ML18038B542
| ML18038B542 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 11/07/1995 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B540 | List: |
| References | |
| 50-259-95-56, 50-260-95-56, 50-296-95-56, NUDOCS 9511160055 | |
| Download: ML18038B542 (78) | |
See also: IR 05000259/1995056
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report Nos.:
50-259/95-56,
50-260/95-56,
and 50-296/95-56
Licensee:
Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga,
TN
37402-2801
Docket
Nosg I
50-259,
50-260,
and 50-296
License
Nosg I
and
Facility Name:
Browns Ferry Units 1, 2,
and
3
Inspection at Browns Ferry Site near Decatur,
Inspection
Conducted:
September
17 - October
14,
1995
Inspector:
~O
Leonar
.
er
,
r., Senior
Ress
ent
nspector
J.
Hunday,
Resident
Inspector
R. Musser,
Resident
Inspector
H. Morgan, Resident
Inspector
ate
sgne
Approved'y:
Har
.. esser,
C
>e
,
Reactor Projects
Branch
6
Di'vision. of Reactor Projects
SUMMARY
Scope:
This routine resident
inspection
involved inspection on-site'n
the areas of
operations,
maintenance
and surveillance testing activities, Unit 3 restart
activities including numerous
equipment testing activities,
and review of open
items,
including several
Three Mile Island Action Items.
Several
hours of
backshift coverage
were routinely worked during most work weeks.
Deep
backshift inspec'tions
were conducted
on September
26,
30, October
1, 7, 8, 9,
10,
13,
and
14.
Enclosure
2
95iii60055 95ii07
ADOCK 0500025'7
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Results:
One violation and
one inspector followup item were identified:
Operations:
One violation was identified involving improper actions
by a control
room
senior reactor operator during
a Unit 3 testing activity.
Failure to follow
the actions of the alarm response
procedure
resulted
in de-energization
of a
480 volt, shutdown
board
and inadvertent
engineered
safety feature actuations.
(VIO 296/95-56-01:
Failure to Follow Alarm Response
Procedures
Results
in Loss
of 480V. Bus,
paragraph
2.3)
A NRC inspector identified that watchstander
actions involving the traveling
water screens
had not been properly communicated
to the Unit 2 control
room.
High differential pressure
across
the screen
was not being effectively
monitored.
Additionally, maintenance
personnel
were not actively cleaning
the trash racks
as expected.
The incident indicated that
some personnel
are
not yet sensitive to aspects
of multiple unit operations.
(paragraph
2.2).
Maintenance
and Surveillance:
An inspector followup item was identified associated
with the
use of a nickel
based
thread lubricant
on gaskets
in fluid systems.
(IFI 50-260/95-56-02,
Use
of Nickel-Based
Thread Lubricants
on Gaskets
in TVA Class
"B" Fluid Systems,
paragraph
3.2)
During observation of Unit 2 surveillance tests,
the inspectors
identified two
issues
in which enhancements
to the procedural
guidance
would improve the
quality of the testing.
(paragraph
3. 1)
Unit Three Recovery:
Extensive monitoring of Uni,t 3 recovery activities
was conducted'.
Numerous
major tests
were observed
and reviewed:
The i'nspectors verified that drywell closeout
and unit separation activities
were prog'ressing
well and were adequate
to support the restart.
(paragraphs
4.2
and 4'.5)
Reviews of the Unit 3 Environmental gualification activities indicated that
the program is being adequately
implemented.
(paragraph
4.7)
The inspectors
reviewed the status of Corrective Action Tracking Documents
and
concluded that the licensee's
program to track and resolve the items
has
been
effective.
(paragraph
4.9)
During review of Nuclear Performance
Plan issues,
the inspectors
identified
some deficiencies
on
a flow drawing of the high pressure
coolant injection
system control oil piping.
Subsequent
review confirmed that the associated
modification work to the governor system
had
been
completed properly
and the
items were drawing inaccuracies.
(paragraph
4. 10)
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Testing of the residual
heat
removal
system,
high pressure
coolant injection
system,
control air systems,
and reactor core
isolation cooling system
was monitored
by the inspectors
(paragraph
4.8).
Other, equipment testing,
including the control
rod drive system,
was observed
or reviewed
.in detai',1- to support closure of open
items
(paragraph
5.0).
Several
deficiencies
associated
with valve position status
(paragraphs
4.8.2
and 4.8.4)
were identified.
While the involved systems
were not yet required
to be operable
at the time, the inspectors
noted that the licensee's initial
actions
in response
to the:specific
problems
were not aggressive.
One example
of improper operator actions
(paragraph
2.3)
was noted.
Overal=l, the testing
was conducted
properly
and emergent
issues
were identified for resolution
as
required.
I
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REPORT DETAILS
1.0
Persons
Contacted
Licensee
Employees:
T. Abney, Unit 3 Nuclear Assurance
and Licensing Manager
J. Brazell, Site Security Manager
R. Coleman,
Radiological Controls Manager
- J. Corey,
Chemistry
and Radiological Controls Manager
T. Cornelius,
Emergency
Preparedness
Manager
~C. Crane,
Assistant
Plant Manager
- J. Johnson,
Site guality Manager
R. Jones,
Unit 3 Startup
Manager
- G. Little, Operations
Superintendent
R. Machon, Site Vice President,
Browns Ferry
J.
Haddox,
Maintenance
and Modification, Manager
- R. Moll, Plant Operations
Manager
- G. Pierce,
Technical
Support
Manager
E. Preston,
Plant Manager
S.
Rudge,
Site Support
Manager
J.
Sabados,
Chemistry Manager
- P. Salas,
Licensing Manager
T. Shriver,
Nuclear Assurance
and Licensing Manager
D. Stinson,
Recovery
Manager
- S. Wetzel, Acting Compliance
Licensing Manager
- J. White, Outage
Manager
H. Williams, Engineering
and Materials
Manager
Other licensee
employees
or contractors
contacted
included licensed
reactor
operators,
auxiliary operators,
craftsmen,
technicians,
public safety
officers,
and quality assurance,
design,
and engineering
personnel.
NRC Personnel:
- L. Wert, Senior Resident
Inspector
- J. Hunday,
Resident
Inspector
- R. Husser,
Resident
Inspector
M. Morgan, Resident
Inspector
G. HacDonald,
DRS Inspector
C. Patterson,
Senior Resident
Inspector,
Brunswick
J. Williams,
NRR Project Manager
G.
Wiseman,
DRS Inspector
- Attended exit interview
and initialisms used throughout this report are listed in the last
paragraph.
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2.0
Plant Operations
(71707,
92901,
71750,
40500)
2. 1
Operations
Status
and Observations
Unit 2 operated
at power during this inspection period.
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.
The inspectors
noted that operators
were cognizant
of plant conditions
and were attentive in their duties.
Due the approaching
Unit 3 restart,
the inspectors
have emphasized
review of issues that have
potential affects
on the operation of the other unit.
Paragraph
2.2 describes
a problem involving poor communications
between
some operations
personnel.
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.
The inspectors
noted that
on
some occasions,
the pace of Unit 3
testing activities in preparation for fuel loading stressed
the Unit 3 control
room personnel.
The large
number of ongoing activities
may have contributed
to some noted lapses
in CR performance
during the period.
(paragraphs
2.2,
2.3,
and 4.8.)
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 controls
on equipment,
work activities in
progress,
and radiological protection controls.
Informal discussions
were
held with plant personnel
during these tours.
The tours in the Unit
1 areas
focused
on maintenance
activities
and
systems
required to be operable
to ensure that appropriate attention is provided to
the shutdown unit.
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
and secured.
The inspectors
also observed
personnel
and
packages
entering the protected
area
and verified they were searched
either
by
special
purpose detectors
or physical
patdown.
2.2
Traveling Water Screen
High Differential Pressure
On September
20,
1995, while .touring the Unit 2 main control
room, the
inspector
noted that the annunciator for circulating water traveling screen
high differential pressure
was in alarm.
The differential pressure
at that
time was approximately
10 inches of water.
Additionally,. it was noted that
the traveling screens
were not in service.
The inspector
informed the unit
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ASOS who was
unaware of the condition.
He indicated that Unit 3 Operations
personnel
were controlling activities associated
with keeping the trash
racks
and screens
clear of debris.
After contacting the Unit 3 ASOS, Operations
personnel
were dispatched
to place the traveling screens
in service
and
maintenance.
was contacted
to scrape
the trash racks.
Further discussion
indicated, that the
AUO responsible
.for operations
at the intake structure
had
contacted
the Unit 3 control
room earlier
and informed them that
he was
securing
the traveling screens
and leaving the area,
however the Unit 2
control
room was not contacted.
At the time of the event Unit 2 was at
100
percent
power
and
was the unit most affected
by this condition.
With the
alarm sealed
in as it was,
the control
room staff would have received
no
warning that the condition was worsening.
Additionally, site
management
had
determined
the previous
week that the trash racks
needed
to 'be cleaned
around
the clock because
of the sudden
insurge of aquatic grass.
At that time the
differential pressure
was less
than
8 inches of water.
At the daily plan of
the day meeting
on September
20, the inspectors
had noted discussion
indicating that maintenance
personnel
were cleaning the racks continuously.
The inspectors
noted that
no maintenance
personnel
were present
at the intake
to clean the racks
when the issue
was identified.
Apparently there
were
some
coordination
problems involving maintenance
personnel.
Subsequently,
the
inspectors
observed
trash rack cleaning activities
and cleaning of material
from intake water with a specially equipped
boat.
The inspectors
concluded that this event
was the result of miscommunication.
The incident indicated that
some Operations
personnel
are not yet
appropriately sensitive to aspects
of multiple unit operations.
Discussions
were held with site management
concerning this conclusion.
Subsequently,
the
licensee initiated
BFPER951321
to document the problem
and develop corrective
actions
which included discussion
with essentially all onsite
personnel
of the
issue
as
a "dual unit incident".
2.3
Inadvertent
ESF Actuations
Caused
By Improper Operator Actions
On October 7,
1995
a .loss of the
3A 480V Shutdown
board occurred
due to
improper actions
by an
SRO in the Unit 3 control
room.
The loss of the
bus
resulted
in
a de-energization
of the "B" reactor protection
system
bus
and
several
inadvertent
ESF, actuations.
Testing, to investigate
a problem noted during previously completed
"B" EDG
load acceptance
testing
was in progress.
With the
"B" EDG supplying
power to
the
"3EB" 4
kV shutdown board,
the
EDG unexpectedly
tripped
due to
a loss of
field as loads
were applied.
When the
"B" EDG output breaker
opened,
this caused
a loss of power to the
3EB
shutdown
board
and consequently
transformer
TS3E which is the backup supply to
the
3A 480
V shutdown
board.
The loss of the transformer
power caused
"480V SD
BD 3A UV or XFER" to be illuminated on
a control
room
panel.
The
3A 480
V .SD board continued to be powered
from TS3A and
4KV board
3EA.
A SRO in the control
room incorrectly transferred
the board to the its
"alternate
source"
which Was the de-energized
feeder
from TS3E.
This caused
a
loss of one
bus
and the
ESFs.
All ESF equipment
performed
as expected.
15
if'gal
One of the inspectors
reviewed the available documentation
of the event,
discussed
the incident with the involved personnel,
and conducted
additional
review.
A pre-job briefing had
been
completed
and the testing
sequence
was
set forth in the text of an approved
Work Order.
The involved
acknowledged
that=he
had
made
an error in transferring the board.
The
inspector
reviewed Alarm Response
Procedure
3-XA-55-8B.
The procedure listed
loss of supply breaker
as
a cause
and requires, operator to "check for
indication of 480V shutdown
board
3A loss".
The procedure
also states; "If
the board is lost, then manually transfer the board".
While the wording on
the annunciator
window seems
to be misleading,
.the inspector verified through
discussion
with operators
that control
room personnel
are trained
and
aware
that the alarm can
be caused
by
a loss
of. the alternate
supply breaker.
The
inspector also noted that the readily available
480V board voltage indications
are located
on the
EDG panels
about
10 feet
away from the alarm
and transfer
switch locations.
(The voltage
can
be obtained at the switch panel
by
selection of the individual board
and reading
a voltage indication with input
from several different boards.)
The inspector
noted that the control
room log entries
associated
with the
i'ncident were very brief and did not contain sufficient details for a reviewer
to understand
some of the factors in the event.
The maj'or concerns
in the incident involved the improper actions
by the senior
reactor operator.
While it is recognized that
some personnel
errors
may occur
during the performance of evolutions,
in this instance
several
significant
deficiencies
were noted.
Pl,ant
management
has
been
emphasizing
the
need to
improve per'formance
so that these
type of incidents
are prevented.
As an
SRO,
this individu'al has
a responsibility to maintain control
and oversight over
the control
room activities.
The
SRO does
not normally operate
control
room
switches.
He became
involved in the details of the incident
and apparently
focused
in on one lit annunciator.
The
SRO did not comply with the actions in
the alarm response
procedure.
The
SRO did not utilize the self verification
techniques
currently being
emphasized
by licensee
management.
As the
SRO,
he
is not only expected
to use the techniques
but he is relied
upon to ensure
that the other control
room operators
apply the techniques.
The present
conditions of Unit 3 did not require
such rapid actions
on
a loss of the 480V
bus.
Operations
management
initiated corrective actions including counseling of the
involved
SRO; discussion of the incident during shift turnovers,
and
preparation of an "immediate reading"
package
on the incident.
" Immediate
readings"
are required to be read
by all Operations onshift personnel
prior to
assuming duties.
The inspector verified .that the reading
packages
were being
reviewed
and signed.
The failure of the
SRO to follow the alarm response
procedure
is
a violation.
This issue is identified as
VIO 296/95-56-01:
Failure to Follow Alarm Response
Procedures
Results
in Loss of 480V Bus.
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2.4
Failure of Secondary
Containment Isolations
To Isolate
On October 4,
1995,
whil'e swapping the inservice reactor
zone ventilation
fans,
the inboard
and outboard
supply isolation dampers,
2-FCO-64-13
and
14,
failed to isolate
as required.
The licensee
entered
TS 3.7.C.2 which required
secondary
containment integrity to be restored within four hours or place the
reactor in Hot Shutdown within the following twel.ve hours.
Operators
were
dispatched
to investigate
and determined
the problem to be due to sticking
The solenoids
were lightly tapped
and the dampers
closed
as
required.
The dampers
.were subsequently
cycled three additional
times to
provide assurance
that this was the cause of the failure.
The remaining
secondary
containment isolation dampers
were also cycled to verify they
operated
properly.
On October
5, the
1-FCO-64-14 failed to isolate
and the
cause.
was again determined to be due to
a sticking solenoid valve.
In this
case
the other damper in series
was isolated
and the system
secured,
Technical Operability Evaluation 2-95-064-1413
was written to determine
the
operability status of the dampers.
The
TOE stated that the affected valves
were operable
but that they needed
to be stroked daily until the solenoids
were replaced.
This was performed
on October
10 and
11.
The
TOE directed
that
upon experiencing
a subsequent
failure of a damper to close
due to
a
sticking solenoid,
the damper could be
made operable
by successfully
stroking
it three successive
times
and then
once per day until the solenoid is
replaced.
If the damper failed again before the solenoid could
be replaced
an operator'ould
be continuously stationed
at the damper to ensure
that it
closes
upon actuation of an isolation signal.
Paragraph
3. 1. 1 of this report
describes
additional
NRC review of this issue.
The inspectors will continue
to monitor the licensee's
actions to resolve the solenoid valve issues
and
concluded that the licensee's
actions to date
have
been
adequate.
One violation was 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
WP 19785-79.80
4kV Shutdown
Board
3EA Modification (Rework of Internals
and
Termination of Cabling/Wiring)
if'gl
On September
19,
1995,
an inspector
observed
the terminator ("re-termination"
of cabling/wiring) portion of the
3EA Shutdown
Board modification.
Specific
associated
with the
3A Core Spray
Pump motor were landed
and the
inspector
noted that the "cutback" of wiring insulation appeared
satisfactory
with no observance
of stray wiring cuts.
The wiring lugs also
appeared
satisfactory
and were of the type required
by the procedure.
Crimping of the
wire lugs to the wires was performed correctly.
The breaker
was
satisfactorily tested after the re-termination activities were performed.
Specifics of the work package
and operation of the
3A Core Spray
pump were
appropriately performed.
WO 95-18326-00
Secondary
Containment
Inboard Isolation
Damper Solenoid
Valve Replacement
'I
On October
10,
1995,
the inspector witnessed
the replacement of the solenoid
valve for the secondary
containment
inboard isolation damper,
2-FC0-64-14.
The solenoid
was being, replaced
because it had failed to properly operate
during previous cycles
as described
in paragraph
2.4.
The inspector
attended
the prejob brief which was attended
by the maintenance,
engineering,
and
operations
personnel
involved in the activity.
The participants
were not well
prepared, for the activity as evidenced
by the following examples; it was not
clear if the work would be performed with the solenoid energized
or
deenergized,
there
was confusion over whether old or new air line fittings
would be used
and
when it was decided to use
new fittings they were not
available,
and questions
concerning
what the proper post maintenance
test
should
be.
Although it was expected that these details
should
have
been
worked out prior to the briefing they were resolved prior to commencing work.
The actual
work in the field was completed with no problems
noted.
The damper
was stroked following completion of the work and performed satisfactorily.
The solenoid which was
removed
was given to engineering for causal
analysis of
the failure.
3. 1.2 Surveillance
Observations
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.
2-SI-4.5.C. I(3)
-RHRSW
Pump
And Header Operability
And Flow Test
This test is performed to verify operability of the
RHRSW pumps in accordance
with TS and to meet the requirements
of the
ASME Section
XI program.
Portions
of this surveillance
were observed
by the inspector
on September
25,
1995.
While testing the
02
pump the inspector
noted that the vibration data
was
taken while the
pump was operating at maximum flow.
After vibration data
was
taken the
pump .flow was decreased
to obtain
a specified discharge
head.
This
flow rate
was recorded
on the section
XI data sheet.
The inspector questioned
the operator
about
why the specified discharge
head
was not first established
prior to taking the vibration data.
The operator conducting the test stated
that Section
7. 14 of the procedure
required that the data
be taken with the
pump at full flow.
The inspector questioned this because
the
pump
maximum
t
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flow rate will decrease
as the
pump degrades.
If the. vibration data is not
taken
each
time with the
same
pump conditions,
the information would not be
useful for trending.
The operator
agreed
and requested
engineering
support.
The system engineer
stated that the vibration data
should not be taken at full
flow but rather at the flow required to obtain the specified discharge
head.
Based
on this information, Operations,
determined that the information
obtained
was invalid and reperformed
those portions of the specific test.
Technical
Support revised the surveillance
procedure
to clarify these
sections
of the procedure.
The inspector
asked the licensee to determine if the
operability of any of the
pumps would be challenged if the previous
performances
of this surveillance
were also performed
wrong with the
pump at
full flow.
Technical
Support
compared
the vibration data with the
pump at
full flow with the vibration data with the
pump at the required test flow.
This review indicated that the point of highest vibration with the
pump at the
flow required
by the test
was approximately
one
and one-half times the
vibration with the
pump at full flow.
Technical
Support then multiplied the
vibration readings for the remaining
pumps
by four to see if this value would
be high enough to result in any of the
pumps
becoming inoperable.
This review
indicated that if the surveillance
was performed this way in the past
and the
data collected
was actually done
so with the
pump at full flow, the vibration
readings
would still be below that requiring action.
The inspectors
concluded
that the safety significance if-the specific testing
issue
was not large
and
the corrective actions
were sufficient.
During the surveillance
the inspector also noted that the
RHR System
I flow
recorder
2-FR-74-64 spiked
when
any of the
Loop I
RHRSW pumps were started or
stopped.
Simple troubleshooting
could not identify the cause.
17904-00
was written to troubleshoot
the circuit further and facilitate
repairs.
2-SI-4.3.C
Scram Insertion
Times
On September
30,
1995,
the inspector witnessed
portions of the performance of
this procedure.
This surveillance
manually scrams
individual control
rods
and
measures
the amount of time necessary
for the rod to travel full in.
An
evaluation of control rod performance
is then
made.
The inspector witnessed
portions of this surveillance
both in the control
room and locally at the
individual hydraulic control units.
While in the control
room, it was noted
that the blue lights indicating that the control rod scram valves
were
open
did not always illuminate when the scram valves were open.
After manually
exercising the limit switches
the blue lights illuminated.
This occurred for
approximately half of the nineteen
rods tested.
The valve limit switches
provide
no function except to illuminate the blue lights in the control
room
and therefore
work orders
were generated
to perform repairs at
a later date.
To perform this surveillance,
the charging water for the control rod being
tested
was isolated to ensure that the rod is being
scrammed
from accumulator
and reactor pressure
only.
While observing the activities of the operator at
the hydraulic control unit the inspector noted that charging water isolation
valve manipulations
were not being independently verified.
The operator
was
questioned
and stated that it was not
a requirement of the procedure.
The
inspector
reviewed the surveillance
procedure
as well as the normal operating
procedure
and confirmed that the procedure
did not require
independent
Igi
gl
i/i
verification.
However, at the conclusion of the surveillance,
BFPER951392
was
written stating that the procedure
did not require independent verification at
the completion of the testing.
Operations
then independently verified the
correct position of all the valves manipulated
during the performance of the
surveillance.
None were found out of position.
At the close of this report
period, Operations
management
had not yet decided if the valves
were going to
be included in the list of equipment requiring independent verification.
This
will be resolved
as part of the closeout of the
PER.
Section 4.8 of the report describes
NRC review of Unit 3 testing
and
maintenance activities.
The above surveillance
observations
indicate that
specific testing
procedures
could
be improved.
3.2
Use of Nickel-Based
Thread Lubricants
on Gaskets
in Class
"B" Fluid
Systems
On August 24,
1995, during
a routine observation of condensate
system
check
valve maintenance,
a licensee
QA inspector, noted that the "pipe flange to
valve joint" gaskets
.were coated with a nickel-based
thread lubricant ("Never
Seez").
The
QA inspector
noted that
such action potentially allowed this
nickel-'based
thread lubricant to be in direct contact with the condensate
system water.
Leeching of this lubricant into the condensate
system
was highly
probable.
The inspector
noted that,the
WO did not specifically .identify'ny
gasket lubrication for this job and the j'ob foreman stated that lubrication of
the gaskets
with this nickel-based
lubricant was
"common practice".
The
inspector
documented
these
observations
in PER951122.
On, August 30,
an
NRC inspector,
during routine reviews of PERs,
conducted
some
followup review of the issue.
The following items were noted
from review of
TVA Specification
G-39, Cleaning During Fabrication of Fluid Handling
Component:
The job required at least class
"B" system cleanliness.
The check valve flanges
were to appear
"metal clean".
The valve flange surfaces
were to be free of oil, grease
and
any other
contamination.
The inspector .further noted that in accordance
with TVA Specification
G-29,
"Standard Haterial Specifications",
specific
and detailed
chemical criteria
for both the gasket
(PF-1060)
and gasket lubricant
(PF-1068)
were to be met
and maintained.
The inspector contacted
the
QA inspector
who initiated the
PER and
was told that any further TVA QA developments
on this issue
would be
passed
on to the inspector.
The inspector,
on. September
14,
1995,
met with
the site maintenance
manager
and
on September
29,
1995, with the site
QA/QC
manager,
and discussed
the issues.
The initial corrective actions for the
PER
failed to fully satisfy concerns
presented
by the site
QA/QC manager
and
was
sent
back for reevaluation.
Pending addi.tional
licensee
action
and inspector
review, this item will be tracked
as IFI 50-260/95-56-02,
Use of Nickel-Based
Thread Lubricants
on Gaskets
in TVA Class
"B" Fluid Systems.
r ~
IS~
~Ii
<gk
One IFI was identified.
4.0
Unit 3 Restart Activities
(37828,
61726,
62703,
37550,
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
activities
and other system recovery activities
was conducted.
4. 1
System Pre-Operability:Walkdowns
On September
27,
1995
an inspector
observed
portions of the system
preoperability walkdown of the Sequential
Events, Recording/Annunciation
System.
A pre-walkdown meeting
was .held.
The system engineer highlighted
SSP-12.55,
"Unit 3 System Pre-Operability Checklist" Appendix D,
Walkdown
Guidelines,
discussed
previously identified/observed
system discrepancies,
and
noted that the control
room
(CR) emergency
diesel
control panels
were not
within the operability walkdown boundary.
A portion of the walkdown pre-brief
and the actual
walkdown was attended
by the inspector
and
a member of the
licensee's
senior
management staff,
The walkdown was performed
by the team in
a straight-forward, direct
and methodical
manner
and in accordance
with SSP-
12.55,
Appendix
D guidelines.
Haterial condition concerns
were noted
such
as
dirty annunciator
and control cabinet interiors, dirty cabinet filters,
missing cable-tray
covers,
mi'ssing cable
harness '"tie-wraps", cable
harnesses/coverings
in need of replacement.
No major deficiencies
were found.
The post-walkdown meeting
was thorough
and met SSP-12.55
guidance.
The
inspector
concluded that the walkdown was conducted
in accordance
with
approved plant procedures
and in
a thorough manner.
On October
11,
an inspector
accompanied
licensee
personnel
on
a
Phase
1
walkdown of the Unit 3 Hain Steam
System.
This walkdown was rescheduled
after
the original September
8,
1995 walkdown was canceled
due to too many
unresolved,
previously 'identified deficiencies
being observed
( IR 95-51).
A
pre-walkdown meeting
was held.
The system engineer,
presented
SSP-12.55,
Appendix D,
Walkdown Guidelines
and conducted
an adequate
brief of
previously identified discrepancies.
A portion of the walkdown was attended
by the inspector.
The walkdown was perfor'med
by the assigned
walkdown team in
a direct/thorough
manner
and in accordance
with SSP-12.55
Appendix
D
guidelines.
Host of the material
condition concerns
were minor such
as loose
instrument
panel
bracketing,
loose conduit connectors.
However,
concerns with
outboard
HSIV operation
remained
and were planned to be addressed
prior to the
Phase
2 walkdown.
The inspector
found performance of the
Phase
1
walkdown to be acceptable
and in accordance
with approved plant procedures.
4.2
Drywell Tour
On September
27,
one of the inspectors
conducted
a detailed tour of the Unit 3
drywell.
The inspector
focused
on the upper elevations
given that fuel load
was expected
in two weeks.
The inspector noted that the reassembly
of
insulation
was progressing well.
The insulation
on the reactor vessel
level
I/i
gl
'g
10
indication reference
leg piping was examined closely
and noted to be in
accordance
with the discussion
in
GE Service Information Letter 470
and in
good condition.
While the drywell was not yet ready for fuel load or startup,
the inspector did not identify any serious deficiencies
in the overall
material condition of the upper levels.
The inspectors
noted that the lower elevations of the drywell will require
considerable effort before they are ready to support startup.
The
inspectors
noted that the recirculation piping wire restraints
were very
loose'nd
questioned if tightening
was scheduled.
A small
amount of trash
was
observed
inside
some ventilation ductwork.
Wedges
were noted
on several
spring cans
on the main steam piping.
The inspectors
also questioned
what
appeared
to be excessive
slack in the cabling running from junction boxes to
the sonic detectors
on the main steam relief tailpipes.
These
items were
discussed
with management.
Some of these
issues
were already in the
licensee's
plans to be resolved.
The licensee initiated actions to address
the remaining issues.
The inspectors
also noted that
an
contained fibrous .insulation
which ended flush with the drywell interior end of the penetration.
The Unit
3 Restart
Manager indicated that the penetrations
are in the process
of being
walked
down for assessment
of corrective actions.
The inspectors
scheduled
a
meeting with site engineering
personnel
to address
the penetration
questions.
This specific issue will be addressed
as part of the inspector's
review of NRC
Bulletin 93-02 prior to Unit 3 drywell closeout.
The inspector
also verified that the
FME barriers
from the drywell to the
torus were still intact.
At the close of the inspection period,
the licensee
had initiated
a thorough cleanup of the drywell.
The inspectors will continue
to monitor the conditions in the Unit 3 drywell.
4.3
Review of Reactor
Water Cleanup
System
(RWCU) Installed Thermocouple
Modifications
One of the inspectors
performed
a review of the location, setpoint
calculations
and the actuation logic for the newly installed Unit 3
thermocouples.
This modification was
made
as
a corrective action to design
and install
a qualified leak detection
system which could detect
and isolate
RWCU pipe breaks
including critical cracks
in the Main Steam Valve Vault,
pump rooms
and heat
exchanger
areas.
The modification removed
from service
originally installed temperature
switches
and replaced
them with
thermocouples.
The modification also set in place
a new logic system for
automatic actuation of the reactor containment isolation
and
RWCU system
discharge
valves.
This modification took into account the revised design for
the
RWCU system
implemented
by other
RWCU modifications.
In a related
June,
1993,
NRR evaluation of the adequacy of the Unit 2
system line break detection circuitry (Unit 3 is similar),
NRR concluded that
while the
RWCU isolation design did not fully meet
RWCU isolation
requirements, it was consistent with BFN's licensing basis
and was
acceptable.
The
SER also stated that since the
RWCU design relied upon direct
operator action to verify and isolate
a postulated
leak, further verification
~
i
01
11
of operator
information/guidance
adequacy
was necessary.
The inspector
reviewed procedures
and concluded that sufficient operator guidance
was
contained within the following documents:
3-ARP-9-3D
Operator
response
to an
RWCU Leak Detection Circuitry High
Temperature
Alarm/Annunciator (3-TA-69-29)
3-ARP-9-5B
Operator
response
to
an
RWCU Isolation Logic Channel
"A"
High Temperature
Alarm/Annunciator (3-TA-69-834A)
3-ARP-9-5B
Operator
response
to
an
RWCU Isolation Logic Channel
"B"
Hi'gh Temperature
Alarm/Annunciator (3-TA-69-834A)
3-AOI-64-2a Group
3
RWCU Isolation
The inspector
also performed
a walkdown of RWCU pump rooms
and heat
exchanger
areas
and noted location of the installed thermocouples.
The inspector
determined that both the actual detector location
and selected
placement of
the associated
"A C" thermocouples
and
"B D" thermocouples
was adequate,
considering
both actuation logic necessity
and range required for a detection
of thermal
change
in these
areas/rooms.
The inspector
also reviewed the following temperature
calculations for
adequacy of both the calculations
and suppositions:
HD-f3069-920188; Analytical Limits For
RWCU Room Temperature
Isolation
ND-f2069-930032;
RWCU System
Response
to
a Critical Crack Downstream of
the Non-Regenerative
Heat
Exchangers
ED-f2069-890080;
Setpoint
and Scaling Calculations
TE-69-834A-D/835A-
D/836A-D/837A-D/838A-D
Based
on this review, the inspector
concluded that the
RWCU thermocouple
modification was properly implemented.
Thermocouple
placement,
associated
circuitry
and calculations
were adequate
to support Unit 3
RWCU system
operation.
4.4
Flexible Conduit Reviews
On August
17,
1995,
NRR representatives
reviewed information at the site
pertaining to flexible conduit design evaluation.
Among the key items
examined
were: the licensee's
flexible conduit related
commitments,
basis for
categorization
of flexible conduits within the scope of 10 CFR 50.49
and those
belonging. to USI A-46 scope,
basis for licensee's criteria set forth in
General
Engineering Specification
G-40, listing of flexible conduits
evaluated,
results of the licensee's
flexible conduits
walkdown, conduit
separation criteria, basis for determination of the straight line distance
"SD" and
a factor to account for thermal
and seismic displacement
"K,"
documented
engineering justifications for selected flexible conduit outliers,
and the background for the
use of the terminology related to long term vs
interim flexible conduit criteria.
41
i/i
12
The staff performed
a walkdown of several
randomly selected electrical
equipment with newly installed flexible conduits which replaced
those
determined
to be not conforming to the G-40 criteria.
The staff also examined
other randomly selected
equipment with flexible conduits which were judged to
be not conforming to the G-40 criteria, but were technically justified to
remain "as-installed"
based
on case specific evaluation.
The walkdown of
these
items provided
an additional
basis for the staff to conclude that the
licensee
did implement or is implementing
an adequate
and satisfactory
evaluation
program for BFN flexible conduits belonging to both
and
USI A-46 scopes.
Based
on review of the licensee
submittals related to flexible conduit
criteria for BFN plants,
previous review and acceptance
of criteria used for
resolution of flexible conduit issues
identified in Unit 2 restart
program,
the results of numerous
evaluations
performed
by the licensee for existing
flexible conduit configurations
at the licensee
plants,
the results of design
audit of the licensee's
G-40 criteria and related
engineering
documents,
and
the results of selected
walkdown of several flexible conduit modifications,
NRR has
found that the licensee's
use of the G-40 criteria to eva'luate
the
seismic
adequacy of flexible conduit not connected
to
10 CFR 50.49 electrical
equipment
and within the scope of the
2 and
3 is
conservative
and acceptable.
Examination of sampled flexible conduit
installations
at the site were satisfactory.
Additional details of the staff's review are
documented
in a safety evaluation
dated
October 3,
1995.
4,5
Unit Separation
Program
During the period of September.
19-22,
1995,
an inspector
reviewed the
activities associated
with the unit separation
program related to the recovery
of Unit 3
~
This program is defined
by procedure
SSP 12.50, Unit Separation
For Recovery Activities.
This has
been
accomplished
by isolating Unit 3
recovery activities
and Unit
1 layup efforts from Unit 2 operational
requirements.
Tagging,
marking, signs,
and color coded drawings
have
been
used to implement these
requirements.
As Unit 3 systems
have
been
recovered
by use of the
SPAE
and
SPOC process,
these
requirements
have
been
removed.
The system engineer
completes
form SSP-161,
Permanent
Removal of Unit
Separative
Boundaries,
to notify site engineering that the boundary isolation
color codings
can
be removed
from drawings.
Once the drawings
are corrected,
Operations
removes
the affected separation
hold order tags,
signs,
tape
and
other markings
from the plant.
The inspector
reviewed procedure
12.50
and completed
SSP-161
forms.
Twelve of the forms were reviewed.
Several
color coded drawings
were reviewed
in the control
room and
TSC.
No problems
were noted.
The inspector
toured
the Unit 3 reactor building looking for removal of isolation boundaries
and
color coded markings
on unit 3 systems.
In general,
for systems that
had
completed
the
SPOC process
the isolation boundaries
and orange
tape
had
been
removed.
The inspector
reviewed the Unit 3 core spray
system for which the
phase II SPOC
was completed
on September
7,
1995;, and the
EECW system for
which the phase II SPOC
was cqmpleted
June
30,
1995.
The inspector
compared
l
41
13
system
33, service air in Unit 3 and Unit l.
Unit
1 still had the isolation
boundary identified but not in Unit 3.
In general
there
was
a one to one
correlation
between
completed
systems
in Unit 3 and activities for removal of
the separation
requirements.
The inspector discussed
the unit separation activities with a'nit
3 control
room operator.
The operator
was very knowledgeable
on the plans for the
separation
program.
The operator provided
a one
page outline of the
activities in progress
and planned unit recovery activities near completion.
These
plans consisted
of moving out of the separation
program with deletion"of
the separation
requirements.
A revised
procedure
and program would delete the
color coded drawings
and
end
up with a unit separation
program that protects
Units
2 and
3 from Unit 1.
The inspector
concluded that plant personnel
were
well informed concerning
the separation activities.
These activities provided
a controlled
and logical transition coinciding with the completion of Unit 3
recovery activities.
4.6
Unit 3 Reactor
Vessel
Level Backfill Modification
The inspector
reviewed field modifications associated
with W32456A which
installed the backfill system for the reactor vessel
level
system.
A walkdown
of the instruments
and controls
was performed to verify they were installed in
accordance
with the applicable
drawings.
Piping configuration
and labelling
was also verified.
This walkdown identified no discrepancies
with the
installation of these
components.
However,
the inspector identified that.
supports
had not been installed for portions of piping associated
with the
four flowmeters which were required in accordance
with drawing change
authorization
3-47B600-2512-1,
revision 0, detail
B.
Site engineering
was
notified and confirmed that the supports
were required.
Following
installation,
the inspector verified the supports
were installed
as designed.
This issue is discussed
in more detail in IR 95-57.
The inspector
also reviewed the completed post-modification test
package.
This test
was essentially
the
same test performed following the modification
previously performed
on Unit 2.
Although the test
was completed
.
satisfactorily,
one Test Deficiency Was written to document the rapid level
changes
noted
when operating
the condensing
pot shutoff valves 3-SHV-085-0850,
0852,
0854,
and 0856.
The indicated level
swings noted
when the valves were
rapidly opened
were approxi'mately twenty-five inches in magnitude
which was
similar to what was experienced
during the Uni't 2 test.
The Test Deficiency
was dispositioned
by adding
an item to the site tracking system to issue
a
procedure
which will be used to operate
these valves.
Notes or cautions will
be in this procedure to ensure
the valves are operated
slowly and
deliberately.
This .item is. scheduled
to be completed
by Unit 3 restart.
The inspector
concluded that .with the exception of the noted tube support
problem,
the Unit 3 reactor
vessel backfill modification was
implemented
and
tested satisfactorily.
4.7
Unit 3
Eg Program
~I
IR 94-35 documented
a review of the Unit 3
EQ Program Plan.
The
EQ issues
identified in the Unit 2
NRC
SER were addressed
for Unit 3.
The report
concluded that the scope of the Unit 3
EQ Upgrade
had not been
reduced
from
what was accomplished for Unit 2.
The inspectors
review of the Unit 3
program consisted
of a review of the
EQ equipment in Unit 3 which was not in
the Unit 2
EQ Program.
Additi'onally, selected
DCNs and
EQ related
emergent
issues
were reviewed.
The following EQ Binders were identified which were
Unit 3 specific:
BFN-3-PENE-003,
GE Electrical Penetration
Assembly
BFN-3-ECON-001
Electrical
Connectors
BFN-3-CABL-052
Anaconda
Cable
BFN-3-CABL-053
ITT Surprenant
Cable
The inspectors
reviewed
EQ Binders
BFN-3-PENE-003,
BFN-3-CABL-052, and
BFN-3-
CABL-053 to determine if they established
environmental
qualification for the
subject
equipment.
EQ Binder BFN-3-PENE-003,
Revision 0,
GE Hodel
F01 Canister Electrical
Assembly
was reviewed.
The binder indicated that the
required qualification to the requirements
of 10CFR50.49
and
Nureg 0588 Category
II/DOR Guidelines.
The Binder was prepared
to the
requirements
of procedure
PI-88-11.,
Preparation,
Haintenance,
and Control of
the Environmental Qualification Documentation
Packages
(EQDPs).
The
inspectors
reviewed the documented test data
and verified that it met the
qualification requirements
of 10CFR50.49
and the
DOR Guidel.ines.
The binder contained
two open items, unqualified pigtail connectors
and beta
shielding for drywell side pigtails for
EQ .circuits.
The inspectors
examined
assemblies
BA and
EC drywell side
and noted that
EQ circuits were
wrapped. with beta tape
and the penetration
assembly
was sealed with foam from
the header plate to the
end of the header
per drawing 3-45W803-23
Revision 4.
On the Reactor Building side the inspectors
noted that the
penetration junction box for penetration
BA did not contain
a weephole.
The
work to drill the weepholes for several
EQ junction boxes
had not yet been
performed.
Work Request
WRC294693
had already
been written for this work.
The pigtail wiring was verified to match the field configuration requirements
in the binder.
The inspectors
considered this
EQ Binder to be adequate.
EQ Binder BFN-3-CABL-052, Revision 0, Anaconda. Cable-
TVA Type
HS Signal
Cable
was reviewed.
The binder documented
that the cables
were qualified to the
requirements
of 10CFR50.49
and
Nureg 0588 Category
II/DOR Guidelines.
The
binder,was
prepared
to the requirements
of procedure
PI-88-11
and contained
no
open items.
EQ Binder BFN-3-CABL-053, ITT Surprenant
Cable - TVA Type
HS Signal
Cable
was
reviewed.
The binder was in preparation for initial issue
and documented
that
the these
cables
were qualified to the requirements
of 10CFR50-.49
and Nureg 0588 Category
II/DOR Guidelines.
The binder
was prepared
per procedure
PI-88-
11
and contained
no open items.
0
igl
~~
15
The inspectors
reviewed the test reports
and verified that the test results
met the minimum requir ed performance
requirements.
Applicability of the test
data to the installed cables
was addressed
in the binders.
From review of
these
two binders it was difficult to verify comparison of the test results to
the minimum acceptable
plant performance
requirements.
The minimum tested
insulation resistance
of approximately
lE7 ohms
met the minimum performance
criteria for these
cable types of lE4 ohms.
The licensee
prepared
an
administrative
change to revise the binders
summary section in Tab C/C-6 for
test performance
acceptance.
This was acceptable
to the inspectors.
The inspectors
performed field verification of selected
cables to ensure that
installed cables
met the configuration description
in the
Eg binder
and were
traceable
to the test data in the binders.
The following cables
were
verified:
Anaconda
Cables
(Binder BFN-3-CABL-052)
ITT Surprenant
Cables
(Binder BFN-3-CABL-053)
3PP656
3PP839
Panel
23D
Panel
'23D
The cable types
and cable jacket contract data
matched
the data in the
respective
Eg Binder.
The inspectors
concluded that these
two
Eg Binders
adequately
documented qualification of this equipment to 10CFR50.49
and Nureg
0588/DOR Guidelines
requirements.
The inspectors
reviewed
a sample of Eg
DCNs and performed
walkdowns to verify
that the installed field configuration matched
the design requirements
of the
DCNs.
Field Verification was performed for the following equipment:
3-FCV-74-057
3-FCV-74-059
3-FCV-77-002B
3-FCV-77-0015B
Junction
Boxes
JB0107A and JB0107F
Electrical Penetrations
BA and
EC
DCN W20902A included design
changes
to ensure
environmental
qualification of
valves
3-FCV-74-057
and 3-FCV-74-059.
The changes
implemented
by this
DCN for
3-FCV-74-057 included limit switch compartment
low point T drain,
replacement
of the power terminal block,
and replacement
of the control circuit internal
wiring.
DCN changes
for 3-FCV-74-059 included limit switch compartment
low
point T drain,
removal of control wiring terminal block, replacement
of the
power terminal block, replacement
of the limit switch,
Raychem splices
in the
motor center
taps,
and replacement
of the internal wiring,
The inspectors
verified that the
Eg configuration
changes
had
been
implemented to meet the
DCN requirements.
During the initial inspection,
actuator
3-FCV-74-057
was
oriented
such that the limit switch compartment
T drain was at
a high point.
IQi
i/i
16
The actuator
had
been oriented for HOV testing.
The inspectors later verified
that the actuator
was correctly oriented following completion of the testing.
DCN W17424 contained
requirements for ensuring qualification of the
GE FOI
electrical
This consisted of providing shielding to the drywell
side penetration pigtails.
Raychem
WTBF tape
was installed
on the drywell
side
Eg circuit pigtails
and the penetration
was sealed with foam from the
header plate to overlap the beta tape.
This change
was to prevent post
accident
beta radiation
damage to the drywell side penetration pigtail
insulation.
The inspectors
examined penetration
EC and
BA on the drywell side
and verified that the configuration met the
DCN requirements.
DCN W21813 included design
changes
to ensure qualification for the electrical
components
associated
with valves 3-FCV-77-002B and 3-FCV-77-0015B.
The
changes
consisted
of adding qualified conduit seals
to the existing solenoid
valves,
replacing the limit switches with qualified switches,
and installing
qualified conduit seals
on the limit switches.
The inspectors verified that
the installed field configuration incorporated
these
DCN changes.
The licensee
prepared
work orders to seal
Eg junction boxes with RTV sealant
to prevent moisture intrusion.
Additionally, weepholes
were required to be
drilled in the bottom of the sealed
boxes.
The inspectors
noted that junction
boxes
JB0107A and
JB0107F were sealed with RTV but did not contain weepholes.
The licensee
had
an open work order,
WO 951840302;. which had not been
completed to drill weepholes
in these
and other
Eg junction boxes.
The
inspectors
concluded that the licensee
was adequately
implementing
Eg program
DCNs.
The inspectors
reviewed selected
Eg,related
LERs,
PERs,
and
NRC items to
determine if the licensee
was adequately
addressing
Eg related
emergent
issues.
LER 94-02
was reviewed in detail.
No deficiencies
were identified
and the licensee's
corrective actions
were adequate.
The inspectors
concluded that the Unit 3
Eg program is being
implemented
in
accordance
with the program plan
and regulatory requirements.
4.8
Unit 3 Testing Activities
4.8. 1 Residual
Heat
Removal
System
The inspectors
reviewed portions of the Unit 3 Restart Testing
on System
74,
Residual
Heat
Removal
System.
The testing which was observed
included O-TI-
36A,
RHR Heat Exchangers
Leak Test,
and 3-SI-4.5.B. I.d (I), quarterly
System
Rated
Flow Test
Loop I.
RHR Heat Exchanger
Leak Test
was intended to determine if the
Loop I
RHR Heat
Exchangers
3A and
3C exhibited leakage
between
the shell
and the tube side.
The inspectors
observed
no increase
in
RHR pressure
on control
room pressure
indicator 3-PI-74-51 with RHR Service
Water pressurized
with an
Pump
running.
This testing activity was considered
acceptable.
ill
17
quarterly
RHR System
Rated
Flow Test
Loop I was performed per procedure 3-SI-
4.5.8. l.d (I)., The inspectors
witnessed
the flow test of RHR Pump
3A and
verified that the
pump met the acceptance
criteria of > 9000
gpm and
p 125
psig.
Actual observed
values
were
9000
gpm at
175 psig.
The acceptance
criteria of the procedure
met the requirements
of Unit 3 Technical Specification 4.5.B. l.d,
RHR System
Pump Flow Rate.
During the
RHR Pump Rated
Flow Test,
leakage
was noted at
RHR Heat Exchangers
3A and
3C.
The leakage
was determined to be from the shell
side
(RHR) located
at the second
flange from the top, the
The licensee
initiated work requests
WRC317208
and
WRC286110 to investigate
and repair
3A
and
3C
RHR Heat
Exchanger
leakage respectively.
Work Orders
WO 91-42438-01
and
WO 91-42439-01
were performed
on
RHR Heat
Exchangers
3A and
3B respectively.
The
RHR heat
exchangers
flange bolts were
tightened to the
maximum torque allowed by Procedure
MCI-0-074-HEX001.
The
heat
exchangers
were still leaking.
Engineering
was assigned
the task to
resolve the leakage.
DCN TDCN 38580
was prepared
to evaluate
and repair the
heat exchanger
leakage.
During the
RHR flowrate testing,
the licensee
attempted to perform Loop II
Simulated
RHR Automatic Actuation Test per 3-SI-4.5.B. l.a (II).
An
inadvertent start of the
3C
RHR pump occurred during this testing
due to
a
procedure error.
The operators
secured
the
3C
RHR pump within the
maximum
allowable
3 minute period at minimum flow.
Step 7.2. 11 of procedure 3-SI-
4.5.B. l.a (II) attempted
to inhibit the
Loop II redundant start signal to the
Loop I
RHR pumps
3A and
3C.
The procedure
called for booting contacts
5-6 of
redundant
auto start relays
10A-K25B and
10A-K47B to inhibit the start of RHR
pumps
3A and
3C.
The licensee
determined that the procedure
specified the
incorrect contacts.
A procedure
change
was
made to boot auto start relay
contacts
1-2
and the testing
was completed.
The inspectors
reviewed drawing
3-45E766-21,
Revision
17, Wiring Diagram 4160
V Shutdown Auxiliary Power
Schematic
Diagram,
and verified Loop II redundant start signals to
RHR pumps
3A and
3C were relay
10A-K258 contacts
1-2 and
10A-K47B contacts
1-2
respectively.
The licensee initiated
PER
BFPER951365 to investigate this
procedure
issue.
4.8.2 High Pressure
Coolant Injection System
On September
27,
1995,
an
NRC inspector
observed
the Appendix
R Backup Control
Panel test for HPCI.
The test
was performed using Technical
Instruction 3-TI-
165B.
The purpose of the test
was to demonstrate
control
room electrical
isolation
and remote operability of the
HPCI turbine
steam supply valve 3-FCV-
73-16.
The inspector
observed
the boot inhibiting of relay 23A-K47 and
jumpering of several
contacts
(to prevent
unwanted valve operations
during the
testing).
These
components
were located
on panel
3-9-39 within the Unit 3
Auxiliary Instrument
Room.
Independent verification of these
procedure
steps
was observed.
The specified test
acceptance
criteria were met.
No other test
discrepancies
were identified during conduct of testing.
The inspector
concluded that the restoration activities
and testing of the
Appendix
R Backup Control for HPCI had proceeded
in a controlled manner.
The
ill
igl
i/i
18
test demonstrated
proper control
room isolation
and remote
HPCI turbine steam
supply valve operation.
The licensee's
independent verification of system
test configurations
was adequate.
However, during the test observation,
the inspector
noted significant
accumulation of dust
and lint on electrical
cabinet ventilation filters
located in the Unit 3 Auxiliary Instrument
Room.
The inspector identified
this situation to the licensee
operations fire protection management.
The
inspector indicated that this condition
may reduce cooling air flow to
instruments
during
a time of increased
energizing of equipment
due to restart
activities causing
equipment
overheating
and
a possible fire event.
Licensee
management
initiated corrective action
and the panel filters were cleaned.
On October
11,
1995,
an inspector
observed
operation of the Unit 3 HPCI system
(on auxiliary steam)
in accordance
with HSI-3-073-GOV001,
HPCI Turbi'ne
Trip Test
and Turbine Stop Valve Balance
Chamber Adjustment.
Although several
equipment
problems
delayed the testing, it was later
completed successfully.
A pre-. brief was conducted.
There
was adequate
maintenance
and engineering
personnel
present
to support the testing.
Operations
personnel
were appropriately cautioned
in the operation of the
turbine
and communications
were good.
Operators
used
procedures
when
performing adjustments.
FHE practices
when the overspeed
assembly
access
plug
was
removed
were good.
Two deficiencies
were noted.
During the performance
of step 7.3.26,
valve 3-SHV-73-0707
(governor valve closure booster oil valve
was found to be
6 turns
open instead of the expected I/2 turn open).
After
the turbine
was started, it was noted that the main oil pressure
was indicated
as zero
and the auxiliary oil pump continued to run.
HPCI was tripped
and it was determined that valve 3-RTV-073-0231A was shut
instead of open.
The following day, the inspector
requested
the cause of the
apparently
improperly positioned
valves since the
I process
has
been
completed
on HPCI.
After additional
review, the licensee identified that the
73-0707 valve was listed incorrectly'on the OI-73 checklist
as "open".
The
73-231A valve was listed
on Attachment
4 (instrument lineup)
and not reopened.
PERs were subsequently
initiated and portions of the lineup were completed
again.
On October
13,
1995, the inspector
observed
operation of HPCI in accordance
with 3-TI-343,
HPCI Injection Line Flush
and 3-0I-73,
HPCI System.
Auxiliary
steam
was
used to run the turbine.
HPCI piping to and from the
CST was
flushed
and then flow was directed to the vessel
to flush the injection line.
Testing
was delayed initially because
during bypassing of the high water level
trip, incorrect leads
were lifted and it was identified that the turbine would
not trip from CR.
A PER was. initiated to address
that problem.
Subsequently
it was determined that
an incorrect lead
was lifted during the disabling of
the high reactor water level trip function.
During the delay in testing,
the
inspector questioned
CR personnel
regarding the operability of the
HPCI oil
cooler discharge
high temperature
The inspector
had
noted that 3-TS-73-52
was disconnected,
rendering
the annunciator
The switch failed and
a replacement
is being obtained.
CR personnel
were not
aware that the annunciator
would not function,
Compensatory
CR monitoring
actions
were not planned.
Personnel
in the
HPCI room were
aware of the status
if'/i
19
of the alarm
and
a local temperature
had
been monitored during the
previous
testing.
The inspector
noted, that the annunciator
status
was not addressed
during the pre-brief and the
CR panel
window was not labeled
to indicate its status.
It should
be noted that the
SPOC II process
has not yet been
completed
on the
Unit 3 HPCI System.
The above
issues
indicated that status of equipment
during/prior to testing activities was not well controlled.
In the case of
the valves not properly positioned,
an additional
concern
was that the
inspector
prompted resolution of the cause of the deficiencies.
4.8.3 Control Air System/Drywell
Control Air System
.The inspectors
reviewed the licensee's
control of moisture in the control
air/drywell control air systems.
Moisture control
was
by use of desiccant air
dryers in the control air system
and
by refrigerant air dryers in the,drywell
control air system.
The,licensee
performed monthly dewpoint checks
on the
operating air systems
per procedure
O-TI-34, Monthly Control Air System Dryer
Dewpoint Test
and
Purge Control, to monitor air dryer performance.
The procedure
acceptance
criteria for control air required control air
dewpoint at line pressure
to be
<18.
F below outside
ambient dry bulb
temperature
and dewpoint at line pressure
to be
< 35'.
For drywell control
air the procedure
acceptance
criteria required dewpoint at line pressure
to be
<
18 F,below local reactor build'ing ambient dry bulb temperature
and dewpoint
at line pressure
to be
< 39'.
The inspectors
reviewed the following completed
work orders to determine if
the dewpoint test results
met the procedure
acceptance
criteria:
913798600
925863800
931399200
940764200
941803700
941913200
942014400
950051000
950069500
950400100
The inspectors
noted that the work orders
documented test results
which met
the dewpoint acceptance
criteria except for
where the
2A drywell
control air compressor
dewpoint of 43.7'
was
above
the- 39
F dewpoint
acceptance
criteria.
The licensee
documented
the test deficiency
and
repaired/reset
the refrigerant dryer temperature switch'he retest
which was
documented
in. WO 941242800
was reviewed
and the results
met the dewpoint
acceptance
criteria.
Unit 3 drywell control air samples
were taken after the system
was placed in
service following system flushing activities.
The sampling
was performed in
accordance
with procedure
3-TI-176, Drywell Control Air Sampling.
The
acceptance
criteria was
<
1
ppm hydrocarbon
and
<
1 particle
h
5 microns.
The
results of <
1
ppm hydrocarbon
and 0.2 particulate for both header
samples
met
the acceptance criteria'he
inspectors
reviewed the results of the dewpoint
testing of the Unit 3 drywell control air system after the system, was placed
into service.
The results of the dewpoint checks
met the acceptance
criteria
. ~
Igi
i/i
Igk
20
of procedure
0-TI-34.
The inspectors
concluded that the licensee's
control of
moisture in the control air and drywell control air systems
was adequate.
IR 95-51
documented
an instance
where drywell control air compressor
38 local
control station handswitch,
3-HS-032-0067
was found in the
AUTO position while
a tagout required it to be in the
OFF position.
The switch is located
in an
area
where it is subject to being
bumped
and inadvertently mispositioned
by
personnel traffic.
The inspectors
noted that
a guard
had
been installed
on
the switch to prevent further mispositioning.
4.8.4 Hain Steam Isolation Valves
On October
1,
1995,
the inspector
observed
portions of surveillance test 3-SI-
4.7.D. l.a-3,
Hain Steam Isolation Valves Closure
Time Test.
The testing
involved the stroking of the Outboard
HSIVs only.
During the testing
evolution,
a number of minor procedural
deficiencies
were encountered
as the
procedure
was being performed for the first time on Unit 3.
These
deficiencies
were noted
and documented
appropriately.
A more significant
problem was discovered
during the cycling of MSIV 3-1-27.
When the operator
attempted
to open the valve,
no valve movement occurred.
The operator
stopped
the test to investigate
the problem.
The investigation revealed that
an air
supply valve, 3-32-2586,
was closed in lieu of the required
open position.
Upon further discussions
held within the control
room and personnel
at the
HSIV, it was determined that the valve in question
(3-32-2586)
had
been
closed
the previous
day due to
an air leak in the vicinity.
The repositioning of the
valve was not documented
in the system
32 (Control Air) status
log as required
for a system that
had previously undergone
Phase I.
The Unit 3
SRO had
assumed
that because
plant maintenance
personnel
were
aware
of. the air leak,
a
work order would be initiated
and clearance
would be placed
on the valve to
facilitate the repair.
This is the second
example of an instance
where status
control
was not being rigorously maintained
on
a Unit 3 system that
had
undergone
the
1 process.
Paragraph
4.8.2 describes
two HPCI
instrumentation
valves which were found incorrectly positioned during testing.
Neither of the systems
have
been declared
at the time the issues
were
noted.
The residents will continue to monitor the licensee's
progress
in this
area.
4.8,5 Reactor
Core Isolation Cooling
On October 9,
1995,
the inspector
observed
portions of the performance of 3-
SI-4.2.B-40A,
RCIC System Logic Functional Test.
The procedure
was performed
in a satisfactory
manner with minor procedural
deficiencies,
such
as
typographical
errors
and
a reference
to
a wrong fuse number; dispositioned
in
an appropriate
manner.
The procedure
demonstrated
that the
RCIC system would
automatically restart
on low reactor water following a trip on high level
as
required
by THI action item II.K.3.13.B.
On September
30, the inspectors
observed
portions of overspeeed
testing of the
RCIC system
on auxiliary steam.
Although several
delays
occurred
due to emergent
equipment
problems,
corrective actions
were completed
as required
and
no deficiencies
were noted
involving conduct of the testing.
No violations or deviations
were identified.
IS~
~(
~gi
21
4.9
Corrective Action Tracking Documents
On September
11,
1995,
the licensee
submitted
a letter to the
NRC which
documented
the current status of the Unit 3 CATDs.
In letters
dated
September
5,
1995
and January
18,
1995, .the licensee
had previously explained that
intentions
were to pursue
completion of corrective actions for all Unit 3
CATDs prior to Unit 3 return to service.
The Unit 3 "open"
CATDs have
been
"rolled over" into NCOs
and tracked in TROI like other open issues.
IR 95-10
and 95-26 documented
NRC inspection of the process
used for rollover and
closure of the
CATDs.
Numerous
NRC inspections of CATD corrective actions
have
been
completed
over
the last year.
Frequently,
CATDs were reviewed during
NRC inspection of
related technical
issues.
The inspectors verified that actions
were completed
and in most cases
checked that the original concern
was addressed
adequately.
No significant discrepancies
were identified during any of these
reviews.
The
licensee's
review and closure of the corrective actions for CATDs have
been
extensive
and conservative.
The September
1'1,
1995 letter stated that corrective actions for eleven
CATDs
are not expected
to be completed prior to Unit 3 return to service.
Return to
service in this correspondence
is defined
as criticality which is currently
scheduled
for the middle of November.
The eleven
open issues
can
be divided
into the following categories:
Six are pending resolution of USI A-46 issues
which are currently
scheduled for Harch
19,
1996.
Two involve personnel
safety issues
(rigging) associated
with Hain Steam
Relief valve removal/reinstallation.
One is connected
to the security upgrade project (security lighting
drawings)
which is expected
to be completed
in January
1996.
One involves potential
inleakage
to the Control
Room Emergency
Ventilation Syst'm (question of GDC 19 compliance).
This issue is
pending additional
NRC review and is expected
to be resolved
by February
29,
1996.
In
a letter dated
Harch
19,
1993,
the
NRC stated that the
licensee
had adequately
addressed
each of the staff's concerns
at that
time,
Additional
NRC review is being conducted
regarding details of the
dose calculations.
One is pending inspection of feed
pump minimum flow lines for excessive
vibration.
The lines will be checked during feed
pump operation.
Corrective actions
are scheduled for completion
by January
3,
1996.
The inspector
concluded that these
open corrective actions
do not represent
significant deficiencies
which would preclude restart.
The majority of the
incomplete actions
are pending completion of extensive
longterm projects.
The
inspector
reviewed the status of open
items associated
with CATDs.
As of
October 6, there
were approximately
30 open
items that
had
CATD actions
associated.
The licensing manager is tracking resolution of these
items
~
i
)0(
~i
22
closely.
Although several
large
scope
(program issues)
CATDs remain to be
closed close to startup,
the inspector
concluded that the schedule of CATO
corrective action completion is attainable.
Based
on the
NRC inspections
which
been
completed
on the
CATDs with positive results,
and this review of the
remaining
open actions,
the inspectors
concluded that the Unit 3
CATDs have
been
adequately
addressed
by the licensee.
The number of incomplete
CATD
corrective actions
on Unit 3 at restart will be significantly lower than the
corresponding
number
open at Unit 2 restart.
4. 10
Nuclear Performance
Plan Issues
During reviews last year to ensure that all potential safety issues
wer e
scheduled
for inspection prior to Unit 3 restart,
the inspectors
noted
two NPP
items which appeared
to be not specifically addressed
by any other open items.
The two subjects
were
HPCI governor controls
improvements
(page
IV-17) and
resolution of open Corrective Action guality Reports
(page II-58).
The inspector
reviewed
NRC documents
and did not identify any specific
regulatory concerns
involving the
HPCI governor control
system.
From review
of licensee
documentation,
the inspector determined that
a
1986 task force had
developed
a list of HPCI improvements.
The list consisted
of numerous
modifications.
DCN W23730A involved modification of the electro-hydraulic
controls
intended to improve governor valve response
and reduce
the overspeed
on HPCI starts.
Other
HPCI improvements
were included in
DCN
W17834A.
The inspector
reviewed SILs 336,
351
and
480 to gain additional
understanding
of HPCI operations
and testing.
The inspector
reviewed the packages
for DCNs W23730A and
W17834A and verified
that selected
testing listed
on the
SSP-121
form had
been completed.
The
inspector
examined
the
new
EG-H control
box and
ramp generator/signal
converter.
The model
numbers
matched
those
in the modification documentation.
Selected
conduits
and wiring connections
were verified to match the
DCAs.
The inspector
walked
down the control oil piping and verified that the
installation matched
the drawings
and the changes
describ'ed
in the
modification had
been
completed.
The inspector identified that the details
section of drawing 3-47E812-2
(CCD flow diagram of HPCI oil system)
did not
match the installed configuration.
Two oil lines between
the
EG-R and the
remote
servo were not connected
as
shown.
A licensee
engineer verified that
the drawing was in error and that actual installation
was correct.
Potential
Drawing Discrepancy
95-501
was initiated to address
the identified problems.
One minor labeling error was also noted
and reported for correction.
As described
in paragraph
4.8.2 of this report,
HPCI was operated
on October
11
and
13,
1995
on auxiliary steam.
The overspeed trip was successfully
tested
and flow was injected into the reactor vessel
to flush the injection
line.
During these
operations,
the
HPCI governor
system
appeared
to operate
properly.
PERs
951485
and
951486
and 951486 were initiated on October
12 to
address
problems involving the governor system.
PER 951486
addressed
problems
with the
ramp generator
and signal converter.
Defective parts
and assembly
problems
were identified on parts
drawn from supply.
Additionally, the spares
were apparently
not periodically energized
as the vendor storage
instructions
IO~
ig>
Igi
23
recommended.
Failure to properly store
spare
EG-N parts
has
been recognized
by other utilities as
a cause of failures.
In 1994,
the resident
inspectors
had questioned
the licensee
on
EG-N parts storage
practices
and received
information indicating that the
EG-H components
are properly controlled in
storage.
PER '951485
was initiated by the system engineer
and addressed
deficiencies
in the
HPCI governor controls calibration procedures.
Recommended
corrective action include revision of the procedures.
HPCI has not yet been
through the
SPOC II process
or declared
Resolution of both
PERs wi.ll be tracked
as part of the
HPCI system recovery
processes.
The inspector
concluded that the governor control modifications
have
been
completed
in accordance
with the
DCN packages.
This item is closed
for Unit 3 restart.
The inspectors will continue to monitor HPCI system
testing.
The other
NPP item involved unresolved
Conditions Adverse to Quality Reports
(CAQRs).
In the past,
TVA did not always take timely action to resolve
CAQRs.
The Licensee
has shifted to
a Problem Evaluation Report
(PER)
program for
corrective actions.
The
PER program continues
to be refined
and
has replaced
most of the various deficiency reporting
systems
onsite.
The
PER program is
.inspected
on
a continual
basis
by the resident
inspectors.
While some
weaknesses
have
been
noted in the past,
overall the
PER program
has
been
an
effective corrective action program.
Unresolved
CAQRs (earlier deficiency
reports
were consolidated
into CAQRs) are being tracked in TROI for
resolution.
As stated
on
Page II-58 of the
NPP, prior to restart of Unit 3
any unresolved
CAQRs will be evaluated.
NRC reviews of the license's
tracking
systems
throughout the Unit 3 recovery
have not identified any significant
deficiencies.
5.0
Review of Open
Items
(92700)
(92901)
(92902)
(92903)
(92904)
The 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.
5. 1
(CLOSED)
Instrument Air Supply Problems Affecting Safety-
Related
Equipment (Unit 3).
As presented
in IR 95-38,
most items for this
GL were closed.
The issue
remained
open pending
checks of equipment operability, performance of
functional testing,
and related
system
AOI revision completion.
The inspector
reviewed the remaining
issues
and observed/noted
the following:
.Drywell air quality testing
was performed
on September
15,
1995
and'esting
results,
received
October
5,
1995,
were satisfactory.
System
AOIs were revised
and noted
as complete
on August 9,
1995.
IQi
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24
System
components
were satisfactorily tested for their failure to an as-
designed
position
on August 29,
1995.
HSIV/ADS accumulator periodic leakage test procedure validation has
been
scheduled
as part of the main steam
system
component testing
package.
Satisfactory
system testing will complete validation. of these
procedures.
Based
on the inspector's
specific review of Unit 3 system operability and
reviews of the AOIs and related
documentation,
GL 88-14 is closed for Unit 3.
5.2
(CLOSfD) THI Action Item II.F.1.2.E
(Formerly II.F. 1.5) - Suppression
Pool/Containment
Water Level Honitor (Unit 3).
IR 95-31 describes
review of many of the elements
of this item.
The issue
remained
open pending
equipment calibration/testing
inspections,
instrumentation
string functional testing,
and following approvals of
associated
level
component testing,
maintenance,
and operating
procedures.
An
inspector
reviewed/observed
closure activities for the remaining issues
and
.noted the following:
Instrument string testing for torus accident level monitoring strings
(PT/PI/XR-64-159A
& 159B)
was performed October
12
& 13,
1995.
Tests
were performed in accordance
with Procedure
3-SI-4.2.F-20(A)
and 20(B),
Suppression
Chamber Water Level - Wide Range.
The inspector
reviewed the
test results
and concluded
they were satisfactory.
System
component operating instructions
were presented
to the licensee's
and approved for use
September
6,
1995.
"A" and "B" train component test procedures
were presented
to TYA's
and approved for use in June,
1995 for the A-train level instrument
and
April, 1995 for the B-train level instrument.
The remaining TI2515/65 items were confirmed to have
been
adequately
addressed
by the licensee.
Based
upon;
1) the
above
items,
2) examination of related
component
procedures,
3) evaluation of modification documents
and 4) review of
operability involving the Unit 3 torus water level monitor,
THI Action Item
II.F.1.2.E, (II.F.1.5), is closed for Unit 3.
Also, during the
above October 12-13,
1995 observations
of the instrumentation
testing,
the inspector walked
down various portions of system piping such
as
test
stand tubing
and instrument
sensing lines.
During the walkdown, the
following was noted:
Tubing/piping was secured
properly
and with allowance for adequate
seismic restraint.
Sensing
portions for system instrumentation
were adequate
and routed
properly for proper detection function.
lpga
25
System modifications were
made in accordance
with design
slope
and
desired piping/tubing run.
Hodification line sl'ope was, for the most part, positive,
and
any
required negative
slope
due to support structure interference
was held
to
a minimum.
During the above
walkdown and during testing for assurance
of meeting the THI
Action Item,
an examination of instrumentation line slope
was performed
by the
inspectors.
The inspectors
noted that in
NRC IR 94-24,
a detailed
examination
of HPCI instrumentation line slope
was previously performed.
The inspectors
reviewed results of a February,
1995,
gA "vertical slice" of reactor
vessel
level
(RVLIS) instrumentation.
PER 950136
was initiated to address
questions
raised during review of this RVLIS line slope
and the inspectors
studied the
completed
PER.
The inspectors
concluded that instrumentation line slope
on
Unit 3 safety
systems
has
been
adequately
addressed
by the licensee.
The
Instrument
Sensing
Line Slope
Program is closed.
5.3
(CLOSED) IFI 84-32-02,
Unit 3 Torus Narrow Range
Level Instrumentation.
As presented
in IR 95-31,
IFI 84-32-02, detailed the "greater than allowed by
Unit 3 Technical Specification" difference in indicated level
between
narrow
range indicators
LI-64-54 and LI-64-66.
Significant review of this
modification had
been
completed;
however, this item remained
open pending
review of instrument testing/calibration
and
upon
a check of component
operability.
Reviews were also required
on performance of functional testing
and completion of changes
to related plant maintenance/testing
and operations
procedures.
Instrument testing for the level monitoring string,
(PT/PI/XR-64-
66)
was performed
on October
13,
1995
and test results,
received
October
14,
were satisfactory.
Based
on these
reviews,
IFI 84-32-02 is closed for Unit 3.
5.4
(CLOSED) Generic Safety
Issue
(GSI)
41
and Hulti-Plant Action (HPA) Item
B058/TAC H51014;
Vol,ume System (Capability Issues).
The inspector
reviewed the August 17,
1993
TVA to
NRC letter,
and verified the
following Unit 3 Scram Discharge
Volume
(SDV) modifications
had
been
completed:
The
SDV has
an independent,
closely-coupled,
scram discharge
instrument
volume (SDIV).
The vent lines are cross-tied
and contain
vacuum
breakers.
System vent/drain lines
have series isolation valves
and
an originally
installed drain piping relief has
been
removed.
The
SDIV has
two main control
room alarms
"volume not drained"
and
"CRD withdrawal inhibit" alarms.
With SDIV accumulations
of
approximately
50 gallons of water,
a scram signal is initiated.
A diverse
mix of float switches
and sealed differential pressure
transmitters/
switches
had
been installed in the original modification;
lpga
26
but the differential pressure
transmitters
were replaced with
transmitters
with heated
reference
RTDs.
As presented
in
a May 11,
1995
TVA to
NRC letter,
the float switches,
while acceptable,
presented
a slow scram input response
(about
20
seconds);
Therefore,
TVA has decided to retain the originally installed
low pressure
switches
due to concerns
regarding
SDV fill-up rates
versus float switch scram signal
response
delays.
As noted in a September,
1993 analysis of BFN's SDVs/SDIVs,
a successful
would be achieved without the scram pilot air header
low pressure
switches,
provided that the
CRD stall flow rate
and the
SDV water level instrument
response
characteristics
remained within acceptable limits.
However,
since
performance of this analysis,
BFN has
noted "higher than expected"
Unit 2
stall flow rates.
BFN also noted that the flow rates
could preclude long-term
conformance of having adequate,
"within acceptable limit", SDV capacity.
Thus,
as stated
in an April 27,
1995
TVA letter to the
NRC, the licensee
determined that their most prudent
course of action would be to maintain the
low pressure
scram function.
In June,
1995,
a design
change
(OCN) was
implemented
on Unit 3 and
OCN completion resulted
in
installation, of qualified /nit 3 scram pilot air header
low pressure
switches.
On June
30,
1995,
TVA submitted
proposed
TS amendment
359, which made
reference
to and
added this scram function.
In March,
1987,
a regional
NRC inspector
reviewed actions
taken
by TVA/BFNP in
response
to Generic Safety Evaluation Report,
System
Safety Evaluation",
IR 87-13.
The inspection
was performed to verify actions
taken to bring all of the
BFN units into compliance with guidelines
establ.ished
by the Generic
SER on
violations or
deviations
were identified.
The inspectors
performed
SDV system
walkdowns
and reviewed applicable Unit 3
documentation
including; TI 2515/90,
"Inspection of Licensee
Implementation of
MPA-58,
SDV Capability",
a TVA to
NRC letter,
dated April 27,
1995,
and
IR
87-13.
The following observations
were made:
The Unit 3
are sized in accordance
with
GE OER-54.
The
are hydraulically coupled to the
SDV instrument
volumes in such
a way which permits
oper ability of the instruments prior to
a loss of
system function.
Unit 3
SDV level instrumentation
is provided which allows for an
automatic scram, while sufficient volume exists in the
SDV.
Instrumentation
taps
are provided
on the vertical instrument
volume
and
not on connected
piping.
Scram instrumentation
is currently capable of detecting water
accumulation
in the instrument
volumes.
This instrumentation
provides
both diversity and redundancy.
IQi
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27
Unit 3
SDV vent
and drain functions appear
not to be adversely affected
by other system interfaces
and the
SDV vent
and drain valves
are
designed
to close
upon loss of air/power.
Unit 3
SDV instruments
are provided which aid the operator prior to any
scram initiation.
They provide detection of water accumulation within
the instrumentation
volumes.
A single active failure will not defeat the isolation of the Unit 3
vent
and drain valves.
As with the currently operating Unit 2
SDV system,
Unit 3 quarterly testing
will be performed to ensure that:
Vent and drain valves are periodically tested
and that valve closure
times are less
than
30 seconds.
" In-place" level detection
instrumention is periodically tested.
Overall
SDV system operability is periodically tested
and at least
once
during each operating cycle of Unit 3.
This quarterly test,
using Unit 3 SI, 3-SI-4.3.F. l.b,
"SDV Valve Operability
SI", for guidance is performed
by simulating
a scram signal to the
SDV drain
and vent air pilot valves
3-FSV-85-37A and
37B using test switches
located
on
the Unit 3 Auxiliary Instrument
Room Panels 9-15
and
17.
A chart recorder is
connected
to each drain
and vent valve "closed" indicating switch to allow
testing of all valves simultaneously to ensure
they close in the specified
time limit of less
than or equal
to 30 seconds.
Provisions
have
been
made for
testing using
a stop watch in lieu of a chart recorder,
although
use of the
chart recorder is preferable.
This SI will also
be performed
immediately
following discovery of an inoperable vent/drain valve
and weekly thereafter,
until the valve is declared operable'nit
3 personnel will also perform
monthly
SDV vent/drain valve position verifications using Unit 3 Surveillance
Instruction (SI), 3-SI-4.3.F. I.a,
On September
29,
1995,
TVA instrument maintenance
personnel
experienced
problems with testing/calibration of the Unit 3 SDV/SDIV instruments.
It was
determined that
a "hydrolasing"
and flush of the system
was desirable
and
on
October 4,
1995,
per
a cleaning of the system
was performed.
Flush sludge deposits
from the both the
and
SDIVs were of a "charcoal"
color and consistency
which was of the
same
sludge color and consistency
as
that observed
from a flush of the Unit 3
HCUs performed earlier in the year.
After a thorough flush of the system
and after observance
of clear flushing
water,
on October
7,
1995,
system piping end covers
were reinstalled.
One of
the inspectors
observed
torquing of some of the end covers.
gC personnel
were
present
and knowledgeable
regarding
the torque requirements.
On October 7,
the system instrumention
was reinstalled
and calibration of the instruments
was subsequently
completed.
Based
on these
reviews,
both
41
and
HPA B-58, is closed for Unit 3.
lgi
ig>
Igl
28
5.5
(CLOSED) TI'515/121
(GL 89-16), Verification of Mark I Hardened
Vent
Modifications - Unit 3
As presented
in IR 95-38, significant review of this TI has
been
performed.
The item remained
open pending review of system testing/verification of an
associated
EOI. Inspectors
reviewed remaining issue closure activities
and
observed
the following:
System functional testing
was performed
on September
17,
1995.
Testing
indicated that the current Unit 3 vent path will perform its function.
The associated
system
EOI, 3-EOI Appendix 13,
"Emergency Venting Primary
Containment,
was approved for use
on October
13,
1995.
During
a walkdown.,
an
NRC inspector
noted that
an associated
Unit 3
system valve pit, located outside the reactor building,
was not fully
secured
by bolting as directed
by system drawing/design.
Accompanying
licensee
personnel
stated that this valve pit would
be. adequately
secured
and sealed prior to Unit 3 operation.
This was confirmed
by the
inspector
on October
11,
1995.
Based
upon the
above
and
an inspector's
specific review of the Unit 3 hardened
vent system operability, the associated
EOI,
and other related
TI/GL
documentation,
(GL 89-16) is closed for Unit 3.
5.6
(CLOSED) (Unit 3)
LER 50-259,
260, 296/91-15,
Low Suction Pressure.
The licensee's
actions to address
this issue
had
been
inspected
as described
in IR 95-10.
The item remained
open pending observation
of testing.
On
October
13, the Unit 3 HPCI system
was operated
(on auxiliary steam)
in
accordance
with 3-TI-343,
HPCI Injection Line Flush
and 3-0I-73,
HPCI System.
The testing is further described
in paragraph
4.8.2 of this report.
No
problems
were noted involving .the suction low pressure circuitry.
The
inspector verified that the low suction pressure
switch had
been calibrated
and tested
(procedure
LCI-3-P-73-029).
The setpoint listed
in. the
CR
response
procedure
matched
the setpoint listed in the calibration
procedures.
Based
on this review and the observed
HPCI operation,
this item
is closed.
5.7
(Closed)
TMI Action Item II.K.3.28, gualification of ADS Accumulators.
This action item involved two concerns
related to the qualification of the
The
ADS system for Unit 3 consists of six pneumatically
operated
SRVs each with an accumulator
and check valve.
The accumulators
have
an approximate
volume of one gallon
and are normally supplied
by the drywell
control air system.
The first concern dealt with the short-term (six hours)
operability of the accumulators
and their capability to cycle the valves
open
five times at design pressure.
The
NRC staff determined that the Browns Ferry
met this criteria
as described
in
a
NRR Safety Evaluation
dated July 24,
1985.
'
i,
i/i
~k
29
The second portion of this action item dealt with the long-term (100 days)
functionality of the
To meet this criteria, the licensee
implemented
a design
change
which utilizes the
CAD system
as the backup supply
for air to the drywell control air system which in turn pressurizes
the
accumu'lators.
Additionally, the drywell control air system
was separated
into two trains within the drywell.
The inspector
reviewed portions of the
design
change
(W17937),
reviewed the applicable drawings,
and walked down
portions of these modifications to ensure
these criteria were met.
Plant
procedures
3-AOI-32A-1 (the abnormal
operations
procedure for loss of drywell
control air)
and 3-0I-84 (Containment Atmospheric Dilution system operating
procedure)
were also reviewed to ensure
appropriate
and technically sound
operating instructions
were in place to allow for connecting
the
CAD system to
the drywell control air system.
During the procedure
review,
a number of
labeling deficiencies
were noted
by the inspector.
Plant operations
personnel
indicated that these
matters
would be corrected.
Lastly,
a number of the post
modification tests for this design
change
were reviewed.
The
PMTs reviewed
were
as follows;
(1) 3-SI-4.7.G. l.a-l, Containment
Atmospheric Dilution
System Valve Operability and
(2) 3-SI-4.7.A.2.g-3/84a,
84b,
and 84d,
Primary
Containment
Local
Leak Rate Test
Containment Atmospheric Dilution-
X-25 and X-205.
Based
on this review of the licensee's
actions,
this item is closed.
5.8
(Closed)
THI II.K.3.13.B, Separation
of High Pressure
Coolant Injection
and Reactor
Core Isolation Cooling System Initiation LevelsAnalysis
and Implementation
This action item involves two separate
issues.
The first portion of this item
dealt with the separation
of HPCI
and
RCIC system reactor water level
initiation setpoints.
In relation to this matter,
the licensee
endorsed
the
BWR Owners
Group evaluation
(performed
by General
Electric) which stated that
the separation
of HPCI
and
RCIC initiation levels would be of negligible
safety benefit.
The staff endorsed this position in
a Safety Evaluation dated
March 16,
1983.
The second portion of this item deals with the restart of RCIC on
a low
reactor level condition following an automatic shut-off on high water level.
In order for the
RCIC system to be able to automatically restart
in the
above
described
manner,
a modification to the
RCIC control logic was performed in
accordance
with DCN W17534A.
Nore specifically, this design
change
was
implemented
by altering the valve which closes
on
a high level condition.
Prior to the modification, the turbine trip valve (3-FCV-71-9) would close
on
a high water level.
Following the modification, the steam supply valve (3-
FCV-71-8) will receive the close signal
on
a high level condition.
Other
trip signals will continue to close the turbine trip valve
and require
manual
action to reset
the system for injection.
The inspector
reviewed portions of
the design
change to confirm these
changes
were covered.
In addition,
the inspector
reviewed 3-0I-71, the Unit 3
RCIC System Operating
Procedure,
to ensure this change
in operating
methodology
was recognized.
The
plant licensed
operator training manual for the
RCIC system,
OPL171.040,
was
also reviewed
by the inspector to ensure this restart feature of the system
was acknowledged.
Finally, the inspector
observed
portions of the
PHT, 3-SI-
0
i/i
i/i
<gl
30
4.2.B-40A,
RCIC System Logic Functional Test, to ensure that the system would
automatically reinitiate
upon receipt of low level signal following a high
level condition.
Based
on this review of the licensee's
actions, this action
item is closed for Unit 3.
5.9
(OPEN) IFI 50-260/95-41-01,
EDG lA Turbocharger
Inspection.
In preparation for the restart of Unit 3, the licensee
contracted for an
independent
Operational
Readiness
Review Team to assess
the readiness
of the
station to begin multi-unit operations.
One of the issues
reviewed
by the
ORRT was the failures of the
1C and
3A
Several
NRC
inspections
have
been
conducted
on the failures.
While performing this
review, the
ORRT noted that
a vendor "modernization
recommendation"
for a pre-
lubricating system
had not been installed
on the Browns Ferry
EDGs.
In
addition, of the approximately
84
EMD EDGs currently being utilized in this
capacity at nuclear
power plants in the United States,
only the Browns Ferry
and
one other licensee's
EHD EDGs have not had this modification installed.
The
ORRT concluded that the licensee's
documentation
of the issue did not
adequately
address
these specific questions
adequately.
The resident
inspectors,
when informed of the ORRT's concerns,
concluded that additional
NRC review of the issue
was warranted.
On October
11,
1995,
a teleconference
was conducted
between
the licensee
and
the
NRC (Region II, NRR,
and the Resident
Inspector Office) to discuss
the
status of the licensee's
corrective actions related to the
1C and
3A
turbocharger failures.
During the teleconference,
the licensee
explained that
they
had determined that the pre-lube modification was not required to be
implemented
due to the methodology in which the engines
are operated.
Hore
specifically, this change is only of benefit to an engine which is fast
started
during
a period from 15 minutes to
3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> from which it was last
operated.
Because
the licensee
procedurally prohibits operation of the
in this manner,
the vendor concurred with the licensee's
decision not to
implement the modification.
Additional actions
being taken
by the licensee
are
as follows;
1) The
licensee
has
purchased
two sets of new turbocharger
gears
which will be
metallurgically examined for manufacturing defects.
2) Recently,
the licensee
discovered
two planetary
gears
from the
3A turbocharger
which failed on August
24,
1992.
These
gears will be sent to TVA central
laboratory for analysis.
3) In June,
1996,
the licensee will remove the
1A turbocharger for destructive
examination.
This effort will be accelerated if the testing of the
above
mentioned
gears
demonstrates
a manufacturing
problem.
The inspectors will
continue to monitor the licensee's
corrective actions related the past
turbocharger failures.
Based
on this review, this item will remain
open
pending final resolution of this matter.
5. 10
(OPEN)
VIO 260,296/95-31-01,
Core Spray Testable
Check Valve Testing
not in Accordance with Requirements.
guestioning
by
a
NRC inspector during observation of testing led to the
'dentification
that the
CS testable
were not being tested
in
accordance
with the approved
IST program requirements.
The disk was not being
~
~
ii
<5>
Igi
31
cycled fully open
and the procedure for setting the disk position indication
lights was not sufficiently detailed.
Additional review of this issue is
documented
in IR 95-43.
On August 30,
1995,
one of the inspectors
observed
cycling of 3-FCV-075-0054 (with the air actuator)
with the top cover removed.
Maintenance
personnel
set the disk position switches
using
a revised
procedure.
The inspector
concluded that the disk position indication lights
were set to more accurately reflect disk position.
The inspector
observed
that the disk initially slammed fully open
when the actuator
overcame
the
small force present
when the disk was fully shut.
The disk could be easily
opened
from the actuator
end of travel position to fully open.
The inspector
noted that the
AUO involved deliberately verified (by,reading
the valve label)
that
he was operating
the correct
component
before opening the valve.
Subsequent
to these activities, the valve failed local leakrate testing
and
additional
work was performed
on the valve.
After this work was completed,
the valve was stroked fully open using
a torque wrench.
The inspector
reviewed the data for the manual
stroking of both Unit 3
CS testable
check
valves.
WOs 95-12395-0
and
12445-0 indicated that the
maximum torque required
to fully open the disk was
30 ft-lbs.
This value is significantly less
than
the pressure
that would be applied if CS .flow was initiated.
The inspector
concluded that the Unit 3 valves
had
been satisfactorily stroked
open.
This
item is considered
addressed
for the Unit 3 restart.
On September
15,
1995
the licensee
submitted relief request
PV-37 which addressed
alternate
testing
of the
The violation remains
open
pending
NRC review of the
licensee's
submittal
and stroking of the Unit 2 valves.
5. 11
(CLOSED)
LER 259,
260,
296/94-02,
Raychem Tubing for
EQ Applications
On October 31,
1994, during installation of Raychem heat shrink tubing, the
licensee
discovered that WCSF-070-N shrink tubing from lot no.
15057 would not
'hrink down enough to form a proper seal for LOCA harsh
environment
applications.
The licensee
placed the inventory of WCSF-070-N tubing from lot
no.
15057
on
QA hold on October 31,
1994.
The allowable range for
applications for WCSF-070-N was 0.07 to 0. 14 inches diameter
.
The material
was procurred
on
TVA procurement
document
21042-E19060Q
item
6 and
was stocked
as
TVA item BGN673K.
On November
1,
1994,
TVA sent
samples of WCSF-070-N tubing from lot no.
15057
to Raychem for evaluation.
The
Raychem written response
indicated that this
material. did have
a reduced
shrinkage
and could only be used for LOCA harsh
environment application for a range of .081 to
. 14 inches diameter.
Material
which had
been
issued to the field and
had not been
used
was returned to the
warehouse
and placed
on
QA hold,
TVA could not determine
a definitive root
cause
but suspected
manufacturing
process
problems
because
no other tubing
from different lots had exhibited this problem.
TVA determined that
no tubing of this lot no.
was
used in 10 CFR 50.49
applications
on Unit 2.
All WCSF-070-N tubing from lot no.
15057
was returned
to Raychem.
The licensee's
review indicated that only 4 cases
were identified
where
WCSF-070-N tubing from lot no.
15057
was
used
on Unit 3.
The
applications
were
uses
as
shims where the tubing is shrunk
on
a cable
and
another
piece of shrink tubing is installed over the joint.
The four
I
.0"
if'/i
ill
32
applications
were identified to fall within the reduced
range of .081 to
. 14
inches for which Raychem stated that lot no.
15057 would remain acceptable.
The inspectors
reviewed the correspondence
from Raychem
and confirmed that the
vendor indicated that the lot was acceptable if used within the range of .081
to
. 14 inches diameter.
The field verification data
sheets
for Unit 2 in
Eg
Binder BFN-O-E(-SPLC-OOI, Revision
15,, were reviewed
and the inspectors
confirmed that
no WCSF-070-N tubing from lot no.
15057
was installed in
Eg
applications
on Unit 2.
The Unit 3 field verification data sheets
had not yet
been
incorporated
into this binder.
This issue
was discussed
with TVA
materials
personnel
and the inspectors
determined that the materials
records
indicated that
650 pieces of WCSF-070-N of lot no.
15057
was received with
approximately
150 pieces
being issued to the plant.
The remainder of the
inventory was returned to Raychem.
The inspectors
examined
the warehouse
gA hold area,
main warehouse,
and the
auxiliary in plant warehouse
and
no inventory of WCSF-070-N of lot no.
15057
was found.
Several
installed .splices
were examined
in Unit 3 electrical
penetration junction boxes for penetrations
BA,
EC,
ED,
and in junction boxes
JB0107A and JB0107F
and
no splices utilizing WCSF-070-N of lot no.
15057 were
identified.
The inspectors
determined that the licensee's
corrective actions for LER 94-02
were adequate,
the item is closed.
5. 12
(CLOSED) IFI 50-296/95-37-01,
Verification of Emergency Lighting Levels
During
a
NRC inspection
(IR 50-296/95-37)
conducted
on July 17-21,
1995,
the
inspectors
observed
the location of the battery pack emergency lighting units
in the control
room and the operator
access
pathway to the backup
shutdown
panel
room.
The inspectors
also conducted
a "lights out
" test in the backup
shutdown
panel
room (electrical
board
room 3A) and the adjacent
480
V switch
gear
room.
This IFI was opened to track questions
raised
regarding
the location of other
emergency lighting fixtures needed for additional
manual
operations of safe
shutdown
systems
and access
and egress
routes to those plant locations
identified in the drafted post-fire Safe
Shutdown Instructions
(SSIs).
During this inspection
the inspector selected
a sample of Unit 3 rooms
and
plant pathways identified in the draft of 2/3-SSI-16,
Attachments
5 and 6, to
evaluate
the lighting installation
and arrangement
of the emergency lighting
system.
The inspector walked down the emergency lighting for operator
manual
actions
taken at the
480V
RMOV Boards,
250V
RMOV Boards,
and
4KV Shutdown
Boards.
During the walk down, the inspector verified by observation that the
arrangement
of the emergency lighting units were adequate
for operator
access
path illumination and board/panel
nameplate
illumination.
The inspector also reviewed the results of Post Modification Test
PMT-150,
Testing of Emergency Lighting System.
The
PMT inspection
was performed
on
August 28,
1995, to verify the functional status of Appendix
R lighting units
installed in the Unit 3 Reactor Building under
DCN W18755A to support Appendix
R safe
shutdown operator
manual
actions.
The test consisted of interruption
4.'Qi
i/i
33
of normal lighting, verifying and documenting illumination levels,
conducting
battery discharge tests,
and validation of the aiming of emergency lighting
heads.
Only'ne significant test deficiency was identified for a burned out
lamp on light number
143.
Work request
WR C307064
was
implemented to replace
the lamp and
was closed
on August 25,
1995.
Retest of the lighting unit was
performed with acceptable
results.
The inspector walked down
12 lighting
units listed in PHT.-150
and identified no discrepancies.
Based
on the location
and number of lighting units observed,
the inspector
concluded that the lighting arrangement
and levels in support of Unit 3 SSI-16
operator
manual
actions
were according to Appendix
R requirements.
Based
on
this observation
and the "lights out" performance test discussed
in IR 95-37,
Inspector
Follow-up Item 50-296/95-37-01
i's closed.
6.0
Exit Interview (30703)
'he
inspection
scope
and findings were
summarized
on October
18,
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
Descri tion and Reference
Closed
Instrument Air Supply Problems
Affecting Safety-Related
Equipment-
Unit 3 (paragraph
5. 1)
THI II.F.1.2.E
IFI 84-32-02
GS I 41/HPA B058
(GL 89-16)
LER'0-259,260,296/91-15
Closed
Closed
Closed
Closed
Closed
Suppression
Pool/Containment
Water
Level Monitor Unit 3 (paragraph
5.2)
Torus Narrow Range .Level
Instrumentation -Unit 3 (paragraph
5.3)
Volume - Unit 3
(paragraph
5.4)
Verification of Mark I Hardened
Vent
Modifications
Unit 3 (paragraph
5.5)
Low Suction Pressure - Unit 3
(Paragraph
5.6)
THI Action Item II.K.3. 28
.
Closed
gualification of ADS Accumulators .-
Unit 3 (paragraph
5.7)
~ ~
i
~gl
Igl
TMI II.K.3.13.B
LER 50-259,260,296/94-02
Closed
Closed
Separation
of High Pressure
Coolant
Injection and Reactor
Core Isolation
Cooling System Initiation Levels
Analysis
and Implementation
Unit 3
(paragraph
5.8)
Raychem Tubing for
EQ Applications,
(Paragraph
5. 11)
IFI 50-296/95-37-01
IFI 50-260/95-56-02
IFI 50-260/95-41-01
VIO 260,296/95-31-01
VIO 50-296/95-56-01
Closed
Open
Open
Open
Open
Verification of Emergency Lighting
Levels (paragraph
5. 12)
Use of Nickel-Based
Thread
Lubricants
on Gaskets
in TVA Class
"B" Fluid Systems
(paragraph
3.2)
1A Turbocharger
Inspection,
(paragraph
5.9)
Core Spray Testable
Testing not in Accordance with
Requirements,
(paragraph
5. 10)
Failure to Follow Alarm Response
Procedures
Results .in Loss of 480V
Bus (paragraph
2.3)
7,0
and Initialisms
AOI
ASOS
CAQR
CATD
CCD
CFR
CR
DCN
Automatic Depressurization
System
Abnormal Operating Instruction
American Society of Mechanical
Engineers
Assistant Shift Operations
Supervisor
Auxiliary Unit Operators
Browns Ferry Nuclear Plant
Boiling Water Reactor
Containment
Atmosphere Dilution
Condition Adverse to Quality Report
Corrective Action Tracking Document
Configuration Control Drawing
Code of Federal
Regulations
Control
Room
Control
Rod Drive
Drawing Change Authorization
Design
Change Notice
Demonstration
Power Reactor
Emergency
Diesel
Generator
Emergency
Equipment Cooling Water
Electromotive Division
Emergency Operating Instructions
~ ~
A
~ .
4i
ig>
i/i
35
EQDP
FHE
GDC
GL
IFI
IR
kv
LER
NPA
NCO
NR
NRC
ORRT
PER
PHT
RMOV
SPAE
TDCN
TI
THI
TOE
TROI
Environmental Qualification
Environmental Qualification Documentation
Packages
Engineered
Safety Feature
General
Design Criteria
P
Generic Letter
Generic Safety
Issue
,Hydraulic Control Unit
High Pressure
Coolant Injection
Inspector
Follow-up Item
Inspection
Report
Inservice testing
Kilovolts
Licensee
Event Report
Loss of Coolant Accident
Motor Operated
Valve
Multi-Plant Action Item
Hain, Steam Isolation Valve
Nuclear Commitment
Open
Item
Nuclear Performance
Plan
Narrow Range
Nuclear Reactor Regulation
Nuclear Regulatory
Commission
Operating Instruction
Operational
Readiness
Review Team
Problem Evaluation Report
Post Haintenance/Hodification
Test
Plant -Operations
Review Committee
Quality Assurance
Quality Control
Reactor, Core Isolation Cooling
Residual
Heat
Removal
Residual
Heat
Removal
Service
Water System
Reactor Hotor Operated
Valve
Reactor Protectionn
System
Reactor
Water Cleanup
Scram Discharge
Instrument
Volume
Scram Discharge
Volume
Safety Evaluation Report
Surveillance Instruction
Service
Information Letter
System Plant Acceptance
Evaluation
System Preoperational
Checklist
Senior Reactor Operator
Safe
Shutdown Instructions
Site Standard
Practices
Test Design
Change Notice
Temporary Instruction
Three Mile Island
Technical Operability Evaluation
Tracking
and Reporting of Open
Items
~ ~
I
i/i
<gt
TS
WP
Technical Specifications
Technical
Support Center
Valley Authority
Unresolved Safety
Issue
Violation
Work Order
Work Plan
Work Request
gpss