptance
testing,
and primary system hydrostatic
testing were well planned
and implemented.
(paragraphs
3.2.2, 6.2.1,
and 6.2.3)
Plant Support:
Inspectors
noted several
instances
in, whi.ch securi.ty guard monitoring of
personnel
access
lanes
.was not. vigorous.
The .observations
were communicated.
to plant management
and corrective actions
were promptly'initiated.
(paragraph
4)
t
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Engineering
and Technical
Support:
One noncited violation was identified.
The licensee initially concluded that
a failure of the "A" diesel generator'id
not have to be incorporated into the
diesel
generator reliability calculations.
NRC inspectors identified that the
failure was required to be included in the calculations.
(NCV 260/95-60-03,
Failure to Perform Diesel
Generator Reliability Determination,
paragraph
5.2)
A detailed review of the Component
and Piece Part gualification Program for
Unit 3 was completed.
The pro'gram fully met regulatory commitments
and
adequate
controls were present
on qualified equipment
replacement
parts.
Good
conditions were noted in the,-storage
warehouse.
(paragraph
7)
I
I
f
1.0
Persons
Contacted
Licensee
Employees:
'REPORT:DETAILS
T.
J.
R.
- J
T.
- C
- J
- G
R.
J.
R.
G.
- E
S.
J.
- p
T.
D.
- S
J.
- H.
Abney, Unit 3 Nuclear Assurance
and Licensing Manager
Brazell, Site Security Manager
Coleman.,
Radiological Controls Manager
Corey,
Chemistry
and Radiological Controls 'Manager
Cornelius,
Emergency
Preparedness
'Manager
Crane, Assistant Plant Manager
Johnson,
Site guality Manager
Jones,
Unit,3 Startup
Manager
Little, Operations
Superintendent
Machon, Site Vice President,
Browns Ferry
Maddox, Maintenance
and Modification Manager
Moll, Plant Operations
Manager
Pierce,
Technical .Support
Manager
Preston,
Plant Manager
Rudge, Site Support
Manager
Sabados,
Chemistry Manager
Salas,
Licensing Manager
Shriver, Nuclear Assurance
and Licensing
Manager.
Stinson,
Recovery
Manager
Wetzel., Acting Compliance Licensing Manager
White, Outage 'Manager
.
Williams, Engineering
and Materials Manager
Other licensee
employees
or, contractors
contacted
included licensed reactor
operators,
auxiliary'perators,
craftsmen,
technicians,
and
public safety
officers;
and quality .assurance',
design,
and engineering
personnel.
NRC Personnel:
- L. Wert,,Senior Resident
Inspector
J: Hunday,
Resident
Inspector
R. Musser,
Resident
Inspector
- M. Morgan, Resident
Inspector
J. Williams,
NRR Project Manager
G.
Wiseman,
DRS Inspector
G. HcDonald,
DRS Inspector
P. Fillion, DRS Inspector
F. Jape,
Senior Project Manager,
B. Rogers,
NRR Special
Inspection
Branch
S. Rudisail,
DRS Inspector
D. Nelson,
NRR Inspection
Program Branch
H. Janus,
Resident .Inspector,
Brunswick
H; Whitener=,
DRS Inspector
P. Byron, Resident
Inspector,
Brunswick
R. Aiello, Inspector,
W
0
'0
NRC Officials/Hanagement
onsite:
W. Russell, Director, Office of Nuclear Reactor Regulation
S. Varga, Director, Division of Reactor Projects,
S. Ebneter,
Regional Administrator,
Region II
J. Johnson,
Acting Deputy Regional Administrator,
Region II
"Attended exit interview
and initialisms used throughout this report are listed in the last
paragraph.
2.0'lant Operations
(71707,
92901,
40500)
2. 1
Operations
Status
and Observations
Unit 2 operated
at power for the entire period.
On October
18,
1995
commenced
loading of fuel into the Unit 3 reactor vessel.
Loading was
completed
on October 29.
On November 2, reactor vessel
reassembly
was
completed.
Unit 3 containment
leak rate
and
RPV hydrostatic testing
was
performed during November 5-11.
The vessel
was disassembled
to correct
a
problem with two misaligned fuel support pieces.
On November
16 and
17 the
Unit 3 vessel
and drywell were reassembled..
Activities within the control
rooms were monitored routinely.
Inspections
were conducted
on day and night shifts, during weekdays
and
on weekends.
Observations
included control
room manning,
access
control, operator
professionalism
and attentiveness,
and adherence
to procedures.
Th'
inspectors
noted that operators
were cognizant of plant conditions
and were
attentive in'heir duties.
Due the approaching
Unit 3 restart,
the inspectors
have emphasized
review of issues that have potential effects
on the operation
of the other unit. Instrument readings,
recorder traces,
alarms,
operability of nuclear instrumentation
and reactor protection system channels,
availability of power sources,
and operability of the Safety Parameter
Display .
System were monitored.
Control
room observations
also included emergency
core
cooling system lineups,
primary and secondary
containment integrity, reactor
mode switch position,
scram discharge
volume valve positions,
and rod movement
controls.
Daily discussions
were held with plant management
and various
members of the
plant operating staff.
One of the inspectors
attended
the daily Plan of the
Day meetings.
Plant tours were taken throughout the reporting period
on
a
routine basis.
Observations
included valve position
and system alignment,
and hanger conditions,
containment isolation alignments,
instrument
readings,
housekeeping,
power supply
and breaker alignments,
radiation
and
. contaminated
area controls,
tag=control-s
on.-equipment-,.
work activities in
progress,
and radiological protection controls.
Paragraph
6. 1 describes
t
specific reviews conducted just prior to Unit 3 fuel loa'ding
and startup
activities.
II
i
During this report period the licensee
and the inspector noted examples of
deficiencies
involving second party verification.
On October 31,
1995, the
licensee identified .that
a hold order card
was not properly second party
verified while placing
a clearance.
BFPER951643
was written to document this
event.
On November 7,
1995, the inspector noted confusion concerning the
requirements
of performing second party verification while observing
an
.operability test.
Conversations
with various Operations
personnel
.indicated
that there
was
a lack of understanding
on the requirements
of second party
verification and
how it is actually performed.
This was discussed
with
Operations
management
'who stated that action
had already
been taken to provide
additional training and restated
the expectations
of management
regarding
second party verification.
The inspectbrs
continued to perform periodic tours of the Unit
1 reactor
building.
On October
19,
1995,
an inspector identified three pipes
(one inch
diameter)
located in the Unit
1 reactor building that had direct communication
outside of the building.
The pipes
were funnel drain pipes from fire
protection deluge valves which drained to the reactor building roof drain
lines.
The inspector felt air discharging
from the funnels which indicated
that outside air was blowing through the roof drains into the building.
Operations
was contacted
and engineering
was requested
to investigate.
The
openings
were found to not have
been
accounted for'in the secondary
containment
breach
program,
however,
when the breaches
were
added to the
recorded existing breaches,
the result
was not an excessive
amount of
secondary
containment
openings.
BFPER951567
was initiated to document
and
correct this condition.
On November
13 and
14,
1995, the senior resident
inspector contacted six local
officials and informed them of the Unit 3 restart
planned for November
19.
The officials included: the mayors of Athens, Moulton,
and Decatur,
as well as
the commissioners
of Limestone,
Morgan,
and Lawrence cdunties.
The inspector
did not receive .any negative
comments or concerns
from the officials..
2.2
Unit 3 Loss of Shutdown Cooling Flow
On October
13,
1995, while troubleshooting
a problem with the
RPS system,
an
automatic isolation of the
Loop II RHR inboard injection valve, 3-FCV-74-67,
occurred
when the
B RPS
MG set
was manually tripped.
Following the isolation
the
B RPS bus
was re-energized
and the injection valve reopened.
At the time
of the event the loop was in the shutdown cooling mode of operation,
however,
no fuel was in the reactor
vessel.
The shutdown cooling suction valves did
not isolate
because
the isolation function had been defeated
in accordance
with the troubleshooting
work order,
WO 95-18774-00.
It was not recognized
by
those involved with the activity that the injection valve would also receive
an isolation signal.
Operations
reported the event to the
NRC in accordance
with 10CFR50.72(b)(2)(ii)
and initiated BFPER951505.
The inspectors
reviewed..the
WO and. noted.-that- it was not planned
as
a high
risk- activi'ty;
SSP-6-..2,
Mai'ntenance
Management
System,, section 3.8.6,.
describes
a high risk activity as
one which has
an inherent increased risk for
causing reactor
ESF actuations,
or transients.
It states
that
activities involving logic systems
such
as
RPS or PCIS that can directly or
I
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indirectly cause isolations
are to .be considered
to be high risk.
Additionally, troubleshooting activities where the causes
of the malfunctions
are not well understood
are to be considered
high risk.
The procedure
requires that high risk activities include additional
planning considerations
and approvals
by the Operations
Manager,
Operations
Superintendent,
Maintenance
Manager,
Duty Plant Manager,
and Technical
Support
Manager prior
to starting work.
The inspector could not conclude that the event would not
have occurred
had the activity been considered
high risk but it was concluded
,that the troubleshooting activities would have received
much mor e review prior
to the work commencing.
An Incident Investigation
was initiated and concluded that the event
was
caused
by inadequate
coordination of activities, technical deficiencies
in the
troubleshooting
plan,
and inadequate
control of the types of activities that
can
be performed from a troubleshooting
plan.
Discussion with the licensee
indicated that the troubleshooting
plan did not receive the proper reviews
and
approvals prior to commencing work.
The safety significance of this event is
small.
Although shutdown cooling was in service,
no fuel was located in the
reactor vessel
and shutdown cooling was not being used to remove decay heat.
This failure to follow plant procedures
constitutes
a..violation of minor
significance
and is 'being treated
as
a Non-Cited Violation, consistent with
Section
IV of the
This matter is identified as
50-296/95-60-02,
Loss of Shutdown Cooling Flow.
. Following the event,
on October
16,
1995, licensee
management
issued
a site
dispatch stating that there would be
a site wide seventy-two
hour quiet time
in which little physical
work 'would be performed.
The plant management
stated
that the purpose of the quiet time was to assess
the activities for the future
and to completely "switch gears"
from. a recovery .mode to an operating
mode.
2.3
Components
Out Of Expected Position
On October 30,
1995, the Unit 3 reactor
mode switch was placed in a "Shutdown"
position for containment
integrated
leak rate testing
(CILRT).
The mode
switch positioning caused
the expected
reactor
however, it was noted
that all eight
SDV vent and drain valves failed to close during the scram.
Upon further investigation,
the valves were found to be in a gagged
("dogged")
open and, therefore,
they could not close
upon receipt of the scram signal.
The valves were not in an ungagged position
as prescribed
in the
SDV system
equipment
alignment checklist.
The
SDV vent
8 drain valves,
(3-FCV-085-0082,
0082A, 0083,
0083A,
0037C,
0037D,
0037E
and 0037F),
have handwheels
which are
actually mechanical
stops or "dogs".
The handwheels
can
be used to manually
open the valves,
but .the valves will then
be "blocked" in an open position.
The handwheels
cannot block the valves from opening
when placed in a closed
position;
however,
they can prevent closure if "dogged" in the open position.
A "dogged" position is
a ful-ly counterclockwise
("open"), direction with
threads visible between the handwheel
and the valve body.
An "undogged"
position -is
a ful-ly"clockwise ("closed" ) direction with no threads, visible.
=between" the 'handQheel--and=valve
body;
When"the valves were later"ungagged'
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they-operated-properly-.
Despite
a detailed investigation,
the inspection
-period, the licensee
was not able to determine
the specific cause .of'he
- misposi,tioned valves.
l
t
ll
5
On November 6,
1995,
an
NRC inspector.,
during
a routine inspection of control
room activities,
noted that the Unit 3
SDV High Level
Scram switch was in the
"Bypass" position.
On November 3, the unit reactor
mode switch'had
been
repositioned
from "Refuel" .to "Shutdown", in order to comply with
prerequisites
of a scheduled
CILRT.
An expected
was later reset;
however,
the
SDV High Level Bypass switch was not returned to normal until the
mispositioning
was observed
by the
NRC inspector.
The mode switch was in
"Shutdown"
and all rods were fully inserted.
However,
TS require that this
The switch was not in the "Normal" position
as
prescribed for in the
SDV system
equipment checklist.
Problem Evaluation Report 951687 noted that, during the month of October., six
similar conditions involving instances
of equipment mispositioning were
reported.
An attachment
to the above
PER was reviewed
by the inspectors
and
it was noted that
a search of the database
was performed
by the licensee to
identify similar configuration control
PERs
on Units-2
8
3 over the last
thirteen months.
Sixteen
"component mispositioning"
PERs were found and were
generically classified
as "loss of status control".
While several
licensee
actions
have
been
performed to resolve this issue,
others
must
be performed to
reinforce facility procedural
requirements
and expectations
of both Operations
and Maintenance
personnel.
At. the close of this report, the licensee
was
evaluating, the overall subject for corrective action.
These
two examples of failure to mainta'in adequate
unit system configuration
control represent
a violation.
This issue is identified as
VIO 296/95-60-01;
Failure to Follow Configuration Control Procedures
Resulting in Misal.ignment
of SDV System. Components.
One violation and
one noncited violation were identified.
3.0
Maintenance Activities and Surveillance Testing
(62703, .92902,
61726,
92901,
37551,
92903)
3. 1.1 Maintenance
Observations
Maintenance activities were .observed
and/or reviewed during the reporting
period to verify that work was performed
by qualified personnel
and that
approved
procedures
in use adequately
described
work that was not within the
skill of the trade.
Activities, procedures,
and work requests
were examined
to verify proper authorization to begin work, provisions for fire hazards,
cleanliness,
exposure control,
proper return of equipment to service,
and that
limiting conditions for operation
were met.
The following maintenance activities were reviewed
and witnessed
in whole or
in part:
WO 95-00312-00
'RCIC Minimum Flow Valve Motor Inspection.
On November=l.l=,
1995, the inspector witnessed electrical
maintenance
personnel
perform portions of an inspection
and -cleaning of the 2-MTR-071'-0034,
-Minimum Flow Valve motor.
The inspector
observed
the craft pull back
il
0
0
insulating tape to inspect connectors,
verify l.ug tightness,
and ensure
the
wiring insulation
was not damaged.
The torque switch setting
was verified to
be acceptable
as
was the general
overall condition of the switch.'ollowing
completion of the activity the inspector verified the housing cover .was
properly oriented. when installed.
The maintenance
.personnel
appropriately
used the proper procedures.
Cleanliness
requirements
were adhered to.
The
inspector
noted
no discrepancies
with this activity.
Section
6 of .this report describes
additional specific maintenance activities
monitored
by the inspectors.
3. 1.2 Maintenance
Work Order Reviews
The inspectors
reviewed several
recently completed
maintenance
work orders
associated
with Unit 3 maintenance activities to verify that the work was
properly controlled
and post'aintenance
testing
was satisfactory.
WO 95-15441-01,
and 95-15441-00:
These
work packages
addressed
"rolled leads" involving the- drywell control air
compressor
inboard
and outboard drywell suction valves.
Discussions
were held
with the Unit 3 Restart
Manager,
the involved system engineer,
and Ma'intenance
management
regarding
some aspects
of the packages.
was written on 8/30/95 to disposition Test deficiency TD-2 on Post
Modification Test 3-PHT-032-.043:
Functional. Testing of Valves 3-FCV-032-0062
and 0063.
(At steps
7.3. 13. 1 the "63" val.ve local handswitch operated
backwards,
at step 7.4.13. 1 the "62" valve would not operate
from the local
switch.),
The inspector
.noted .that the problems
and the
WR actions
were
logged
on the chronological test log in the test -package.
'he
WR was assigned
as a,priority 2 "immediate attention"
and the Restart
'Manager authorized
the work to be performed in parallel with the planning.
The inspector verified that this is permitted
by SSP-6.2.
The work was
performed
on August 30,
1995.
The work was documented
in detail
(lead
by
lead, including second
checks)
on the
WR form.-and included
a simple functional
~
test.
The opening of the junction box was recorded
on Attachment
5 of EII-0-
OOO-TCC106, Troubleshooting
and Configuration Control of Electrical
Equipment.
(Box was left "unsealed",on
August 31.)
PMT-BF-032.043
was- subsequently
completed
on August 31.
The inspector verified that the steps of the
PHT that
were re-performed
also served
as
a post maintenance
"functional test" after
the electrical
were connected.
Inspector obtained
copy of Potential
Drawing Deficiency
(PDD)95-441.
This
PDD was initiated on August 31,
1995 to correct the connection
diagram for the
valve leads.
(The schematic
drawing was correct.)
WOs 95-15441-00
and -Ol were subsequently
planned.
These work orders
were
signed-.off on. September-
15;
1995.
Usually,
WOs are=planned
much:more-quickly.
if "in parallel" with the work.
Although it is not specificall'y set forth in
. the
SSP, it is expected that planning "in parallel"
be performed's
the work
is being done.
In this case, -restoration -of operabi.lity was not,a concern.
i1
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The
WO packages
included the
Form SSP-235s
required for all of the worked
Eg
components,
the
PDD,
and completed
sheets
out of the EII-0-000-TCC106
procedure.
The,inspector noted that the functional test
was N/A'd in the
and suspected
that this was because
the "actual work" was done
as noted
on the
WRs (8/31/95)
and the
WO paperwork
was completed
as "documentation of
completed actions"
on September
14-15.
The actions required
by the
Form 235s
(Eg maintenance
sheets)
and the TCC106 sheet for resealing of the junction box
were completed
on September
14-15.
The system engineer
and maintenance
management
confirmed that this was what had occur red.
The inspector
questioned
maintenance
management
as to why the workers did not simply
document that the wire connection activities had
been
completed
on August 31
as recorded
on the
WR instead of writing the steps
out again with the
September
14 date.
Maintenance
management
indicated that this practice will
be reviewed.
In summary,
the inspector
concluded that the work was controlled in accordance
with the procedures.
All Eg work requirements
were completed
and documented
as required.
On operable
equipment
such
as Unit 2, the
same
sequence
could
occur except that the planning would be more in "parallel" and the
completed
more timely since the equipment would remain inoperable until the
was completed.
WO-95-01888-03
and WO-94-02123-00:
This work was to disconnect/reconnect
a
RHR heat
exchanger
discharge
valve and
temperature
sensor
so that the
RHRSW piping could be replaced.
The inspector
'eviewed
the
EMS .data
base
and noted that 3-FCV-023-0034 is not flagged
as
Eg
in EMS.
However, the motor actuator
(3-MVOP-023-0034) is coded
as
Eg.
The actual
work performed section of WO-95-01888-03'stated
that the valve
cables
were reterminated
and conduits replaced
by
WO 94-02123-00.
The
inspector obtained
a copy of this
WO.
The
WO clearly identified the actuator
as
Eg and the required
Form 235s were completed.
Post maintenance
testing
of the val.ve was included in the
WO and was accomplished
by an approved
procedure.
WO-94-16769-00:
This
WO involved troubleshooting
an unexpected
window response
during
a test.
The equipment
involved was Unit 3 load shed circuitry.
The
inspector
reviewed the referenced
procedure,
EII-O-OOO-TCC106, Troubleshooting
and Configuration Control of Electrical
Equipment
and noted that it provides
methods for documenting/controlling electrical
lead lifts and other electrical
maintenance activities.
was initiated on October
16,
1995, to support completion of Stage
6
of.
DCN. 21284,
The actual
work performed section. of. the
WO described
activities performed October
17,
1994 to October 23,
1994,
then the activities
were initiated again
on March 6,
1995 to test
changes
made
by
DCN F33386 for
t
W21284.
The
WO contained
a detailed
45 page attachment
which-was- used. to-.
guide the troubleshooting/testing
activities starting. on March 6,
1995.
The
attachment
included prebriefing, specific acceptance
criteria,. and. speci,fic
0
0
8
step-by-step
method
of, testing.
The. attachment
was completed
on March 6,
1995.
WO 94-16769 work activities were completed
on June
21,
1995 when leads
to a relay were rol.led.
The inspector verified that'.PMT 268.001 functionally
tested
the circuitry and it was completed
on July 19,
1995 (after the work was
done).
The inspectors
concluded that the activities were adequately controlled
and
regulatory requirements
were met.
3.2
Surveillance Obsyrvations,
Surveillance tests
were reviewed
by .the inspectors
to verify:procedural'.and
performance
adequacy.
Testing .was witnessed
to ensure that approved
procedures
were used, test equipment
was calibrated,
prerequisites
were met,
test results
were acceptable,
and system restoration-was
completed.
3.2. 1 Routine Surveillance Testing
i
2-SI-4.4.A.l
Pump Functional. Test
On November 7,
1995, the inspector witnessed
the'performance of this
surveillance.
This test operates
each
SLC pump to verify the proper flow rate
can
be obtained
and the vibration levels are acceptable.
During the
surveillance the inspector noted that step 7.5. 10 did not receive
second party
verification prior to its performance
as required.
The step required the
isolation of a drain valve when
a specified
amount of water is drained
from
the system.
It did not appear
to the inspector as,a
step requiring this type
of verification nor one in which 'the verification could reasonably
be
performed.
The inspector questioned
both the
AUO performing the test
and
an
ASOS observing
about this step.
They stated that the step should not be
required to be second party verified because it. was not
a critical step
and
.
was required to be performed
when
a parti'cular setpoint
was reached.
If a
second party verification,;were performed the setpoint would have:been
exceeded
prior to its'erformance.
The licensee
stated that the procedure
would be
reviewed
and .revised to delete
any unnecessary
second party verifications.
including the one for-this step.
While operating
pump
2A to verify flow requirements
the
pump discharge
hose
rig started leaking
an excessive
amount
and the
pump was secured.
The hose
was repaired,
the test tank refilled, and the test restarted.
The inspector
noted the operators
contacted
the main control- room to apprise
them of the
situation,
backed
up in the procedure to the appropriate
step,
and
recommenced
performance of the surveillance.
The inspector considered this process
to be
well communicated'nd
coordinated.
During the surveillance
the operator
noted
that the green
"pump off" light flickered on and off. It was determined that
the socket
was loose
and
WR C285369
was initiated to correct the condition.
It was also noted that the red
"pump. running" light was dim.
The operator
removed the bulb and determined that- it-was= not the-same-type
bulb as the
green light.
Engineering
was contacted <o determine
what- bulb -should-be-
i'nstalled for these. l,ights but was unable to identify a particul.ar,
requirement.
Operations initiated
a
PER to address this issue.
No further
discrepancies
were noted during .the, performance .of this procedure.
0
.3-SI-4.6.B.1-4
Reactor Coolant Chemistry
On November
7,
1995, the inspector witnessed
the sampling
and analyzing of
reactor coolant for conductivity in accordance
with this procedure.
The
continuous conductivity monitor was =-inoperable
and Technical Specifications
requires
a reactor coolant sample
be analyzed for conductivity 'every eight
hours
under these conditions.
The inspector
witnessed
the sample
being drawn
and analyzed.
Proper radiological protection requirements
were observed.
The
conductivity was acceptable for the existing plant conditions.
No
discrepancies
were identified during the performance of this activity.
3-SI-4.2.C-4(B)
Instrumentation
That Initiates
Rod Blocks/Scrams
Source
Range Monitors
(SRM) Calibratio~ And Functional
Test
On October
14,
1995,
the .inspector witnessed
portions of the performance of
this surveillance.
The test
had previously been performed with the .exception-
of the discriminator high threshold/high, voltage calibration port'ion.
Performance of this section required that
a neutron source
be located close to
the
SRM detector.
The .inspector verified that the test equipment
was properly
calibrated,
the appropriate
reviews
had
been obtaine'd prior to performance,
and the proper procedure
was being used.
The procedure
was
on revision
0 and
had not yet been validated.
It was therefore
necessary
to validate it during
'this performance.
The technicians
performing the surveillance .identified that
step 7. 11.34 incorrectly operated
component
Z32-Rl.
The performers
determined
that the correct
component
was PS21-Rl.
This was considered
to be
an obvious
minor error and the surveillance
was completed
as written.
Following the
conclusion of the surveillance the inspector:verified that this discrepancy
was identified on the
new procedure, validation form.
No.further discrepancies
were identified with this activity.
Additional routine surveillance testing activities conducted
on Unit 3 in
preparation for,.restart were, observed
and are discussed
in paragraph
4.2.
3.2.2
Unit 3 Integrated
Leak Rate Test
The inspectors
reviewed test documentation
and witnessed test activities to
determine that the Unit 3 primary containment
integrated
leak rate test
(CILRT) was performed in accordance
Primary
- Reactor Containment
Leakage Testing for Mater Cooled
Power Reactors;
ANSI
N45.4 - 1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N45.4 - 1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.,
American National Standard,
Leakage
Rate Testing of Containment
Structures for Nuclear Reactors;
Browns Ferry Nuclear Plant Technical
Specifications 3.7/4.7.A.2.a-f,
Unit 3; test procedure 3-SI-4.7.A.2.a-f,
Integrated
Leak Rate Test;
and,
Bechtel Topical Report,
'BN-TOP-l, Rev.
1, Testing Criteria for Integrated
Leakage
Rate Testing of
Primary Containment Structures for Nuclear
Power Plants.
Selected
sampling of the licensee's .activities which were inspected
included:
(-1:)'- review-.of the test 'procedure to verify that the procedure
was properly
approved
and conforms with'-the regul'atory requirements
listed-above;
(2)
observation of test performance to determine that test preparat'i'ons
were
completed,
special
equipment
was installed,
and appropriate
data
was recorded;
0
10
and (3) preliminary evaluation of test results'o verify that leak rate limits
were met.
From review of the test procedure 3-SI-4.7.A.2.a-f,
and associated
technical
instructions 3-TI-173 and 3-TI-179 the inspectors
concluded that the licensee
had incorporated
the essential
elements of the regulations into the procedure
and instructions.
Procedure 3-SI-4.7.A.2.a-f contained
adequate
instructions
for venting, draining and alignment of systems to establish
boundary
conditions, identification of systems to remain operable for safe
shutdown of
the;reactor,
and .acceptance
criteria for a short duration test
and
a '24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
test which were consistent
with the regulations.
Technical instructions
provided detailed instructions for installation, location,
and determination
of weighing factors for instrumentation
and data recording setup.
The
technical
instructions
also required inspection of the accessible
areas
o'
containment for degradation
and delineated
.the leakage
surveys to be performed
during the test.
The inspectors
reviewed the instrument calibrations, verified that selected
alignments
were correct,
observed that appropriate
data were
recorded
and processed,
and evaluated
the test results.
The containment
integrated
leak rate data analysis
program used
by Browns
Ferry had the capability of analyzing the data in accordance
with BN-TOP-I for
a short duration total time test
and .in =accordance
with ANSI N45.4 and
Appendix J for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> total time or mass point test.
The inspectors
evaluated
the data
and determined that the all acceptance
criteria for
termination of the leak rate measurement
were met in a 10.2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> short
duration test with an uppei
95K confidence leak rate (includes
measurement
error) of 1.06 wt. percent pe'r'ay of the'ontainment,air
at Pa.
The
allowable limit for,Browns Ferry Unit 3 for the test is 0.75
La or 1.5 wt.
percent
per day.
Subsequent
to the containment
leak rate measurement,
a supplemental
test must
be performed to verify the ability of the CILRT instrumentation to measure
a
change in leak rate..
An acceptable
method is specified in Appendix
C of ANSI .
N45.4 which involves establishing
an additional
known leak rate
on the
containment
and verifying the
known change
by measuring
the .overall leak rate.
The licensee
performed
a 5.3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> supplemental
test
and measured
the composite
leakage of 2.84 wt. percent -per day which-was well within the acceptable
range
of leakage.
+I
The inspectors
concluded that .the licensee
had demonstrated
the leak tight
'ntegrity
of the primary containment
as required
by the regulations.
The test
was well planned'and
implemented.
During a previous inspection,
NRC Report 95-08, the inspectors
had reviewed
six -design
changes
associated
with plant modifications to meet Appendix J test
requirements. and-found'that-*the-modifications
were properly implemented.
During this inspection the inspectors
reviewed-two additional'lant
changes
associated
with containment leak testing
as follows:
C
IN
11
RHR Suppression
Chamber
Spray Valve
(FCV 74-58)
and
RHR Recirculation
and
Pump Test Valve
(FCV 74-59)" were"'required
- to be rotated
180 degrees
to facilitate testing the valve bonnets.
The inspectors
confirmed that
this change
had
been
implemente'd
by Maintenance
under. work orders
95-
06550-00
and 95-06557-00 respectively.
Auxiliary Boiler System Valve
(HCV 12-742) required the installation of
a block valve to facilitate local leak rate testing.
The licensee
subsequently
determined that the valve and associated
piping is part of
a zinc chromate injection system which is not used.
Consequently,
under
DCN W23574A, the zinc chromate injection system including
HCV 12-742
and
associated
piping and valves were removed.
The tie-in of the Auxiliary
Boiler System to the .RCIC pump minimum flow bypass line to the
suppression
chamber
was cut,
capped
and welded outside primary
containment to preserve
containment integrity.
The inspectors
walked
down the change
and observed
the capped penetration
and confirmed
removal
on the piping and valves.
Also, the Configuration Control
Drawing 3-47E813-1 reflected the capped line and piping removal.
The inspectors
concluded that the licensee
had adequately
implemented the
above
changes
to enhance
Appendix J testing.
No violations or deviations
were identified.
~
4.0
Plant Support
(71750)
The inspectors
toured the protected
area
and noted that the perimeter fence
was intact
and not compromised
by erosion
or. disrepair.
The fence fabric was'-=.
.
verified to be intact'rid secured.
The inspectors
also observed
personnel
and'ackages
entering the protected
area
and verified they were searched
either by
special
purpose detectors
or physical
patdown.
The resident
inspectors
and
a
visiting inspector noted several
instances
in which security guard attention
was not strong during personnel
access.
During off normal hours, monitoring
of the entry lanes at the access
portal
appeared
to be less rigid than
expected.
While no regulatory requirements
were violated,
more management
attention
was needed
in this area.
The observations..were
discussed
with
security
and plant management
and corrective actions
were promptly initiated.
The inspectors will continue to monitor personnel
access
controls.
No violations or deviations
were identified.
5.0
Engineering
and Technical
Support
(37551)
5. 1
RPS Logic Problem Review
~
On October 21,
1995,
guad Cities Nuclear Plant
(a
BWR-3 similar in design to
Browns Ferry), commenced
a dual unit technical specification required
shutdown
. due
a design
problem .,in the scram discharge
volume high level reactor
logi'c.
More specificall'y, the si'ngle failure criteria was not" met in that the
~
~
~
~
~
~
failure of a single
RPS subchannel- relay coupled with a high level in one
scram discharge
instrument
volume would fail to generate
a full reactor
-,as required.
The inspectors
learned of this incident during
a routine review
I
0
12
of 50.72 reports
on October
24.
This information was relayed to the licensee
via the
RPS system -engineer that day.
The licensee
and the inspectors
independently verified that .this condition did not apply at Browns Ferry.
The
scram discharge
volume high level reactor
scram -logic at
BFNP is designed
such
that
a single failure of any component
coupled with a high level in a single
scram discharge
instrument
volume or both scram discharge
instrument
volumes
would result in the required reactor
Each
scram discharge
instrument
volume has four level switches
(one for each of the four RPS subchannels)
and
.
=four different
RPS logic relays for a total of eight different level switches.
and logic relays.
This review revealed that the
BFNP scram discharge
instrument
volume high level
scram logic is appropriately designed to
withstand
a single failure.
5.2
EDG Failure Not Included in
EDG Reliability Calculations
On October
10,
1995, while performing
a preventive. maintenance activity on the
A DG relay
ESTR malfunctioned which resulted
in the'DG failing to start.
The
malfunction occurred
on the third start of a redundant start test.
Investigation identified that the cause of the failure,was a,piece of tie wrap
used to bind wiring together
had fallen into the relay mechanically preventing
it from operating properly.
The tie wrap was removed
and the relay operated
satisfactorily..
The system engineer
surmised that the piece of tie wrap was
located
above 'the relay .and
had simply fallen onto the
ESTR relay.
The other
-DG relay cabinets
were inspected -.for loose tie wraps and'ther foreign debris
and
none
was found.
\\
The inspector
asked the licensee, if this event. was:considered
to be
a valid
failure to start in accordance
with O-SI-4.9.A, Diesel Generator Reliability
And Start Log.
The licensee
stated that since the
DG had two successful
'tarts
before the event occurred,
they did not consider it to be
a valid
failure.
The inspector
reviewed .the,SI
ahd .Regulator'y:Guide
1.9 and concluded
that the event met the criteria,for being considered
as
a valid failure to
start
and should
have
been included in the
DG reliability. calculation.
Following .additional discussion,
the l.icensee
reached
the
same conclusion
and
classified this event
as
a valid failure to,start.
Subsequently
0-SI-4;.9.A
was performed to determine if any additional testing
was required.
Failure to
classify this event
as
a failure to start
and perform O-SI-4.9.A is
a
violation .of plant procedures,
however,
the significance is minor.
The
reliability did not change appreciably
and no additional testing
was required
due to the failure to start.
This violation is being treated
as
a Non-Cited
Violation, consistent with Section
IV of the
This
matter is identified as. NCV 50-260/95-60-03, 'Failure To Perform Diesel
Generator Reliability Determination.
5.3
Hoisture in Drywell Penetration
Guard Pipe
During routine tours of Unit 3 one of the inspectors
observed
moisture within
the"guard: pipe on reactor building- side-of- the-:SLC system-drywell- penetration.
This condition had.-previously
been
ques'tioned
by the inspector during the
walkdown of SLC..
On October 20, 1995,.:PER-951590-was-initiated-on
this- issue.
Technical. support personnel
reviewed the issue
and insulation
was removed.
The .water was initially attributed to condensation,
'.Several
days later, the
0
13
had dried except. for a small -amount of moisture at the drywell end
of the pipe.
The inspector noted that the re'fueling cavity had
been drained
.and questioned
engineering, personnel
on the source of the leakage.
The
inspector questioned
whether water may be leaking from the refueling cavity
bellows, which was leaking
down between the outside of the drywell liner and
the concrete shielding.
The inspector
was concerned that the construction of
the SLC:penetration
may be permitting water to leak into the penetration.
At
the end of this report period,
Engineering
was reviewing the issue.'o
immediate operability issues
were involved but potential corrosion issues
need
to be examined.
The inspectors will continue to monitor the licensee's
actions.
One noncited violation was identified.
6.0
Unit 3,Restart Activities
(37828,
61726,
62703,
87550,
92903)
(Unit 3)
The inspectors
reviewed
and observed
licensee 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
QA/QC activities.
Detailed observation of numerous testing
acti.vities
and other system recovery activities was conducted.
6.1
Unit 3 Refueling Operations
and Preparations
~6. 1. 1 Verification of Readiness
To Load Fuel
and Restart .
The inspectors
reviewed
a portion of the various licensee
procedures
and
documents
in preparation for fuel load into the reactor vessel.
Technical
Specifications
were reviewed to identify requirements
necessary
for the
Refueling mode.
The licensees
procedures
were then verified to contain
.actions or steps
necessary
to ensure
compliance with these specifications.
Test deficiehcies
were reviewed for various post-maintenance,
post--
modification,
and surveillance activities to verify that they'were
appropriately dispositioned.
No deficiencies
were noted.
Nuclear.
Instrumentation
surveillances
3-SI-4.2.C-1.2FT,
Instrumentation
That Initiates
Rod Blocks/Scrams
APRM Functional Test With Reactor
Mode Switch Not In Run
Position
and 3-SI-4.2.C-4(A), Instrumentation
That Initiates
Rod Blocks/Scrams
SRM .Calibration
and Functional Test, were reviewed following completion.
This
review verified the acceptance criteria was satisfied
and performed
a.
comparison with the
same procedures
applicable for Unit 2.
The Unit,3
procedures
are virtually identical with the Unit 2 procedures.
This is true
for the remaining nuclear instrumentation surveillances.
The Site Master
Punchlist
was reviewed for two systems to determine if items still existed
that were either coded for fuel load
and had not been
completed or were coded
for another milestone
but should
have
been
coded for fuel load.
No
discrepancies
were noted during this review.
On-November
16, the inspector
reviewed the open items for three safety,:.related,
systems:
EECM (System 67),
HPCI (System 73),
and
RHR (System 74) to"verify-
I
C
II
14
that all required work would be completed prior to restart.
The open
WOs for
the
same
systems
were reviewed.
The
WO review revealed
the following:
~Oe ~s
ECCW
22
ll
75
44
.
88
'59
The inspector did not identify any open items which would affect restart.
He
noted that all open lists were"very -dynamic as evidenced,
when the November .I7,-
SMPL printouts for the .three systems
were reviewed.
The updated
SMPL report
listed fewer open items.
The inspector
met with the respective
system
engineers
and their manager to discuss
changes.
The discussions
revealed that
significant changes
in the number of open items was
a function of timely
updating.
The system engineer's
system health report was also reviewed.
There
was correlation
amongst the data.
The inspector concluded that the
licensee's
review process
to address
work to be performed after startup
was
adequate.
6.1.2 .Unit 3 Drywell Closeout
Inspections
Throughout the recovery of Unit 3, the inspectors
have. monitored. the'ondition
of the Unit 3 drywell and torus.
Numerous tours were taken in both areas.
On
November 8, the inspectors
performed
a detailed
walkdown of the Unit 3 drywell
and compiled
a list,of deficiencies
needed to be corrected prior to restart of
the Unit.
These
items included
numerous
housekeeping
items,
a loose
electrical junction box cover,
a loose yoke bolt on
a
RBCCW valve, loose
~electrical outlet covers,
debris in floor drain screens,
and two sensing lines
on the
B main steam line appeared
inadequately
supported.
These
items were
turned over to the licensee's
drywell closeout .coordinator.
All items were
corrected with the exception of the sensing lines
on the main steam lines.
The sensing lines were .evaluated
as acceptable
by site engineering
personnel.
A regional str.uctural
inspector, also reviewed this issue
and determined that
the licensee's
conclusion
on this matter was acceptable.
On November
17, the
licensee
performed their:final drywell closeout inspection in accordance
with
3-GOI-200-2, Drywell Closeout.
An inspector
accompanied
.the licensee
during
the .walkdown and noted that the drywell..was in good condition and acceptable
for restart.
On:November
17,
one of .the inspectors
performed
a final drywell walkdown of
the Unit 3 drywell with the plant manager
and assistant
plant manager.
The
inspection
covered all levels of the drywell.
The condition of the drywell
was quite good.
The inspector
found
a tie wrap,
a cotton glove, several
pieces of wire,, and several
pieces of tape.
The inspection did not identify
any tools or miscellaneous
hardware.
The condition of the drywell was
among
the best that the inspector
has observed
during
a final walkdown.
Additional discussion of inspection involving drywell conditions is included
in paragraph
8. 18 of .this report.
0
15
6.1.3 Nuclear Safety Review Board/Senior
Management
Assessment
of Browns Ferry
Readiness for Unit 3 Restart
and Multi-Unit Operation
On November 7, l995, the inspectors
attended
the combined
NSRB/SMART meeting
,to monitor the licensee's .senior
managements
final review of the Browns Ferry
Site (staff, programs
and hardware)
readiness
for Unit 3 restart
and multi-
unit operation.
The site's
Vice President
presented
an overview of, the status
of the Unit 3 recovery.
Items discussed
included restart
and post-restart
.regulatory issues,
self assessments,
maintenance
backlog, plant material
condition,
power ascension
plan,
and. emerging issues.
Detailed presentations
were then
made
by the plant manager
and engineering
and materials
manager.
Topics of discussion,
in addition to th'e =above mentioned
items,
included
assessments
of the various plant departments/systems
readiness
for restart,
open engineering
issues,
and emergent restart
issues.
The emergent
issues
included the recent
component mispo'sWioning;;events,(see,paragraph
2.3)
and
a
control rod drive, problem which necessitated
the .disassembly of the reactor.
The assistant
plant manager
discussed
the work remaining
on Unit, 3 and the
licensee's
goal to have their backlog below 600 work items prior to restart.
The
ORRT team leader also
made
a presentation
to the boar@
He stated that
all of .the
ORRT issues
had
been resolved
and
made
a recommendation
to the
board
and President,
TVA Nuclear that Unit 3 be allowed to restart.
In
addition, the site
NA&L manager
discussed
all open
NRC items
as well as the
status of the
gA oversight of the recovery of Unit 3.
The
NA&L manager stated
that all .gA issues
had
been resolved
and that the unit was ready for restart
from a gA perspective.
The board/team
members
asked
probing
and pertinent questions
and received
comprehensive
and appropriate
responses.
The inspectors
perceived
the review
performed
by the
NSRB/SMART team
as thorough:and,comprehensive.
The final
resul.tant,-of
.the meeting
was
a recommendation
to the President of TVA Nuclear
that restart
be approved subject to the completion of all identified restart
items being tracked
by site -management.
6. 1.4
NRC Operational
Readiness
Evaluation
Team Issues
During the
ORAT, inspection
conducted
in October,. two issues
were identified in
which it was .determined that licensee
actions
and additional,NRC review prior
to 'Unit 3 -restart would be appropriate.
Both issues
were related to fire
protection.
The
ORAT identified that the procedural link. which instructed the operators
to
~
shut off ventilation fans to ensure that fire dampers
would close
was weak.
The instructions
were contained in the Abnormal Operating Instruction 30
series of procedures,
but there
was insufficient guidance to refer the
operators
to the AOI.
Additionally, when questioned
by ORAT inspectors,
several
operators
did not realize the importance of securing
fans to ensure
that=dampers,,go
shut..
The licensee
has revised related'procedures.
A new AOI', O'-AOI-26-1, Fire
Respons'e,
has
been written which encompasses
the AOI 30 proced'ures'in
one
procedure
and addresses
the actions to be taken
on
a fire.
The resident
inspectors
verified, that AOI 0-26-1 is present
in .the control rooms..
il
16
Operators that were questioned
on fire response
referenced
the
new AOI.
There
is
a red label
on the control
room fire panels
(Unit
1 and Unit 3) which
states
that AOI-26 is to be implemented
as required for actual fires.
The AOI
states
that actions regarding ventilation are to be taken
based
on the request
of the fire brigade leader.
The AOI contains
a list of switches to be operated
for the different areas
in the plant.
Operations
and fire leaders will be
briefed/trained
on the procedural
changes
by November 18,
1995.
Discussions
with fire protection
management
indicated that the dampers
in the reactor
buildings had
been
upgraded
such that they would shut against ventilation fan
flow if actuated.
The licensee
could not state th'at all control building
are designed to or tested to shut against
fan flow.
During the resident inspector's
review of the corrective actions,
an actual
fire occurred
(small fire in a trash
can in the turbine building).
Control
room actions
were completed
as required
by the procedures
and
PER 951722
was
initiated to address
the fire.
The inspectors
noted that the fire alarm in
the Unit 3 control
room was not of sufficient volume to be clear1y heard
above
the noise
caused
by several
ongoing activities.
The inspector
informed the
Unit 3 Restart
Manager
who responded
that the volume would be adjusted.
guestioning
by an
ORAT inspector resulted in the licensee identifying a
potential
problem involving two spurious valve failures.
The postulated
scenario
involved two
RHR valves spuriously opening during
an Appendix
R
event,
allowing
RHR pump discharge
piping to be drained. down.
The concern
was that this could cause
a water
hammer incident.
The licensee notified the
NRC operations
center of the condition.
Subsequently-,
the licensee
reviewed
the issue in more detail.
The licensee
concluded that, while Browns Ferry
fire protection .analysis calculations did include mor'e than
one spurious
failure, regulatory requirements'did
not require
more than
one failure to be
cons'idered.
The inspector reviewed the licensee's
commitment evaluation of
this aspect of GL 86-10,
Implementation of Fire Protection
Requirements,
and
found no. discrepancies.
On November
13,
1995, the licensee- retracted
the
50.72 notification 'on this issue.
The inspectors
concluded that these
two issues
were sufficiently resolved
such
that the involved equipment
and personnel
could support the restart of Unit 3.
6.2
Unit 3 System Testing
6;-2.1
Load Acceptance
Testing
The inspector
observed testing of the
3D
EDG on October 2,
1995,
and testing
of the 3A
EDG on October
3,
1995.
The testing
was performed in accordance
with procedures
3-SI-4.9.A.l.b-4 and 3-SI-4.9.A.l.b-l, Diesel
Generator
Emergency
Load Acceptance
Test.
The inspector
reviewed the procedures,
applicable portions of the
FSAR,
and
TS requirements
before observing the
testing.
The inspector reviewed the Baseline Test Requirements
Document (2/3-
BFN-BTRD-082) and concluded'hat
the test procedures
addressed
the
requirements
adequately.
The briefing prior to each of the tests
was highly detailed.
The test
director reviewed outlines of the entire evolutioy,
The.+scussjun.--..jocluded
~c'
W
i
O.
17
the test organization,
expected
system performance,
and contingency actions.
The
SOS was involved in the briefing.
Communications
were stressed.
B'efore
beginning the 3A EDG test,
a half scram condition on Unit 2 was discussed
to
ensure that no impact between the units was involved.
Other control
room
activities were suspended'o
minimize potential interference.
During the testing,
an i.ntercom line was operating
between the Unit I/2
control
room and the Unit 3 control
room.
High levels of plant management
.were present .in the Unit 3 control
room during the tests.
The inspector noted
good oversight of the reactor operators
by the
SROs.
Running
pumps were
monitored appropriately during the test.
Test'deficiencies
and emergent
equipment
issues
were 'identified and resolution actions promptly initiated.
Manipulations of the
EDG controls~encl'UtAig";the.. paralleling activities, were
well performed.
The inspector noted that the loads;,pieced'n
the:EDGs were
well below
the load limits.
During the trip of the 'RRR pump, the
responded
very smoothly.
The inspector:concluded .that .the testing
was
conducted
in a professional
.and highly controlled manner.
The inspector subsequently
reviewed the completed test
package for the
3A EDG
in detail during this report period.
The inspector reviewed the test recorder
printouts
and verified that the data
had
been accurately .interpreted
and
transferred to the data portions of the package.
The results
met the
acceptance
criteria.
The inspector confirmed that Test Deficiency (TD-Ol)
.which addressed
a failure of two 480 volt loads to trip on undervoltage,
was
appropriately resolved.
The inspector noted that the current
FSAR describes
the Unit 3
EDGs from the
perspective
of supporting Unit 2 operations,
not Unit 3 operations.
Licensing
management
indicated to the inspector. that
a revision to the
FSAR is planned
which would update this data.
J
The inspector reviewed the three documents
which describe
the current
analysis for BFN: NEDC-31580P
(Safety Evaluation in Support of Extended Valve
Stroke Times for Browns Ferry Units 1,2,3),
GE calculation
EAS-49-0889
(Evaluation of Extended Diesel Generator
Ready to Load Times).,
and
calculation
ND-.90000-89062.
The inspector confirmed that the
EDG testing
~
results
were in accordance
with the .assumptions
regarding
EDG start
and load
ti~es in. the documents.
--The
EDGs were .ready for loading much faster than the
analyzed limiting times.
The inspector
concluded that the testing verified that the Unit 3
EDGs were
capable of performing their safety functions under
LOCA loading conditions.
The preparation
and planning efforts, along with the careful
and well paced
execution of the testing,
led to overall
smooth performance of the testing.
6.2.2
Unit 3 Torus Penetration
Leak Rate Testing Verification
Between
November I and November 7,, l995,.
an. inspector .performed walkdowns of
the-Uni-t-3-Torus area in order to verify that various inside
and outside
diameter
torus. penetrations-.would-be"subjected"to
leak rate testing pressures
during performance of li'censee
surveill'ance
procedure,
3-SI-4.7.A.2.'a-f;
ILRT". Mhile the,inspector
observed that the, existing
~4
il
l5
18
would be adequately
tested,
the inspector
also noted the
following:
With the exception of three
(3) penetrations,
all other field-identified
were not adequately identified with field markings.
Five (5) penetrations
were not identified on the licensee's
dr awing.
Also three
(3) of the field penetrations
were not accurately reflected
on the drawing; i.e.,
an inerting sample return line penetration
was
listed
as. an "instrument tube"
on the drawing.
However, with use of
both the system drawing
and drawing "change/revision
papers",
most
-'=;penetrations
.could .be found and accurately classified.
Almost all of the system penetrations
have
been verified as correctl'y
marked in accordance
with SSP-8.7
(Rev 8), "Containment
Leak Rate
Programs",
Appendix J; i.e.; the field penetration
indications. match
those penetrations
listed in SSP-8.7.
No major penetration identification deficiencies
were found by the inspector
and it was the inspector.'s
under standing, after discussions
with the system
engineer,
that field marking of these penetrations will be performed
soon.
The inspector also noted that incorporation of inspector
8 licensee-identified
drawing discrepancies
are to be'erformed
in the near future.
The inspector
intends to continue monitoring of the licensee's
progress
in this area.
6;2.3
Unit 3 Reactor
Vessel Hydrostatic Pressure
Test
One of the inspectors
observed
the conduct of Procedure .3-SI-3.3.1.B:
Hydrostatic Testing
as test pressure
was approached.
The inspector verified
that temperature
and .pressure
monitoring:.was being .performed as:required
by
TS.
The inspector verified that the temperatures
being monitored
and recorded
would confirm compliance .with TS figure 3.6-1 (curve I). 'The operator
was
knowledgeable
regarding the
TS requirements
and location of the temperature
detectors.
The inspector
noted that one narrow range suppression
chamber
water level
was slightly lower than the administration limit in Procedure
3-
SI-2 (-5.5 inches).
The SI requires
only -daily verification of torus level.
The
TS limit is -6.25 inches.
CR operators
increased
suppression
chamber
.
level in response
to the inspectors .questions.
After test pressure
of 1014
,psig was attained,
the inspector walked down the Unit 3
SDV system.
The
inspector
observed
numerous
and reported the
observations
to maintenance
personnel.
Work Requests
were initiated for
repairs.
The inspector
reviewed the completed surveillance test
package for the Unit 3
reactor vessel
hydrostatic test which was signed off on November
13,
1995.
Licensee
procedure '3-SI-3.3:I.B,
ASIDE Section
XI Hydrostatic Systen
Pressure
Test of the Reactor
Pressure
Vessel
and Associated
Piping
Class. 152),. control:led-the-..test-.-
Four-test- deficiencies-were written to
identify six valves which 'coul'd not be cycled due to operating=limitations-.
'
~
~
~
~
~
~
~
~
~
~
~
gC inspectors
performed
a VT-2 inspection
on the reactor vessel
and associated
,piping .
They inspected
215 val.ves .and, fittings.
Fifty had leakages, in excess
of 35 drops per minute.
gC identified leaks ranging- from weeping .:gg.,one
i5
iN
0
19
gallon per minute
(gpm) for a valve packing.
Work orders
were written to
tighten fittings and to tighten or replace
The licensee
reduced
system leakage to a level which they expect will result in a system
leakage of less
than
one
gpm at restart.
Leakage at the
CRD under vessel
was brought to the vendor limit of less
than 30 drops per minute for
all but one flange.
Leakage at the
when tightened.
WO 95-2086-02
was written to replace
the o-ring for CRD 10-47 which. was
completed
on November
12.
The inspector
noted that all valve manipulations
were verified to be in the specified position.
The review di.d not identify
any deficiencies.
On November
17, the inspector attended
the
JTG meeting which addressed
interim
test results for several
Power Ascension Tests.
The JTG was thorough
and
indepth questions
were asked.
There were no issues
identified which would
affect restart
but two test reports
were remanded
back to the system engineer
for clarification.
The inspector considered that the
JTG provided the
licensee
a good indepth cross discipline review of startup test issues.
6.2.4 Unit 3 Fire Protection Surveillance
and Post Modification Testing
Surveillance Instruction O-SI-4.11.G. l.a, "Inspection of Fire Rated Barriers"
was reviewed
by the inspector to verify procedural
and performance
adequacy.
The SI inspection
was performed to verify the functional status of fire rated
seals installed in the Unit 3 Reactor Building under
DCN W18196 to
support Appendix
R safe
shutdown
system separation.
The completed test
was
examined for necessary
test prerequisites,
instructions,
acceptance
criteria,
technical
content,
authorization to begin work, data-.collection,
handling of
deficiencies
noted,
and review of completed work.
The test
was inspected to
determine that approved
procedures
were available,,prerequisites
were met, the
test
was conducted
according to procedure,
and test results
were acceptable.
The SI package,
SI performance
and surveillance results
were satisfactory.
'our SI test deficiencies
were identified.
Corrective actions
had
been
initiated and given proper status.
6.3
Seals8 -+ 'v>
In the Browns Ferry Fire Protection
Report
(FPR) Section 3.0,
TVA committed to
mechanical
pipe
and electrical conduit
and cable tray penetration
seals that
are qualified by meeting criteria that:
(1) are tested
and Underwriters
Laboratory
(UL) Listed or otherwise
approved
by
a recognized
independent
testing facility; (2) the penetration
seal
design
and installation was
previously approved
by the
NRC; or (3) the seal
design
has
been evaluated
and
approved
by a qualified fire protection engineer.
In the review of penetration fire stop seals,
the inspector
used the
criteria,
Design Critetia BFN-50-799, "Fire and Pressure
Seal Selection",
and
recognized
industry penetration fire stop seal testing guidance of American
Society for Testing
and Naterial
(ASTH) Standard
E814-1988,
"Standard
Test
Hethod for Fire Tests of Through-Penetration
Fire Stops'"
and Institute of
Electrical
and Electronics
Engineers
(IEEE) Standard
634-1978,
"IEEE Standard
Cable Penetration
Fire- Stop-equal.ification Test".
The inspector reviewed the
typical
BFN mechanical
and electrical penetration
-seal installation
0
20
procedures,
installation drawings
and details, quality control
(QC)
and
quality assurance
(QA) installation records,
GL 86-10 fire protection
evaluations,
and
TVA testing data for a sample of 13 typical mechanical,
electrical conduit,
and cable tray penetration
seals identified in Attachment
1 to this inspection report.
These
seals
were reviewed to determine that the typical installed plant seal
configurations
were representative
of those .utilized in TVA's fire seal
qualification tests.
The penetration
seal
samples
were established
by an
inspector walk down of fire barriers associated
with Fire Areas 3, Fire Zones
3-1, 3-2, 3-3 and 3-4; Fire Area 16; Fire Area'9,
and Fire Area 25.
The fire
barriers
represented
10 CFR 50 Appendix
R fire barrier separation
in those
areas for required safe
shutdown
components of the
RHRSW"and <<ECCW systems.
The typical seal
sampl'es
were representative
of about
80X of the plant seal
installations.
ay
No discrepancies
were identified by the inspector in the review of the
seal installation procedures,
the
QA/QC records
associated
with
those seals
inspected,
and the penetration
seal qualification tests.
Also, no
discrepancies
were identified by the inspector
during the visual inspection of
the seal installations.
However, during the seal- review,
TVA engineerin'g
personnel
identified that the installed configuration of 'MP-3 penetration
seals
was not consistent
with the typical seal detail
dr awing 3-47E3392-628.
The top damming material for floor seal installations
was not installed
as
t
.shown in the typical detail drawing.
Additional seal material
was installed
to the top of the penetration
TVA BFPER951455
was written to address
the lack of the top damming material for typical NP-3 floor seal
installations.
Based
on the review of the fire:barrier penetration fire stop seals,
the
inspector
concl,uded the'-following:.
The penetration
seal qualification tests for mechanical
pipe
and
electrical
conduit seals
met minimum industry test guidelines for
significant test parameters.
The test
specimens
in qualification tests reports'were
representative
or
adequately
bounded the installed as-built, penetration
seal
configurations.
The qualification tests
bounding conditions for the significant fire
barrier penetration
seal material
and design attributes
(e.g.
type of
seal material,.sealant
density, location
and type of damming boards,
and
location
and type of penetrating
item) were clear.
The tests
sufficiently established
a fire propagation qualification rating of the
seals.
Electrical cable tray penetration
seal
desi'gn at .Browns Ferry have not
been tested/approved
by a recognized
independent- testing facility nor
tested" to-approved-industry
standards.
The. cable. tray. penetration.-seal-
design
was
based
on fire tests
conducted
by TYA and approved
by
NRC in
Part X, Fire Recovery Plan
. These tests
demonstrated
.the..adequacy
of a
ik
I~
21
seal
design that prevents
flame occurrence
on the unexposed
side of the
barrier seal for a fire condition representative
of in-plant combustible
loading.
Additional TVA engineering
evaluations
indicate'd the design
was comparable to a
UL Listed design
and acceptable.
6.4
Station Blackout Rule Unit 3 (92701)
10 CFR 50.63 requires that:plants
be able to cope with a loss of alternating
current
(AC) power sources.
Regulatory
Guide 1.155 defines which AC sources
must
be postulated
to fail, specifies the required coping duration
and
provides guidance
on how to demonstr ate that the station blackout
(SBO) rule
.. '-...has
been met.
The licensee's
latest submittal describing their approach to
meeting the
SBO rule was
made
on April 28,
1992.
The
NRCs safety..evaluation
was issued
on September
16,
1992.
On June
12 16,
1995, the
NRC con'ducted
an
on-site inspection of the
SBO rule for Unit 3.
The
NRC Inspection
Report (95-
34) states that violations or deviations
were not identified,
and lists items
that
had not been completed.
During this inspection
(October
1995) these
outstanding
SBO items for Unit 3 were addressed.
The licensee's
basic coping
strategy for SBO was to run HPCI and
RCIC systems
independent
of AC power on
.the blacked out unit and reenergize
necessary
HVAC equipment within one hour
through
"excess
capacity" diesel
generators.
The licensee's
procedures
for responding to a station blackout event were
contained
in Abnormal Operating Instruction O-AOI-57-1A, Loss of Offsite Power
(161
and
500 kV) / Station Blackout,
Rev 35, dated
September
12,
1995,
and
Transmission
Emergency
Plan,
dated
March 1,
1993.
The inspector
reviewed these
procedures
and found they met the requirements
of the .SBO rule.
The inspector verified by inspection of the:batteries
that the
new larger
batteries
required to meet the
SBO rule -had .been instal.led.
The inspector
verified through review of drawings .and inspection of;distribution panels
in
the, plant that
DC loads
had:been
removed .and/or relocated .as necessary
to
allow the batteries
to .provide the necessary, power for four hours:without'he
need for manual
shedding of loads.
=-'3he inspector verified that the battery
loading calculation supported
the design basis of multi-unit -operation
and
incorporated factors for temperature
correction,
design, margin
and aging
consistent with the
SER.
To address
the issue of loss of ventilation during
an
SBO event, the licensee
generated
Calculation MD-(0031-930059,
Control
Bay Transient Analysis - Loss
of HVAC, Rev 0, dated July 12,
1993,
and Calculation MD-N0999-890021,
Loss of
Ventilation during Station"Blackout,
Rev 3, 'dated
March 31,
1992.
The
inspector reviewed these calculations
.and observed that the temperatures
in
the control
bay,
HPCI rooms,
RCIC rooms
and the main steam tunnel
were
calculated to remain at acceptable
levels during
a postulated
SBO event.
Also, Calculati'on
BFNAPS4-004,
Appendix .R - HVAC Review,
Rev 0, dated
December
6,
1988,
demonstrated
that temperatures
in the swi.tchgear
rooms would remain
at..acceptable
levels:during--a- postulated
SBO event.
The license
had addressed
the issue of containment isolation capability
associated
with a
SBO event through Calculation ND-N0999-890021,
Station
Blackout Equipment List, Rev 4, .dated January,2$ ,
$ 995.
,As
a result of the
0
il
22
analysis
in this calculation, certain valves are included in AOI-57-1A to be
position -perified by the operators.
The inspector
concluded that the
recommendation
in the area of containment isolation valves
had
been fulfilled
by the licensee.
The inspector concluded that the licensee
had provided sufficient training to
operators
on the subject of coping with an
SBO event.
Training plans
OPL173R200
and
OPL173S116 outlined the classroom
and simulator training for
SBO.
In addition,
Job Performance
Measure
No.
166 provided for training
personnel
to observe
operators
walking through the AOI-57-lA steps
performing
realignment of power sources
to re-energize
HVAC equipment
from available
diesel
generators.
The inspector reviewed diesel
generator start
and run failure records
and
unavailability,
and observed that the target reliability was being maintained.
Overall, the inspector concluded that the licensee
had implemented the SBO-
rule for Unit 3 in accordance
with the
SER.
There were
no outstanding
items.
6.5
Appendix
R Post-Fire
Safe
Shutdown Capability Safety Evaluation Report
Follow-Up Items
NRR review of the licensee's
proposed post-fire safe
shutdown capability,
as
described
by a December
20,
1994 submittal of the Fire Protection
Report
(FPR)
for simultaneous
operation of Units
2 and 3, identified three
items which
require verification by inspection prior to restart of Unit 3.
These
items
are:
1.
Verification that the next revision to the
BFN-FPR reflects the results
of the most recent cal'culations of maximum drywell temperature.
2.
Verification of the manual
action to transfer the
RCIC system suction
from the condensate
storage
tank to the torus from outside the control
room.
3.
Verification that
new manual
actions that
may be required
as
a result of
the
RWCU system modifications have
been considered
in the licensee'.s
listing of principal
manual
actions
and time frames.
With regard to inspector follow-up item I, inspection confirmed that the
licensee
has
documented
the required
changes
to address
the maximum drywell
temperature
calculation in the
The licensee
has drafted
a
revision to incorporate the required
changes,
and is tracking these
changes
as
an open item (Punchlist
Item REC-0208) to ensure
implementation
before
BFN.
Unit 3 restart.
Inspection confirmed the changes
are appropriate.
The
licensee's
open item tracking provides reasonable
assurance
the required
changes will be completed
as required.
Therefore,
inspector.fol-low-up-item I
is closed.
t
With regard to inspector fol-low-up. item 2; the licensee
provided information
from procedure
2/3-SSI-16,
which provides instructions for the manual
actions
to transfer the
RCIC system suction to the torus.
Inspectors--confirmed
the
Ik
23
instructions
accomplish this action outside the control room.
Therefore,
inspector follow-up item 2 is closed.
For inspector follow-up item 3, the licensee
provided draft changes for
procedure
2/3-SSI-3-3,
specifying manual actions required for operation of
components
isolating high temperature
piping from low temperature
components.
The licensee
also provided draft changes
.to the
Unit 3 configuration.
These
items are being tracked
as part of Pun'chlist
Item REC-0195.
Inspection confirmed the changes
are appropriate.
The
licensee's
open item tracking provides reasonable
assurance
the required
.'changes will 'be completed
as required.
Therefore,
inspector follow-up item 3
is closed.
These conclusions will also
be documented
in the
NRR safety evaluation of the
.'BFN post-fire safe
shutdown capability.
6.6
Review of Electrical Calculations for Unit 3 (TI 2525/lll)
The Electrical Distribution System Functional
Inspection
(EDSFI) was conducted
in 1992
and documented
in NRC Inspection
Report 50-269,
270, 296/92-15. 'he
EDSFI concentrated
primarily on Unit 2 and shared
systems.
The purpose of
this current inspection
was to review those
areas of Unit 3 electrical
systems
design not reviewed during the .EDSFI or during previous Unit 3 restart
inspections.
The sample of calculations
selected
by the inspector for this
review excluded those calculations
which had been 'inspected
in previous
inspection efforts.
These
included fuse .calculations,
thermal
overload
calculations,
and cable,ampacity
calculations.
The inspector reviewed the following calculations:
.
'D-Q0057-920034,
4 .KV and 480
V Busload
and Voltdrop
ED-Q3057-920035,
Diesel
Load Study
.ED-Q3057-920036,
480V System,
Motors and:Miscellaneous
Loads Voltage Drop
ED-Q3999-930130,
Unit 3 Slow Bus Transfer
ED-Q0057-910236,
4KV Short .Circuit
ED-Q3057-910237,
480V Short Circuit
ED-Q3082-920354,
Undervoltage Analysis of Electrical Auxiliary System During
Diesel Generator
Load Sequencing
ED-Q3999-910224,
Cable
and
Bus Protection/Breaker.
Coordination for 4KV
Switchgear
and
480
V Loadcenters.
The inspector
reviewed-.each
of these calculations for accuracy
and to ensure
the calculation
scope
encompassed
the design basis of the electrical
system.
The inspector also reviewed
each of the problems identified.'n th'
calculations to ensure that they:were .being corrected
or had
been corrected
by
0
0
I~
24
the Unit 3 restart effort;
'The inspector did not identify any calculation
errors
or
any .problems that were not being adequately
addressed.
This item is
closed for Unit 3 restart.
7.0
Procurement
Engineering
Group (IP 38703)
The object of this inspection
was to review the program
and results, of the
commitment
made in the Nuclear Program Plan
(NPP), dated October 24,
1988,
regarding Section
12.0,
Component
and Piece 3?art Qualification for Unit 3.
The original commitment stated
two goals: "
,Goal
1:
BFN will verify that 'previously. environmentally qualified.
equipment
has not been degraded
through the use of spare
and replacement
items.
'oal
2:
BFN will establish.
programs
and practices that will ensure that
,previously qualified equipment will not be degraded
in the future
through the use of spare
and replacement
parts:
Goal
2 for the evaluation 'of installed
commercial
grade .replacement
items
and
remaining inventoried commercial
grade
spare parts
was revised
as stated
below
and the Goal regarding installed material
was withdrawn based
upon Generic Letter 91-05,
issued April 9,
1991.
The revised
Goal
2 was restated
as
follows:
Establish administrative controls to ensure that in-stock commercial
grade
items will not be issued for installation in a safety-related
app1ication
unless
they have
been evaluated
in- accordance
with the
established
site procedure.
Goal
1 addressed
the qualification program for safety-related
components
in
.
10
CFR '50.49
(EQ) applications..
Goal.
2. addressed
safety-related
components
in
non-10
CFR 50.49 applications.
BFN Procurement
Engineering
Group
(PEG)
had
completed all actions,
as originally committed for Goal
1, to ensure that
previously
EQ equipment
had not been
degraded
through the use of spare or
'eplacement
parts or items.
The inspectors
reviewed the closure submittal for
Goal
1, which listed four open items which were required to be closed prior to
BFN Unit 3
EQ certification.
PEG indicated that one item, related to the
closure of two PERs which was to be tracked
and closed separately,
had already
been
accomplished.
A second
item, issuance
of an EQ.binder
(Cabl-0053)
had
been completed.
The remaining
two open items, related to maintenance
work
order review,
and incorporation of field walkdown sheets
into
EQ binders,
were
targeted for completion
on November 3,
1995,
and
November 8,
1995
respectively.
These
two items were closed
by TVA as planned.
The inspectors
concurred with the completion of Goal l.
BFN had establ.ished
barriers
and procedures 'to"ensure that in.-.,stock commercial.
grade
equipment,
Goal
2 items, .will not.be issued-.for -instal.lation. in a
safety-related
application
unl.ess. they have
been evaluated
in accordance
with
SSP-10.5,
"Technical Evaluation for Procurement
Materials
and Services,"
Revision.
9. and .O-TI=.329, "Evaluation of Components
an Piece Parts
Procured
il
il
il
25
Prior to the Implementation of BFNP Commercial
Grade Dedication Program,"
Revision l.
issued April 9, 1991, states "...the
(NRC) staff does not
expect licensees
to review all past procurement."
Therefore,
TVA revised the
scope of their commitment which was issued
October 24,
1988, to exclude the
review of those
non-Eg items that were installed prior to October
1,
1988.
(The selection of October
1,
1988,
as
opposed to April 9,
1991, is
conservative.)
7.1
Summary of Actions Taken to Complete
Eg Equipment,
Goal l.
This activity was accomplished
by:
1)
Reviewing the plant's maintenance
history to identify the
activities that have replaced safety related
components
or items.
2)
Performing
an evaluation of replacement
items that have
been
installed in 10 CFR 50.49 systems.
3) 'Performing
an evaluation of the
10 CFR 50.49 inventoried
commercial
grade
(and/or ANSI N45.2) spare parts to assure that
th'eir subsequent
use will not degrade
previously qualified
equipment.
This process
was implemented
and controlled by site approved
procedure 0-TI-
329,
"Evaluation of Components
an Piece Parts
Procured Prior to the
Implementation of BFNP Commercial
Grade Dedication Program," Revision
1.
4)
Taking credit for existing programs that qualified
Eg components
by walkdown.
5)
Taking credit for Eg components qualified by evaluations.
6)
Taking credit for Eg components, replaced
by DCNs.
For all components
evaluated
by the Unit 3
Eg Project,
evaluations
were
controlled by PI 88-11,
"Preparation,
Haintenance,
and Control of
Environmental gualification
.Documentation
Packages
(EgDPs)," Revision 6,
Section 4.2.9.
7.2
Summary of Actions. Taken to Complete
Non-Eg Equipment,
Goal
2.
The original commitment approach to satisfy these
goals
had
been formulated at
a point in time when the impact
on qualification of the host components
and
plant safety at
BFN and throughout the. industry- had not been firmly
established.
Therefore,
the commitment included review of past
procurement
for items installed in the plant,
as well as items still. in inventory.
Since
that time however,
Generic Letter 91-05. had been
.issued. which established
that
licensees
were not expected to review all past
procurement
unless
problems
with a specific vendor's or supplier's
products
were found during current
procurement activities.
26
Since the time that
TVA made the original commitment,
several
other changes
had also occurred.
Primarily, the scope of items
had changed
because
a
significant number of items that were installed prior to October
1,
1988,
had
been
removed
from service
due to extensive
design modifications
and normal
maintenance
of plant equipment.
Procurement of replacement
commercial
grade
items subsequent
to October
1,
1988,
had
been specified
and accepted
so
as to
be consistent with the industry
(EPRI) guidance that was endorsed
by NRC in
and later discussed
As
procurement
engineering
processes
had improved, the population of remaining
items decreased.
Since that time, replacement
commercial
grade
items
had
demonstrated
satisfactory in-plant performance with no adverse
trend to.
suggest that items were replaced
due to inherent part defects or non-
conformance.
Improvements of site 'procurement
engineering
processes;at
BFN,
and other
activities
had
been
implemented to gain additional
assurance
that installed
commercial
grade
items:would perform as designed
and not degrade
the
qualification of their host components.
These actions
had included evaluating
commercial
grade
items to determine
the extent to which inadequate
engineeri.ng
involvement in the procurement
process
may have resulted
in either the
improper classification of items, the incorrect specification of items, or
incomplete acceptance
documentation;
and evaluating the extent
commercial
grade
items
had
been installed in applications
other than those for which they
were previously evaluated.
The resul.ts of evaluations
performed indicated that in only 3 out of
approximately
1300 reviews did previous procurement
processes
and
documentation result in items that
had degraded
the original qualification .of
their host components.
These
items were further .evaluated
under TVA's
Corrective Action Program
and none
had created
a plant operability concern.
The results
indicated that 1) commercial
grade
items were installed in safety-
related: appl;ications for which they were evaluated,
and
20 gA Level
3 items
(installed in a safety-related
component for which it was not original=ly
designed),.
were suitable .for their installed applications.
Using the
NRC guidance of Generic Letter 91-05
as
a basis,
and the assurance
gained
from years of -satisfactory in-plant performance of remaining pre-
Octobei
'1,
1988,
commercial
grade replacement
items,
BFN concluded that
further review of .installed commercial
grade
items
was
no longer necessary
to
ensure that previously qual.ified equipment
was not degraded
through the use of
these
items.
Therefore,
the original concern identifie'd in NPP Volume III had
.been resolved.
Continuous
improvements
made to
BFN procurement
processes
since October
1,
1988, extensive site-specific evaluations of past
procurement
performed to date,
and lessons
learned
from similar evaluations
in the nuclear
industry since
1988 supported
these
conclusions.
Goal
2 addressed
commercial
grade
items
(gA2 items) which were in 'inventory
and intended for safety-related
application.
The substance
of the commitment
remained
unchanged
because
the revision simply clarified the original
commitment
and provided more detail to facilTtate closure.
0
0
27
The revision allowed for closure of the commitment
by using, administrative
controls which prevent issue of commercial
grade
items for safety-related
applications
unless
they had
been evaluated for those specific end uses.
Examples of the controls which had
been applied to the items are to down-grade
to gA3 or gAO, surplus,
or put the items
on hold.
The inspectors
toured the
warehouses
and noted that the
gA2 items had
been
tagged with appropriate
hold
tags.
The revision also specified that technical
evaluations
would, meet
either plant-approved
procedure
SSP-10.5
or TI-329.
SSP-10.5
was the process
by which safety/quality-related
items were currently procured,
and met current
industry guidance.
TI-329 was the procedure
developed to evaluate
past
procurement (prior to October
1,
1988) of commercial
grade
items for use in
safety-related
applications.
7,3
Verification of the Piece Parts gualification Program
and Results
The Inspectors verified. the program
and results
by reviewing the procedures
used to accomplish the goals.
These were:
O-TI-329, "Evaluation of Components
and Piece Parts
Procured Prior to
the Implementation of BFNP Commercial
Grade Dedication Program,"
Revision
1.
SSP-10.5,
"Technical Evaluation for Procurement of Materials
and
Services,"
Revision 9.
PI-88-11,
"Preparation,
Maintenance,
and Control of the 'Eg Documentation
Packages,"
Revision 6.
SSP-10.2,
"Material Receipt
and Inspection," Revision
14.
The inspectors
met with various managers
and supervisors
involved in the
procurement
piece parts
program,
which included Nuclear Stores,
PEG,
Procurement
Engineers,
Purchasing
personnel
and gA/gE personnel.
During these
meetings
the process
and results
were described
.in detaij..and
any questions
regarding the program were satisfactorily .answered.
The inspectors
reviewed
'ssessment
NA-BF-94-114, "Special
Assessment 'of:the:Evaluation of Components
and Piece Parts
Procured Prior to the Implementation of Browns Ferry Nuclear
Plant Commercial
Grade Dedication Program," dated
September
7,
1995.
The
assessment,
performed
by guality Engineering,
was to verify that components
and spare parts associated
with 10 CFR 50.49 equipment
were being adequately
evaluated
to -ensure the
Eg status of BFN3 was not degraded.
The assessment
reviewed the scope
and adequacy of the evaluation,
contract requirements,
work
history review,
and engineering
evaluations.
The assessment
identified
several
deficiencies related to review of, supporting documentation
and
previous evaluation,
identification of references,
and work history reviews,
and documented
the deficiencies
on
PERs.
PEG had addressed
the
PERs
and
was
preparing to close
them out.
The inspectors
also discussed- the assessment
with the-'equal-i;ty,- Engineering-'personnel.
involved 'who indicated that they had
concluded that the assessment
had
shown
PEG to be adequately
meeting the
requirements
of the implementing procedure..
0
0
28
In addition, the inspectors
reviewed several
evaluations that
PEG had
performed of inventoried
10 CFR 50.49 replacement
.items
and concluded that
PEG
had performed
adequate
evaluations
.in accordance
with applicable the
procedures.
Examples
as the reviewed evaluations
are
as follows:
Evaluation U3IEG-006, dated July 8,
1995, for Valcor Solenoid Valve
Model V526-529-2,reviewed
several
components
including
a switch block
assembly, coil, and ceramic rectifier.
For the Valcor components,
PEG
had concluded that the
POs for the replacement
items
had not imposed the
proper documentation
requirements for use in 10 CFR 50.49 applications,
the components
were not qualified for use in a
10 CFR 50.49 environment,
and .placed the inventoried components
in surplus.
Evaluation U3IEG-007, Revision 1, dated
September
27,
1995,
reviewed
a
Rosemount
Pressure
Transmitter
Model
1153 Series
B which included
an
electronic
assembly
hardware kit, adjustment
screw kit, valve stem,
and
sensor, module.
PEG had concluded that the
Rosemount transmitter
components
were acceptable
for Eg applications.
Evaluation U3IEG-004, Revision
1, dated August 25,
1995,
reviewed
SOR
Flow Switches
Models 103AS-B212-NX-JJTTX6,
103AS-B202-NX-JJTTX6',
and
103AS-B803-NX-JJTTX6, which included components
o-ring and cov'er
gaskets'.
PEG had concluded that the
SOR Flow Switch components
were
acceptable
for Eg applications.
A walk-through inspection .of the warehouse
was also conducted.
The warehouse
space
was impressive in that"it,was very clean.,an
wel,l organized.
Material
and items were labeled
and tagged
These discussions
and review of procedures listed, above,
review .of Assessment
NA-BF-94-114 and discussion with gE personnel,
review of the
PEG evaluations
for inventoried
Eg parts,
arid inspection of the warehouses
led the inspectors
to concl'ude that the program in place
was adequate
and satisfactory to
complete the goals.
Based
on the procedures
reviewed, discussions
with licensee
personnel
and
observations
by the inspectors it is concluded that the commitment,
as
amended,
.in the
NPP is satisfied sufficiently for restart of Unit 3.
The
ongoing program to release
gA2 items
on hold currently held in inventory is
acceptable
as
a basis of control to ensure qualification of installed
materials or parts.
7.4
Procurement of Structural Material
By TVA From Mid-South Nuclear
A potential
problem was identified during an
NRC inspection of Mid-South
Nuclear,
Report
No. 99901270/95-01,
dated. September.-27,-
1995, related to the
purchase
of 2 inch, schedule
160,
ASME SA-106,
Grade
B piping.,
The .problem
identified that the -possibility existed-that all cri'tica1 characteristics
required to dedicate commercial'rade
materials for safety-related:
appl-ications
may-not have-been
appropriately
addressed.
IS
0
0
29
The
NRC report,
No. 99901270/95-01',
was received
by TVA Corporate
on October
23,
1'995,
but had not yet been distributed
by TVA to
BFN such that
BFN had no
knowledge of the potential
problem.
The report findings were discussed
with
PEG management
and it was discovered that
a section of the pipe in question
had
been released for a safety-related
application in BFN Unit 3.
Immediately
upon discovery the licensee
segregated
and tagged the remaining pipe in
inventory to prevent further
use
and the operation shift supervisor,
on duty
was notified of the discovery.
PER 951611
was prepared to initiate corrective
actions.
The licensee
determined that the
critical characteristics
test that was
lacking .was
a tensile properties test.
Therefore
a section of the inventoried
p1pe
was submitted to TVA's central laboratory for performance of this test.
The'test
was performed
on October 27,
1995,- and the results obtained
met the
tensile properties for ASME SA-106,
Grade
B, schedule
160 specifications for
seamless
carbon steel
pipe.
'ven though the material
was determined
acceptable
for use at
BFN, the
remainder of pipe was transferred to the scrap yard..
By scrapping
the
, material
and receiving acceptable
test results,
the
BFN PER 951611
was closed
and
removed
from the Unit 3 restart list.
TVA Corporate Materials Engineering
Group has
issued
a separate
PER,
CHPER 950128, to evaluate this problem from a
generic view and extent of condition.
One hundred
ASME Section III purchases
from Mid-South Nuclear for the past yea'r were identified and from these
20
were examined in detail to determine if any code compliance
problems existed.
.Results
were negative,
that is no code compliance
problems were identified.
Therefore this issue is resolved
as it relates to BFN3 restart.
No violations or deviations
were identified.
I
8.0
Review of Open
Items
(92700)
(92901)
(92902)
(92903)
(92904)
~
.
g.
he
open items listed below were reviewed to determine if the information,
provided met
NRC requirements.
The determinations
included the verification
of compliance with TS and regulatory requirements,
and addressed
the adequacy
of the event description,
the corrective actions
taken',
the existence of
potential generic problems,
compliance with reporting requirements,
and the
relative safety significance of each event.
Additional in-plant reviews
and
discussions
with plant personnel,
as appropriate,
were conducted.
8. 1
(CLOSED)
Reactor
Scram Resulting
From A Turbine Trip Due
To A Sensed
Generator
Load Unbalance Condition Caused
The Actuation Of
The
ESF System.
On February 9,
1995,
a reactor
scram occurred
when the main turbine tripped
due to a stator cooling leak causing operation of a generator field ground
relay.
The water was leaking from the cooling water supply. mani.fold for the
generator rectifier"and. dripped onto rectifier electrical
components -creating
an electrical
path to ground.
The leak was repaired
and potentially damaged
=--components. were- repaired or replaced.
Preventive maintenance'o.
inspect
cooling water components
susceptible
to degradation
has
been
scheduled
to be
performed every eighteen
months.
In addition, the licensee
defeated
the main
0
30
generator
and turbine trip functions which are generated
by the operation of
the generator field ground relay.
The annunciator function due to this
condition is, unaffected.
This will allow time for operator action,to isolate
the ground
and perform repairs withou't experiencing
a generator
and turbine
trip.
8.2
(CLOSED)
Reactor
Scram Resulting
From Personnel
Error
During Surveillance Testing
Caused
The Actuation Of The
ESF System.
On March 30,
1995,
a reactor
scram occurred during the performance of
surveillaTfce"-2'-.".SI-4;"2.'B-'ATU(C), Core
and Containment
Cooling Systems, Analog
Trip Unit Functional Test,
which tested
among other things, the
initiation logic.
The event
was the result of a personnel
error in which a
test performer prematurely turned the
ATWS test switch from the Test position
to the Normal position.
Personnel
action was taken against the individual
involved in the event.
.Labels
were attached
to the switches identifying them
as having unit scram hazard potential.
In addition the licensee
deleted the
ATWS logic test from 2-SI-4.2.B-ATU(A, B,
C,
and D).
This test is not
required
by technical. specifications,
however,
the licensee
intends to write a
separate
test to be performed every eighteen
months.
The initiation of this
test is being tracked
by the licensee's
tracking system
and is scheduled
to be
completed prior to the completion of the next Unit '2 refueling outage.
8.3
(CL'OSED)
Noncompliance
With IOCFR50 Appendix
R Results
In Unit 2 Being Outside Its Design Basis
And In A Condition not Covered
By The 'Plants Operating Instructions.
'On September
29,
1994, 'the licensee
identi.fied that
IEC Bus
2B which supplies
a Unit 2 suppression
pool level indication would be made unavailable
due to a
fire occurring in Fire Area 18.
Upon discovery of this condition, the
licensee
entered
a Unit 2 Appendix
R limiting condition of operation
which
established
compensatory
measures.
Long term corrective actions
included
revising the Safe
Shutdown
Program to correct the compensatory
measures
for
loss of IK Bus
2B and revised the calculations
and procedures
to allow the
use..of the alternate
feed to I8C Bus .2B for a fire occurring in Fire Area 18.
In addition,
a comparative
r5view twas 'per'formed
between the Appendix
R Safe
Shutdown
Progr'am
and the Appendix
R calculations. to identify any other
potential discrepancies.
Those identified .were also corrected.
8.4
(CLOSED) (Unit 3)
Battery Failui e Concurrent with
LOP/LOCA Prevents
Automatic Start of Residual
Heat
Removal
Pump.
This
LER describes
a design
problem with electrical
systems identified by the
licensee
during
a design review;
The identified problem was that failure of
one battery would result in loss of DC power to one division of RHR system
logic and thereby
cause
the voltage sensing circuitry within the logic to
incorrectly enable the
RHR pump breaker to close onto
a dead
bus.
Therefore,
during the
10 second diesel
generator
start=-time-fol-lowing-a-.LOP-, the
breaker would close onto
a dead
bus.
At the
same time; there would-be
a trip
t
signal present -from-the- undervol-tage
load shed relays.
Simultaneous trip and
close signals
cause
the anti-.pump circuit to lockout the breaker.
The
corrective action
was to wire a normally closed contact from the undervoltage
il
31
load shed relays into the close circuit of the
RHR pumps 4o prevent closing
onto
a dead
bus regardless
of the functionality of%he
RHR system 'logic.
Then,,since
one
RHR pump in each division receives
a start signal
from the
system logic of both divisions, the failure of any one
DC power supply would
'ot
result in failure to start of both
RHR pumps of a division.
The inspector
verified the logic change
by reviewing the schematic wiring diagrams for the
RHR,pump motor breakers..
LER 88-12
was closed for Unit 3.
8.5
(CLOSED) (Unit 3)
Inadequate 'Design Controls Result in
the Backup Control
System Not Meeting Design Requirements.
This
LER addressed
problems identified by the licensee
during
a design review
with the as-installed
Backup Control System,
the requirements for which are
described
in FSAR Section 7.18.
The physical separation
requirements, of the
'Backup Control System are enveloped
by the Appendix
R requirements.
The
licensee
had
a special
program'to
address
Appendix R,
and this was reviewed
and inspected
by the Staff (refer to
NRC Inspection
Report 95-37).
Corrective
actions for this
LER were superseded
by the Appendix .R-.program.
'During this
inspection period,
the, inspectors
selected
a few corrective .action
modifications at random for implementation veWification.
From Design
Change
Notice W21814, the inspector verified that the transfer switches for valves 3-
PCV-001-0018,
-0019,
-0031
and -0179 were moved from the backup control
panel
to local panel
3-LPNL-25-0658.
LER 88-40 was closed for Unit 3.
8.6
(CLOSED) (Unit 3)
Design Errors. in 250
VDC Electrical
System Results in Unanalyzed
Condition.
=-'This
LKR involved three problems with the single failure criterion and
electrical
systems.
One problem applied to Unit 3.
RHR containment isolation.
valves 3-'FCV-74-47 (outboard)
and 3-FCV-74-48 (inboard)
have independent
power
supplies,
the .outboard is
DC powered
and the inboard is .AC powered.
However,
the inboard valve logic circuit power had been taken .from the
same
source
as
the motive power for the outboard
valve,:RNOV 3B, thus .violating the single
failure criterion.
'Review of system operation indicates that this failure
- would represent
an unanalyzed
condition.
The corrective action
was to take
motive power for the outboard valve, 74-47,
from RHOV 3A.
This was consistent
~
with the overall division separation
scheme.
The inspector verified that the
power source
change
had
been
implemented 'by reviewing one-line diagrams
and
inspecting the distribution panels in the plant.
'LER 89-25 .was closed for
Unit .3.
8.7
(CLOSED) VIO 259,260,296/95-38-01,
Inadequate
Drawing And Procedures
r
The violation addressed
failure to have appropriate
procedures
and/or drawings
for activities that affected quality including Thermo-Lag installation.
The
inspector
reviewed the corrective actions for the Thermo-Lag issues
identified
in TVA's reply to the
NOV dated
September
6,
1995.
The inspector
concluded
that the- drawing
and procedure
revi'sions affecting the material control
and
installation of the Thermo-Lag adequately
addressed
.the violation-.=
Additional
review of Thermo-Lag design
comparison to Watts Bar details identified no
significant discrepancies.
The corrective actions
associated
with electrical
relay contact drawings were reviewed.
This violation .i.tern is=,closed';. '-
0
32
8.8
(CLOSED)
Rev. '2, Inspection to,Determine
Compliance with
ATWS Rule,
(CLOSED)
Inspection
For Verification of BWR Recirculation
Pump Trip, Multi-Plant Action Item C-02.
The inspection for these
items covered the remaining .issues identified in IRs
259,
260, 296/95-22, specifically,. additional reviewof testing and"procedures
.upon completion of the ATWS/ARI/RPT modifications
on Unit "3 prior to recovery.
The modifications were tested
in accordance
with ECN P0126', 'Mechanical to
Analog Transmitter Trip System
(ATTS) modification, Post Modification Test
(PHT),
PMT-116 and
DCN W19321A, ARI/RPT Modifications,
PHT-258.
The ATTS
modi'fication replaced
old style mechanical
pressure
and differential pressure
indicating switches with more rel,,iable electronic
components
and included
many
other instruments
in addition to those .associated
with the
ATWS modifications.
PHT-116 functionally tested
the modification from the sensor to the analog
trip units
(ATUs).
PHT-258 functionally tested
the remainder, of the
modification from the
ATUs to the actuating
components, i.e., the
recirculation
pump trip. breakers
and the control rods hydraulic control units
(HCUs).
The testing
was completed
October
10,
-1995.
The inspector reviewed the
completed
PMTs for completeness
and satisfaction of the pre-determined
~acceptance
criteria.
The inspector considered
the 'PMTs to be comprehensive
and to have successfully
demonstrated
the desired functionality of the
modifications.
An error in the design of the. ARI portion of the modification was revealed
during the
PHT.
Numerous intermittent fuse failures in the power circuit to
the ARI solenoid valves occurred.
The licensee ultimately attributed this
problem to the absence, of a .suppressor
diode around the solenoid coils..
Without the suppressor
diodes,
discharging the coils upon reset of the ARI
actuation
would degrade
the upstream fuses.
After several
actuation resets,
the fuses
would blow, disabl.ing subsequent
initiations for the affected
HCU.
The licensee
determined that .the
same problem had been revealed during the
Unit 2
ATWS PHT, but had not been factored into the modification for Unit 3.
Upon installation of the suppressor
.diodes for each
ARI solenoid valve, the
testing
was successfully
conducted.
The inspector'erified that appropriate surveillance instructions
(SI) existed
to satisfy the Technical 'Specification surveillance
requirements for periodic
actuation
instrumentation calibrations
.and functional tests.
The surveillances
were verified to be current
and entered into the licen'see's
surveillance
scheduling
process
with the correct frequencies.
The
TS required daily
instrument
channel
checks required
by TS 4.2.B for LIS-3-58A-D and
LS-3-58A-D=-
were verified to be included in the routine surveillance
procedures.
The inspector verified that Emergency Operating Instructions correctly
directed-manual
actuation of ARI in the event of ATWS in'dications.
.The.',Unit
3,
ATWS/ARI/RPT fs fiinctionally,equivalent to 'the Unit 2 system.
All training
-.
received
by the operators:for.'.Unit
2 is directly .applicable to Unit 3.
0
is,'
33
The Unit 3
SLC system
has
been established,
concentration verified to be within the Technical Specification required
range.
.Based
on the above information, section 4.05 of TI 2500/20 is considered
closed.
IR 259,
260, 296/90-33
documented
inspection of the
ATWS related
gA
requirements
of Generic Letter 85-06 for Unit 2.
Inasmuch
as the
gA program
is common to both Units 2 and 3,
no further action is required to verify 'the
existence of gA program attributes for Unit 3.
Thus, section 4.06 of TI
2500/20 is considered
closed.
8.9
(CLOSED) Review of ATWS Issues for Generic Letter 83-28 Items 4.5.'2
and
'4.'5;3:(IP 37700)
The inspector
reviewed the licensee
actions
completed for Generic Letter (GL) 83-28 for Unit 3 restart.
Item 4.5 of the
GL identified
a
NRC position that
required on-line functional testing of the .reactor trip system,
including
independent
testing of the diverse'trip features.'n
TVA submittal
dated
March 15,
1984 in response
to the
GL,
TVA delineated
the Browns Ferry testing
requirements
for the reactor protection system.
The channel
functional
testing
scheme
was described with the frequency
and scope of this testing
used
as
TVA basis for not modifying the system to enhance testability..
The Safety Evaluation. (SE). issued
September
2,
1986 in response
to the
.
previous submittal
documented
a conclusion that
TVA had demonstrated
a
sufficient basis for:not requiring modification of the backup
scram function
to provide for on-line testability.
However, the
SE identified a requirement
to test the backup
scram function during refueling outages
and such testing
should
be included in,the Technical Specifications.
The inspector
reviewed
'he testing requirements
for the backup
scram function.
This festing is
included in Surveillance Instruction '3-SI-4. 1.A. 1, Reactor Protection
System
Mode Switch in Shutdown Functional Test. This test is required during
refueling outages.
Item 4.5.3 of .the
GL required confirmation from all licensees
that
on line
testing of the reactor trip system
was being performed.
The
NRC Safety
Evaluation Report
(SER) for Item 4.5.3 of the
GL was issued
August 17,
1990.
The conclusion of this report stated that the current test intervals are
sufficient to provide high reliability. All licensing actions
were considered
complete for Item 4.5.3 for Browns Ferry Unit 3.
Items 4.5.2
and 4.5.3 of the
GL '83-28 are complete.
The i'nspector
determined
that the licensee
actions
were adequate
for addressing
the items identified in
the GL.
This item was closed.
.8. 10
(CLOSED) IFI 296/95-37-02,
Performance of Simulated
Shutdown for an
.Appendix
R .Event
On September
7,
1995, the inspectors
accompanied
operations
personnel
on
a
walk through of -a simulated Appendix
R fire in fire area
16 (control
bay,.
II
0
II
34
including control room).
This effort was intended to be training on the
combined
U2/U3 SSIs
as well as
a enhancement
of the procedures.
This area is
regarded
as the most challenging safe
shutdown scenario
due the extensive
number of in-plant activities required.
Operators
simulated
performance of
plant activities
on Units '2 and
3 while the simulator was shutdown
as the "non
fire" unit.
The inspectors
(and operators)
noted
numerous differences
between
the labels
on the instal.led equipment
and the procedures.
The procedures
had
been through validation.
The inspectors
discussed
with licensee
management
-their conclusions that the exercise
involved more procedural validation effort
rather than operator training and verification of time .requirements.-
Following this initial observation, it was concluded that the inspectors
would
observe
an additional
safe
shutdown exercise drill scenario to ensure
the
licensee
properly demonstrated their ability to remotely shutdown the units
during
an Appendix
R event
and to verify the noted labeling problems
were
corrected.
On September
28,
1995,
a group of. four inspectors
observed
another
performance
of an exercise
involving the training of operations
personnel
in the use of
the Unit 2/3 Safe
Shutdown Instructions.
Again, Safe
Shutdown Instruction
2/3-SSI-16,
Control Building Fj.re on Elevation
593 through Elevation 617,
was
demonstrated.
A majority of'he previously noted labeling issues
had
been
corrected.
However, the inspectors
noted that
some Unit 2 "20 minute" actions
were accompl'ished
exactly at the
20 minute'ime limit. After these
concerns
were communicated to the licensee,
plant management
concluded that the drill
was unsatisfactory.
Site engineering
stated that there is some margin in the
20 minute requirement,
however,
the inspectors
noted that existing
SER for
Appendix
R exemptions refers to 20 minutes.
Following this demonstration,
the
licensee
stated that SSI 2/3-SSI-16 would be revised
by adding
an additional
remote operator for Unit 2.
Additionally, all of the Unit 2/3 SSIs would be
revised to address
multiple impedance faults.
On October 25,
1995, the residents
again observed
.the licensee's
performance
.of an Appendix
R Safe
Shutdown simulation for a fire in the control bay.
This
demonstration
involved simulating the remote
shutdown of both
U2 and
U3 from
their respective
remote
shutdown panels.
All labeling deficiencies
were
corrected."
The. licensee
revised. 2/3-SSI-16 for the control
bay which resolved
the inspectors
concerns
related to timeliness of Unit 2 remote operator
actions
(20 .minute).
The licensee
successfully
demonstrated their ability
(through the simulated. exercise)
to remotely shutdown Units
2 and
3 with the
Safe
Shutdown Instructions.
The SSIs for Unit 3 operation will be issued
prior to restart.
Based .on the inspectors
review,of this matter, this IFI is
.
closed.
8. 11
(CLOSED) THI Action Item 296/II E.4.2,
Containment Isolation
Dependability
Items
1 through 4, Diverse Isolation.
The .inspector
performed
a review of the licensee's
activities associated. with
this item-. --These-activit;ies=-are-:related:=to-those
for NRC Bulletin 80-06,
Engineered
Safety Feature
Rest"Control's;
which was closed-for Unit 3 in IR 95-
22.
Tlie licensee
was committed to ensuring that the containment isolation.
system design
complied with the requirements
of the Standard
Review Plan,
Section 6.2.4.
fl
35
The inspector
reviewed the applicable. Safety Evaluation Report issued
by the
NRC 'on January
5,
1995.
This
SER contained
an evaluation of information
provided in response
to NUREG-0737, -Item II.E.4.2.
The report evaluated
the
design of the containment isolation systems for BFN Units
1 and
3 and
compared
them to the previously evaluated
Unit 2 design.
The report concluded that the
containment isolation systems for Units
1 and
3 were acceptable
and that
no
differences
in Appendix J,
Primary Reactor Containment
Leakage Testing were
identified between the units.
The inspector reviewed supplemental
information
provided
by TVA concerning additional differences
between Units
2 and
3 and
noted that final
NRC acceptance
of the Unit 3 system configuration
was granted
in a letter dated October
18,
1995.
The inspector reviewed the system modifications associated
with this item
performed
under
DCN W17185A.
Field work on this modification was completed
on
August 25,
1994.
The inspector
noted that this work was previously inspected
and documented
in
NRC IR 95-16.
This .DCN installed the containment isolation
status
system,
as well as the modifications to TIP system required
by NRC
As noted in IR 95-16, the remaining activities to be
inspected
involved the completion of post modification testing
and revision of
impacted
procedures
necessary
for return to operation.
The inspector
reviewed
the required post modification,testing
and noted that it included:
a number of
different valve and relay functional tests; circuit continuity checks
remote
position indication tests;
PCIS logic functional tests;
and the verification
of Containment Isolation System Status
(CISS) computer points.
The inspector
reviewed the completed test results
and noted that the various system
responses
were within the established
acceptance criteria
and that .any test
deficiencies
were identified, evaluated,
and corrected.
The inspector
determined that the post modification tests .appeared
adequate
to ensure that
the system performs
as designed.
During review of the:,post modi'fication
testing,
the inspector
noted that
a small portion of the testing
remained to
be completed.
This testing involved verification of CISS computer points for.
system which had
been turned over to operations.
Based
on .a schedule to
complete these activities,
the inspector
found the post modification testihg
acceptable for closure of this item.
The inspector
reviewed
a selected
number of procedures
.impacted
by the above
noted modifications to verify that the licensee
has completed all required
procedure revisions.
The .inspector
noted that the licensee
had completed all
procedure
revisions required
by the implementation
on
DCN W17185A.
The
inspector's
review of revised
procedures
confirmed that the licensee
had
adequately
revised =the procedures
to reflect the changes
associated
with the
modification.
Based
on
a review of the completed activities, the inspector
has determined
that the licensee
has satisfactorily completed all requirements
associated
with this .commitment,
and considers this item closed.
8. 12
(CLOSED)
TMI Action Item 296/I.L.E.4.2,, Containment
Isolati.'on
Dependabil.ity Item 6, Containment
Purge Valves.
The licensee
has completed the following actions to ensure that the
Containment
Purge isolation valves
met the criteria of '.Branch Technical
il
11
36
Position
CSB 6-4.
BFN Unit 3 containment isolation system design
compliance
with Branch Technical Position
CSB 6-4 has
been evaluated
and accepted
by'the
NRC in a letter to TVA dated July 1,
1985.
Calculations
analyzing the effects
of a
LOCA occurring while purging the Containment
and impacts
on the Reactor
Building ductwork, Secondary
Containment,
and Standby
Gas Treatment
systems
were completed satisfactorily in 1991.
The stroke times of the containment
purge isolation valves were reduced
through the implementation of ECN P0384.
This
ECN replaced
the solenoid valves
and supply tubing for the valves
and was
.completed in September of 1993.
Debris screens
were installed
on the
'ontainment
purge lines in August of 1981 through the implementation of ECN
P0428.
Lastly, the containment
purge isolation valves were"replaced
under
DCN
W18233,
completed in September
1993.
The replacement
valves
have
a different
seat
design resulting in better sealing capability and requiring lower valve,
operator torque.
The licensee
has completed all of the actions
noted
above in
fulfillment of i.ts commitment to Branch Technical
Position
CSB 6-4.
The inspector
has reviewed
and evaluated
the licensee's
efforts as various
activities have
been completed.
The inspector
reviewed the implementation of
the system modifications
and documented this review in NRC IR 95-16.
Following the completion of these modification activities, the remaining
actions to be reviewed involved the implementation of post modification
testing
and procedure revisions.
The inspector
has reviewed the post
modification test activities associated
with ECNs
P0384
and
P0428
and
DCN
W18233.
These test activities included:
remote operation
and 'indication;
LLRT; leak'esting;
and closure/stroke
time testing.
The inspector
has
reviewed the results of ,these completed test activities
and noted that test
deviations, were properly identified, evaluated
and- corrected.
The inspector
noted the testing reviewed
appeared
adequate
to ensure
proper operation of the
systems.
The final area,to
be inspected
involved
a review of:procedures 'to ensure that
'all impacted procedures
were properly 'updated.
The inspector reviewed the
modification packages,
associated
documentation
and noted that the licensee
has completed all procedure revisions required for return to operation.
The
inspector reviewed the current revisions of selected
procedures
to ensure that
.,
these activities have
been
completed'.
The inspector noted that the procedures
reviewed
had all been properly modi.fied to,reflect the changes
associated. with
the plant modifications.
'Based
on
a review of the completed activities, the inspector
has determined
that the licensee
has satisfactorily completed all requirements.
associated
,with this commitment,
and considers this item closed.
8. 13
(CLOSED)
IFI 296/94-18-02, .Condition of Unit 3 Containment Coatings,
During the performance of a containment
inspection in August,
1994,-
the
NRC determined that containment
were being properly controlled at
Browns Ferry.
However, at the time of that inspection -effort, over 4000
square feet of Unit 3 containment
were not- DBA"qualified.
The=.-
licensee's
calculations. stated-that
only 157 square feet .of unqualified-
(uncontrolled) coatings
could exist within primary containment
and not exceed
il
II
37
the 65 percent
ECCS suction strai'ner
blockage criteria.
The above stated IFI
was
open pending resolution of this matter.
On November 6,
1995, following extensive evaluation
and effort to reduce
certain coatings to a dry film thickness of (0.003", the total
amount of
unqualified (uncontrolled) coatings within. Unit 3 primary containment
was
reduced to 118.2 square feet as delineated
in the Unit 3. Primary Containment
Uncontrol,led Coatings
Log (Calculation
Number MD-93303-940038).
The log also
stated that the application of Valspar
78 coating to stainless
steel
was
now
DBA qualified therefore allowing the coating to remain
on the
SRV T-quenchers
and other stainless
steel
surfaces within containment.
The inspector reviewed-
the calculation (uncontrolled coatings log) and found it to be acceptable.
In
addition, the inspectors
toured the drywell
(November 8)
and the torus (prior
to fil.,l:ing),,:and found the condition of the coatings to be acceptable.
Based
on .this Ye'0'i'ew, XPe, inspectors
have determined that the coatings within Unit 3
are'acceptable
for Unit 3 restart
and this item is
considered
closed.
8. 14
(CLOSED) TMI Action Item II.F.1.2.D (Formerly II.F. 1.4)
Containment
Pressure
(Accident) 'Monitor (Unit 3).
As presented
in IR 95-31,
some review of this item was previously conducted.
However, the issue
remained
open pending,
equipment calibration/testing
inspections,
instrumentation string functional'testing,
and following
approvals of related pressure
component testing,
maintenance,
and operating
procedures.
An inspector
reviewed/observed
closure activities for the
'remaining .issues
and noted the following:
Instrument string testing for the wide range .accident:monitoring strings
(PT-64-160A 5 160B)
was performed.on
October
16
8 17,
1995 .and results,
received/reviewed
October 30,,were satisfactory.
Based
upon this review and examination of related
component
procedures,
Action Item II..F.1.2.D, (.II.F.1.4), is closed for Unit 3.
8. 15
(CLOSED)
TMI Action Item II.K.3.18, A'utomatic Depressurization
System
(ADS) Logic Modification '(Unit .3).
Previous review of this item was addressed
in IR 95-43.
However, the issue
remained
open pending,
additional inspection of ADS component operability,
performance of ADS functional testing, testing of the
ADS logic and completion
of proposed
changes
to plant maintenance/testing
and operations
procedures.'n
October 23,
1995, logic train "A" testing
was performed,
on October
24,
"B"
testing
was perfo'rmed
and results,
received
and reviewed
on October 31, were
found to be satisfactory.
An inspector
reviewed closure activities for the
remaining issues
and noted the following:
The improved,
ADS timer met the::prescribed
Unit 3'echnical
Specification
(Section 3.2.B.) setpoint;.of: 95. (+/.-7).-seconds..--
-.-
"New" initiation logic inhibit switches
operated
as designed.
0
38
The "new" ADS logic train time delay relays operated
as designed.
Mhen the manual
"A"/"B" keylock switches
were operated,
the "new" alarm;
B INHIBITED", functioned
as designed.
Based
on these
reviews,
THI Action Item II.K.3.18, is closed for Unit 3.
8.16
(CLOSED) THI Action Item I.D.2 (Specifically Action Item I.D.2.2
Installation)
Safety Parameter
Display System
(SPDS - Unit 3).
Previous review of this item was addressewd
in IR 95-22.
However, the issue
remained
open pending completion of a licensee
Post Hodification Test
(PHT)
229 and::a status .of Unit 3 system tie-in to the Integrated
Computer
System
(ICS).
The
PHT,
a test of thermocouple, digital signal
and "sequence-of-event"
inputs into the
ICS neutron monitoring instrumentation strings,
was
performed
November 7,
1995.
Results of this testing
was received
and
'reviewed
November
8 and found to be satisfactory.
System tie-in to the
ICS.was
completed
November 7.
Remaining action plan issues for TI2515/65 - 3.02.b.(2)
[Equipment
Calibration],
and 3.02.b.(3)
[Operability) - have
been adequately
addressed
by the licensee.
Based
on these
reviews,
THI Action Item I.D.2 specifically, I.D.2.2
("Installation" ) - is closed for Unit 3.
8.17
(CLOSED)
GSI 75
(HPA B085);
"Required Action Based
On Generic
Implications Of Salem
ATWS Events",
Section 1.2, "Post-Trip Review (Data
and Information Capability)" (Unit 3).
Licensee
computer capability to record data pertinent to a unit reactor trip
~is
an integral part/capabil1ty of the previously mentioned Unit 3 SPDS.
2'apabilities of assessing
"'sequence-.of-events",
"variable time-histories",
and
"unscheduled
reactor
shutdown probable-cause"
are met with the installed
system.
Based
upon present
status of the installed Unit 3 system
and closure
of the prior THI Action Item, Item I.D.2, this capability issue,
(GSI 75), is
also addressed
and closed for Unit 3.
8. 18
(Closed, for U3 Restart)
and 93-02,
Supplement
1, Debris
Plugging of Emergency
Core Cooling Suction Strainers
(and supplement
1) were issued
by the
NRC to notify the
operators
of light water reactors of the potential for debris plugging of ECCS
suction strainers.
This inspection, documents
the licensee's
readiness
to
restart Unit 3 as it relates to thi's matter.
The corrective actions
performed,
for Unit 3 are equivalent to those
performed
on Unit 2 and previously accepted
by the Office- of 'Nuclear Reactor Regulation.
The inspectors
reviewed the
correspondence
related to this bulletin.
.In addition, the inspectors
performed
a detailed
walkdown of the Unit 3 drywell for temporary
and
4
IS
39
permanently installed fibrous material.
During the walkdown, the inspectors
noticed that the fibrous material
permanently installed inside various drywell
(the
NRC was -informed of these penetrations
in correspondence
related to this Bulletin) was in a condition such that the insulation
was
flush with inboard side of the penetration.
The inspector discussed
this
matter with site engineering
personnel.
The engineers
stated that this
material
would be "trimmed back" such that the fibrous material
remaining
within these penetrations
would be shielded
in the event of an accident'nd
thereby minimizing the possibility of the material
being transported
to the
suppression
pool.
The inspectors verified the fibrous material
had
been
trimmed back.
No temporary or any additional
permanently installed fibrous
material
.was identified by the inspectors.
In addition,
the. inspectors
verified that the Unit 3,EOIs appropriately .addressed
pump
NPSH concerns.
Also reviewed were the operator lesson
plans
and simulator scenario. addressing
ECCS suction strainer .plugging.
These
were found to be acceptable.
Lastly,
the inspectorgccompan'ied.
the licensee
on the final drywell closeout,
performed in accordance
with 3-GOI-200-2, .Drywell Closeout,
and found no
fibrous material.
Based
on these reviews,
the inspectors
determined that the
actions required
by Bulletin 93-02 (including supplement I) were accomplished
satisfying the requirements
for the restart of Unit 3.
8.:19
(Closed, for U3 Restart)
Unexpected
Clogging of a
Residual
Heat
Removal
(RHR)
Pump 'Strainer While Operating in Suppression
Pool
Cool.ing Mode
Bulletin 95-02 was issued
by the
NRC (on October
17,
1995) to notify the
operators of boiling water reactors of the potential for debris plugging of
RHR suction strainers while 'operating in the suppression
pool cool.ing mode.
'his inspection
documents
the licensee"s
readiness
to restart. Unit 3 as it
relates to this matter.
During the recovery of Unit 3, the inspectors
have
'closely
monitored the licensee's
actions related to the torus.
This included
a detailed inspection of the .torus prior to filling (which included
cleanliness
of the entire pool area
and strainers
and inspection of coa4ings).
Following torus fill, the licensee
had
an event in which a vacuum bag
became
lodged in the 3A,core spray
pump.
,As
a result of this matter,
the licensee
performed
.a complete
underwater
inspection,and
vacuuming of the torus.
The
licensee
also stated that they would perform an additional inspection of the
torus just prior to the units restart.
The licensee
responded
to this
bulletin in..a letter to the
NRC on November
15.
On November
16, the licensee
compl'eted
a complete
underwater
vacuuming of the torus including
a cleaning of
the,ECCS suction strainers.
Material
removed from the torus included the
remnants of the previously discussed
vacuum
bag
and silt from piping corrosion
products.
Following the vacuuming of the torus, the licensee
ran
2
RHR pumps
for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> in the suppression
pool cooling mode,
which pumped
an equivalent
of almost three times the torus volume through the
ECCS suction strainers.
Upon completion of the torus flush, di.vers- reinspected
and video" taped the
conditi'on of- the-'ECCS suction: strainers-.-
The strainer s were found to be-
essentially free of any debris.
In addition to these actions,
the licensee's
response
to this bulletin was
reviewed
by .NRR and discussed
in,phone call with the licensee
on November
16;
40
NRR -found that the licensee's
response
was satisfactory
pending the results of
the flushing and reinspection
discussed
above.
NRR was advised of the
satisfactory
underwater .inspection results
on November
17 and concurred that
no issued
remained preventing the restart of Uni.t 3 related to bulletin 95-02.
Based
on these
reviews, the inspectors
determined that the actions required
by
Bulletin 95-02 were accomplished
satisfying the requirements for the restart
of Unit 3.
, e
8.20
(CLOSED) 296/IFI 95-31-06: Potential
Unit 3
Eg Program Deficiencies
Eg
ISSUES
During a guality Assurance
assessment
of the .Unit 3 IOCFR50.49 Environmental
guaTification Program,
a number of findings wer e made which brought the
effectiveness
of the Unit 3 program into question.
The predominant finding
dealt with the fact that
some Unit 3'g equipment
was potentially wo} ked as
non-Eg.
To determine the extent of the condition, the licensee
formed
an
incident- investigation
team.
The team determined that
a window of
vulnerability existed
from November,
1992,
(time at which recovery workplan
write began) until July,
1994,,when
a revision'to the site standard
practice.
controlling the
Eg program at
was issued.
The
SSP 6.5 revision
laid out
a program to install, modify,, and .maintain all equipment designated
as
Eg in accordance
with 10 CFR 50.49 requirements.
The licensee
performed
a,
review of work plans
and work orders ~performing work on
Eg components
during
the window of vulnerability to ensure that components requiring environmental
qualification are baselined
as such.
The review wa's performed
on
a system
basis
as part of the
SPOC activities.
The licensee
performed incident investigation
BFPER950469 to address
the
issue.
The inspectors
reviewed
BFPER950469
and verified the corrective
actions
incl.uded completion of the Unit 3 50.49 list and
gMDS Manual'.and
revision of SSP 6.5.
Beginning the
Eg workplan effort prior to finalizing the
50.49 list and.
gMDS Manual also .occurred
on the Unit 2 recovery effort and was
the subject of a Unit 2 lessons
learned
item.
The Unit 2 lessons
learned
item
was not addressed
and
a Unit 3
Eg work,plan
and work.order review .was required
to baseline
the Unit .3
Eg program.
The incident investigation concluded that
the root cause
was inadequate
management
fol.lowup 'and monitoring of
activities.
-Procedure
TI-339,
Eg Review Project,
was prepared to implement the work
order/work plan review.
The work activities were categorized
into one of six
classes.
Class I items were activities which are periodically performed
and
the licensee verified the satisfactory'erformance
of the last activity
for'he
baselining effort.
Class
2 items were. activities which were controlled
independent of the
Eg status of the equipment.
Class
3 items were activities
which could be affected 'by .a work plan or work order.
Work plans
and work
orders
were reviewed for these
items.
Class
4 items were activities which
could
be affected
by. a work. order but not- a- work- plan.
Work-orders- were"
reviewed, for these
items.
Class
5 items were activities which were
recommended
not required-maintenance
activities in the--gMDS- manual..
Class-6---
items were activities which"were verified to .be-completed
or work orders
were
performed to complete the activity in lieu of a review of closed work
plans/work orders.
0
0
The completed
Eg system baseline
packages for systems 32,.69,
70,
and
90 were
reviewed.
The inspectors verified. that the
Eg components
in the system
packages
included .those
components listed in
EMS for the system.
The
qualification maintenance
items listed in the system
packages
were compared to
the activities listed in the
gMDS Manual.
No di,screpancies
were noted.
The
packages
were prepared
in accordance -with TI-339 and the activity
classifications
and detailed work order/work plan evaluations
were,acceptable.
Twenty-one selected activities were reviewed
and the inspectors verified that
the
WO/WP implemented the
gMDS requirements for the listed equipment.
No
discrepancies
were noted.
The inspectors
determined that the corrective
actions for IFI 95-31-06 were completed. -;This;item is closed.
9.0
- Exit:Interview (30703)
t'la, sP"
The inspection
scope
and findings were summarized
on November 29,
1995, with
those, persons
indicated in paragraph
1 above.
The inspectors
described
the
areas
inspected
and discussed
in detail the inspection findings listed below.
Although proprietary material,was
reviewed during the inspection,
proprietary
information is not contained
in this report.
Dissenting
comments
were not
received
from the licensee.
Item Number
Status
VIO 296/95-60-01
Open
NCV 296/95-60-02
Closed
NCV 260/95-60-03
Closed
'-"VIO 259,'260,296/
Closed
95-38-01
Descri tion
Failure to Fol.low Approved Configuration Control
Procedures
Resulting in Misalignment of SDV
System
Components.
Loss .of Shutdown Cooling .Flow.
Failure -to,perform Diesel 'Generator Reliability
Determination.
Inadequate
Drawing and Procedures.
Closed
Battery Fai-lure Concurrent with LOP/LOCA
Prevents, Automatic .Start of Residual
Heat
Removal
Pump.
(Closed for. Unit 3)
Closed
Inadequate
Design Controls Result in the Backup
Control System Not Meeting Design Requirements.
(Closed for.Unit 3)
Closed
TI 2500/20,- Rev.2 Closed
Design Errors in .250
VDC Electrical
System
Results in Unanalyzed Condition.
(Closed for
Unit 3)
Compliance- with ATWS Rule,
Closed
42
BWR Recirculation
Pump Trip, Multi-Plant Action
Item C-02.
Closed
Closed
Closed
Reactor
Scram Resulting
From A Turbine Trip Due
To A Sensed
Generator
Load Unbalance
Condition
Caused
The Actuation Of The
ESF System.
Reactor
Scram Resulting
From Personnel
Error
During Surveillance Testing
Caused
The Actuation
Of The
ESF System.
Noncompliance With lOCFR50 Appendix
R Results
In
Unit 2 Being Outside Its Design Basis
And In A
'Cendition not Covered
By The Plants
Operating
Instructions.
Closed
Review of ATWS Issues for Generic Letter 83-28
Items 4.5.2
and 4.5.3
IFI 296/95-37-02
Closed
TMI Action Item
Closed
296/II E.4.2
TMI Action Item
Closed
296/II.E.4.2
IFI 296/94-18-02
Closed
TMI Action Item
Closed
II.F.1.2.D
(Formerly II.F.1.4)
TMI Action Item
Closed
II.K.3.18
TMI Action Item
Closed
I.D.2 (Specifically
Action Item I.D.2.2
Installation)
GSI 75,
MPA B085
Closed
BU-93-02
8
Supp
1
Closed
Performance of Simulat'ed
Shutdown for an
Appendix
R Event.
Containment Isolation Dependability
Items
1 through 4, Diverse Isolation.
Containment Isolation Dependability
Item 6,
Containment
Purge Valves.
Condition of Unit 3 Con'tainment Coatings.-
Containment
Pressure
(Accident):Monitor
,(Unit 3).
l
Automatic Depressurization
System
(ADS) Logic
Modification (Unit 3).-
Safety Parameter
Display 'System
(SPDS - Unit 3).
Required Action Based
On Generic Implications Of
Salem
ATWS .Events,
Section 1.2, Post-Trip Review
(Data
and Information Capability) (Unit 3).
Debris Plugging of Emergency
Core Cooling
Suction Strainers
(Closed for Unit 3 restart).
0
'BU-95-02
Closed
43
Unexpected
Clogging of a Residual
Heat
Removal
(RHR)
Pump Strainer While Operating in
Supression
Pool Cooling Mode (Closed for Unit 3
restart).
IFI 296/95-31-06
Closed
Potential
Unit 3
Eg Program Deficiencies
Eg
Issues.
i
0
10.0
ADS.
ANSI
AOI
ASOS
ATU
BFNP
CILRT
DCN
EDSFI
'EQDP
GL
IEEE
IFI
IR
kV
La
LER
NRC
NSRB'
oIIAT
.Acronyms and Initialisms
.Automatic Depressurization
System
American National Standards
Institute
Abnormal Operating Instruction
Average
Power
Range Monitor
American Society of Mechanical
Engineers
Assistant Shift Operations
Supervisor
American Society for Testing
and Material
Analog Transmitter Trip System
Analog Trip Units
Anticipated Transient Without
Scram'uxiliary
Unit Operators
Browns Ferry Nuclear Plant
Boiling Water Reactor
Contai.nment Isolation System Status
Containment
Integrated
Leak Rate Testing
Design Basis
Event
Design
Change Notice
Diesel
Generator
Emergency Diesel
Generator
Emergency
Core Cooling System
Engineering
Change. Notice
Emergency
Equipment Cooling Water
Electrical Distribution System Functional
Electric Power Research
Institute
Environmental Qualification
Environmental Qualification Documentation
Engineered
Safety Feature
Fire Protection
Report
Final Safety Analysis Report
Generic Letter
Generic Safety Issue
High Pressure
Coolant Injection
Heating, Ventilation,
and Air Conditioning
Integrated
Computer System
Institute of Electrical
and Electronics
Inspector Follow-up Item
Inspection
Report
Kilovolts
Allowable leakage
in wt. percent
per
day
Licensee
Event Report
Loss of Coolant Accident.
Multi-Plant Action Item
Non-Cited Violation
Nuclear Performance
Plan
Nuclear- Reactor Regulation
Nuclear.'Regulatory.
Commission.
Nuclear Safety Review .Board
Operating Instruction
Operational
Readiness
Evaluation
Team
Inspection
Packages
t
0
i
ORRT
Pa
PDD
PER
RI-
RMOV
TI
TS
UL
V
't-
Operational
Readiness
Review Team
Containment Accident Pressure
Potential
Drawing Deficiency
'Public Document
Room
Problem Evaluation Report
Post Maintenance/Modification Test
Plant Operations
Review Committee
Quality Assurance
Quality Control
Reactor
Core Isolation Cooling
Residual
Heat
Removal
Residual
Heat .Removal Service
Water System
Resident
Inspector
Reactor Motor Operated
Valve
Reactor Protection
System
Reactor
Water Cleanup
Station Blackout
Scram Discharge
Volume
Safety Evaluation Report
Surveillance Instruction
Senior Management
Assessment
of Readiness
for Restart
Team
Safety Parameter .Display System
Source
Range Monitors
Senior Reactor Operator
Safe
Shutdown Instructions
Site Standard Practices-
Temporary Instruction
Three Mile Island
Technical. Specifications.
Valley Authority
Underwriters L'aboratory
Unresolved Safety Issue
'Volts
Violation
Work Order
Work Request
Weight percentage
of containment
0
i
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Reactor BuMny.
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