ML18036A858
| ML18036A858 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 09/02/1992 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036A853 | List: |
| References | |
| 50-259-92-29, 50-260-92-29, 50-296-92-29, NUDOCS 9209220150 | |
| Download: ML18036A858 (26) | |
See also: IR 05000259/1992029
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
Report Nos.:
50-259/92-29,
.50-260/92-29,
and 50-296/92-29
'Licensee:
Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga,
TN
37402-2801
Docket Nos.:
50-259,
50-260,
and 50-296
License Nos.:
and
Facility Name:
Browns Ferry Units 1, 2,
and
3
Inspection at Browns Ferry Site near
Decatur,
Inspector:
Inspection
Conducte
- July
8
August, 14,
1992
~
~
a
on,
en>or
ss
ent
nspector
Date
cygne
Accompanied
by:
E. Christnot,
Resident
Inspector
W. Bearden,
Resident
Inspector
J.
Munday,
Resident
Inspector
Approved by:
Pa
.
e
g,
C se
R actor ProJects,
Section
4A
Division of Reactor Projects
Date
S gne
SUMMARY
Scope:
This routine resident
inspection
included surveillance
observation,
maintenance
observation,
operational
safety verification, verification of
plant records,
secondary
drawing status,
Unit 3 restart activities,
and organization structure.
One hour of backshift coverage
was routinely worked during the work week.
Deep backshift inspections
were conducted
on July 25, August 2,
and August 9,
1992.
J
9209220150
920911
ADOCK 05000259
6
A public meeting
was held onsite
on July 27,
1992 for discussion of the
Systematic
Assessment
of Licensee
Performance
report.
The details
are in
inspection report 92-18.
Results:
Unit 2 operated
at power during this period,
paragraph
four.
occurred
on July 28,
1992,
ending
89 days of continuous operation,
paragraph
four.
After a thorough review oF the tri'p, the unit was restarted
and
had
been
on line for 15 days at the end of the period.
Unit 3 recovery activities completed replacing the recirculation
system piping
and portions of the reactor water cleanup
system,
paragraph.
seven.
Other
.intergranular
stress
corrosion cracking mitigation techniques
are mechanical
stress
improvement
programs
and weld overlays.
These activities are in
progress
or being planned.
The site engineering
organization
has transitioned
to
a single organization with a Unit 3 component.
This has
increased
the
ownership of contractor design activities.
However, significant problems
were
encountered
with the drywell chiller installation
by construction contractor
personnel.
Approximately 100 field design
change
notices
were necessary
for
two design
change
notices.
One violation was identified for failure to sign onto
a hold order prior to
commencing work, paragraph
seven.
A modifications contractor
supervisor
failed to follow plant procedures.
Although, this was identified by the
licensee,
the violation is
a repeat of a previous
NCV 259,
260,
296/92-17-01.
One apparent violation was identified concerning
operator
rounds,
paragraph
five.
The licensee
conducted
an audit
and two personnel
received disciplinary
action,
The review of the licensee's
audit
and inspection
by the inspector
completed
temporary instruction TI 2515/115.
REPORT DETAILS
Persons
'Contacted
Licensee. Employees:
- 0. Zeringue,
Vice President,
Browns Ferry Operations
- H. McCluskey, Vice President,
Browns Ferry Restart
- J. Scalice,
Plant Manager
- J. Rupert,
Engineering
and Modifications Manager
- J. Swindell, Restart
Manager
- M. Herrell, Operations
Manager
J.
Maddox, Project, Engineer
- H. Bajestani,
Technical
Support Manager
R. Jones,
Operations
Superintendent
A. Sorrell, Special
Programs
Manager
- C. Crane,
Maintenance
Hanager
G. Turner, Site guality Assurance
Manager
- R. Baron, Site Licensing Manager
P. Salas,
Compliance Supervisor
- J. Corey, Site Radiological Control
Manager
A. Brittain, Site Security Manager
Other licensee
employees
or contractors
contacted
included licensed
reactor operators,
auxiliary operators,
craftsmen,
technicians,
.and
public safety officers;
and quality assurance,
design,
and engineering
personnel.
NRC Personnel:
P. Kellogg, Section Chief
- C. Patterson,
Senior Resident
Inspector
- E. Christnot,
Resident
Inspector
W. Bearden,
Resident
Inspector
J.
Hunday,
Resident
Inspector
- Attended exit interview
and initialisms used throughout this report are listed in the
last paragraph.
Surveillance Observation
(61726)
The inspectors
observed
and/or reviewed the performance of required SIs.
The inspections
included reviews o'f the SIs for technical
adequacy
and
conformance to TS, verification of test
instrument calibration,
observa-
t'
of the conduct of testing
confirmation of proper removal
from
ions
o
service
and return to service of systems,
and reviews of test data.
The
inspectors
also verified that
LCOs were met, testing
was accomplished
by
qualified personnel,
and the SIs were completed within the required
frequency.
The following SI was reviewed during this reporting period:
SI-4,9.A.1.A (C24), Diesel Generator 'C'4 Hour Run
On August 4,
1992, during completion of SI-4.9.A. I.A (C24), Diesel
Generator 'C'4 Hour Run, the
DG tripped spuriously
on reverse
power
as
the
DG was being unloaded.
The licensee
is conducting
an II of this
event.
The initial assessment
determined that
a "holding coil" in the
reverse
power relay was still in place causing the relay to remain
energized
as the
DG was unloaded.
The coil is used in high vibration
areas
to keep the reverse
power relay in place.
The holding coil was
found adjusted
out of service
on the other
seven
DGs.
The coil was
adjusted to be out of service
on the 'C'G.
The reverse
power relay is
located
in an electrical
cabinet
mounted
on
a separate
concrete
pad than
the
DG in the
DG room.
Vibration has not been
a problem in this
electrical cabinet.
The 'C'G was returned to service
on August 5,
1992.
The inspector will review the completed II which will include
extensive
review of this problem by the licensee.
No violations or deviations
were identified in the Surveillance
Observa-
tion area.
Maintenance
Observation
(62703)
Plant maintenance
activities were observed
and/or reviewed for selected
safety-related
systems
and components
to ascertain
that they were
conducted
in accordance
with requirements.
The following items were
considered
during these
reviews:
LCOs maintained,
use of approved
procedures,
functional testing and/or calibrations
were performed prior
to returning components
or systems
to service,
gC records
maintained,
activities accomplished
by qualified personnel,
use of properly
certified parts
and materials,
proper
use of clearance
procedures,
and
implementation of radiological control.s
as required.
Work documentation
(WR and
WO) were reviewed to determine
the status of
outstanding
jobs
and to assure
that priority was assigned
to safety-
related
equipment
maintenance
which might affect plant safety.
The
inspectors
observed
the following maintenance
activities during this
reporting period:
Unit 3EB Diesel
Generator
Outage
~ The
NRC inspector followed licensee activities associated
with the
scheduled
outage
on 3EB Emergency
DG.
The
DG was
removed
from
service to perform several
planned
work activities.
which checked
the tightness of bolted connec-
tions.
This check is required six months following perfor-
mance of a six year
outage
on any diesel
generator.
e
which replaced
the 38-2 Diesel
Fuel Transfer
pump due to high vibration.
WO 92-531,18,,which
performed
EPI-3-082-0GZ002,
Diesel
Generator
3B Redundant Start Test.
b.
The inspector
reviewed the hold order in effect on the
DG,
3-92-272,
and verified it to be adequate
for the intended
maintenance.
The inspector
observed
portions of work in progress
and the associated
work packages.
The work packages
were clear
and provided adequate
detail to support the work activity.
The
inspector verified the torque wrench being used,
I.D. number
544355,
was within it's requi) ed calibration date
and acceptable
for the intended work.
Following completion of the maintenance
the
DG was satisfactorily tested
and returned to
operable'outine
Preventative
Haintenance
An inspector
observed
work associated
with the following work
orders:
c ~
which performed the required weekly inspection
of the
3B Control
Bay Chiller.
which performed
EPI-O-OOO-HCCOOl,
Haintenance
and Inspection of 480
VAC and
250
VDC Hotor Control Centers.
Work was performed
on breakers for Drywell Equipment Drain
Pump
2B, Drywell Floor Drain
Pump
2B, Reactor
Building Equipment Drain
Pump
2B,
and Reactor Building,
Floor Drain Sump
Pump
2B.
The inspector
reviewed the work instructions
and determined that
the instructions
were of sufficient detail
and provided
adequate
guidance to support the intended
work activities.
Unit 2 Pre-outage
Hodifications
1.)
Hodification of Hiscellaneous
Steel
During
a routine tour of the reactor building on August 3,
1992,
the inspector
observed that
some concrete
blocks
had
been
removed
above the double doors to the reactor building
equipment
access
area.
The doors
were marked
as
an
Eg door
and pressure
boundary door.
The door was not to be left
opened without
SOS permission.
The inspector
questioned
the
SOS why the concrete
blocks were
removed
since this had
the
same effect
as leaving the doors
open.
It was determined that the concrete
blocks were
removed to
reinforce
some structural steel.
This work was
accomplished
under
DCN W17292-A.
An interim program for
seismic qualification of miscellaneous
steel
supports
was
approved for Unit 2 restart.
This work was being performed
as part of the long-term qualification.
The inspector
reviewed
WP-2211-92 which contained
a review by the
SOS.
In
this area near the reactor building elevator
and stairwell
there
are doors leading from Unit 2, from Unit I, and the
equipment
access
area to the area.
One of the doors
must
remain closed.
The inspector
concluded that adequate
controls
and review of this work activity had
been
maintained.
2.)
Scaffolding Problems
On July 31,
1992,
the inspector identified
a scaffold
incorrectly erected
in Unit 2 HPCI room.
The licensee
corrected
the scaffolding problem
and initiated II-B-92-053
to address
scaffolding problems.
The licensee
inspected all scaffo'1ding in the field and
20
scaffolds
were removed.
A comprehensive
procedure
revision
was conducted
as part of the II.
The inspector will
continue to follow these
problems with review of the II 'and
closure of IFI 260/92-21-02,
Adequacy of Scaffolding Review.
No violations or deviations
were identified in the Maintenance
Observa-
tion area.
Operational
Safety Verification (71707)
The
NRC inspectors
followed the overall plant status
and
any significant
safety matte
s related to plant operations.
Daily discussions
were held
with plant management
and various
members of the plant operating staff.
The inspectors
made routine visits to the control rooms.
Inspection
observations
included instrument readings,
setpoints
and recordings,
status of operating
systems,
status
and alignments of emergency
standby
systems,
verification of onsite
and offsite power supplies,
emergency
power sources
available for automatic operation,
the purpose of tempo-
rary tags
on equipment controls
and switches,
alarm status,
adherence
to procedures,
adherence
to,LCOs, nuclear instruments
opera-
bility, temporary alterations
in effect, daily journals
and logs,
stack
monitor recorder traces,
and control
room manning.
This inspection
activity also included
numerous
informal discussions
with operators
and
supervisors.
General
plant tours were conducted.
Portions of the turbine buildings,
each reactor building,
and general
plant areas
were visited.
Observa-
tions 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 selected
plant personnel
in their functional
areas
during
these tours.
Unit Status
Unit 2 tripped
on July 28,
1992,
ending
89 days of continuous
operation.
The cause of the trip is discussed
in this section.
The unit was restarted
and the generator
synchronized
to the grid
on July 30,
1992.
At the end of the report period the unit was
'on-line for
15 days.
On July 28,
1992 Unit 2 experienced
an automatic
main turbine trip
due to an indicated high water level spike
and subsequent
reactor
scram from 100 percent
power.
The spike occurred during
troubleshooting activi,ties associated
with a control relay in the
FWLC system.
Following the scram the plant was stabilized with
EHC controlling reactor pressure
and
a reactor
feed
pump
controlling water level.
Four SRV's with setpoints of 1105 psig
opened,
PCIS groups 2,3,6,
and
8 isolated,
Alternate
Rod Insertion
initiated and the 'reactor recirculation
pumps'ripped
as expected.
Additional plant equipment
responded
as expected
with the
following exceptions:
2.
The TIP probes
which were at the indexers
at the time of the
event,
automatically retracted
to the in-shield position
as
.
designed,-however
the TIP ball valves were found in the
open
position during scram recovery operations.
The local TIP
~ isolation reset
switch located
on the TIP drawer 'was
discovered
stuck depressed
in the reset position.
h
The feeder breaker for 480 volt Reactor Notor Operated
Valve
Board
2C tripped during the event.
This breaker
had
randomly tripped twice in the past
and this trip was
considered
to be
a continuation of the
same
problem.
The
breaker
was subsequently
replaced
as
a precautionary
measure.
3.
The
SRV tailpipe temperature
recorder
was found to have the
chart paper
jammed
and therefore did not record
operation.
An alternate
method
was
used to verify proper
SRV operation.
On July 27, maintenance
was to backfill the "A" channel
reactor
water level reference
leg.
The "A" channel
was indicating 2-3
inches higher than the
"B" channel
level instruments
and it was
determined that its reference
leg was not completely filled.
Prior to commencing
work Op'erations
placed the
FWLC to the
"B"
level signal to avoid any perturbations
during the backfill
process.
When this was performed
flow decreased
resulting in
a reduction of reactor water level.
Increasing
the
demand
in manual
had
no effect and
FWLC was placed
back to the "A"
level signal
and reactor water level
was subsequently
recovered.
Technical
Support reviewed the
FWLC system
response
and schematics
and determined that the only difference
between
the "A" and "8"
level control
mode
was operating relay 6A-K7 by the level control
selector switch.
The licensee
decided to backfill the reference
leg while in the "A" level control
mode.
They then decided to
replace
the suspect
6A-K7 relay.
The relay was
removed
and
indicated level dropped
downscale
as expected
but immediately
upon
installation of the
new relay
a main turbine trip and reactor
scram occurred
as well as
a trip of all three
feedpumps.
It was
later determined that instal'/ation of the
new relay and re-
energization of the instrument loop caused
output
demand to be
.
driven to maximum in an attempt to maintain
a constant
current
output,
and in doing so resulted
in a full scale spike of the
level switches in the circuit.
To verify this the newly installed
6A-K7 relay was
removed
and re-inserted
several
times,
and signal
spiking was observed
each time.
Following the unit trip the licensee
repaired
the stuck TIP
isolation reset
switch and is investigating the procurement
and
installation of a different switch type.
A work order
was
generated
on the
SRV tailpipe temperature
recorder to investigate
and repair
as necessary.
The licensee
performed post-event
troubleshooting
on various feed4ater
control
components
to
positively identify the cause of the initial level perturbation.
The original 6A-K7 relay was tested
in the instrument
shop
and
operated
properly.
The master
FWLC and controller mode select
switch was
bench tested,and
functioned properly.
Following
reinstallation,
a functional test of the
controller was
performed in the various operating
modes with satisfactory
results.
The event could not be recreated.
The inspector
attended
the licensee's
PORC meeting
on July 29,
1992, to review the trip.
Following
a thorough review of the trip
the reactor
was restarted
on July 29,
1992.
Drywell Leak Analysis
During previous periods of plant operation,
unexplained
increases
in drywell unidentified leakage
below the
5 gpm TS limit occurred.
The licensee
developed
a series of procedures
as
a systematic
method to determine
the source
and magnitude of unidentified
leakage
in the drywell when normal
access
is not possible.
The
procedures
developed
are
as follows:
2-TI-275A
2-TI-2758
2-TI-275C
2-TI-275D
2-TI-275 E
Drywell Leak Investigation
Temperature
Drywell Leak Investigation - Radwaste
Drywell Leak Investigation - Primary Containment
Leak Detection
Cam,
2-RN-90-256
Drywell Leak Investigation - Chemistry
Drywell Leak Investigation
Analysis
The inspector
reviewed
each of the procedures
and concluded that
the procedures
provide
an integrated
approach
to determine
the
7
source of unidentified drywell leakage.
The procedures
contain
charts,
graphs,
physical layout sketches,
and useful historical
data from past
leakage
problems.
Each of the procedures
performs
a specific trending
and evaluation for a department
specific area
of expertise.
d.
Drywell Liner Drain
During a plant tour underneath
the torus the inspector
noted that
the drywell liner sand
cushion drain pipe
on sever'al
lines
had
rags or paper in the end of the open pipe.
The inspector also
questioned
how often the lines were checked for any leakage.
The
inspector
reviewed Generic Letter 87-05
and the licensee
response
dated
Hay 29,
I987.
In the response it was stated that the
current preventative
maintenance
and inspection activities
pertaining to this area consists of observation of the appropriate
drains'he
system engineer
provided
a logbook of periodic
wal,kdowns of the. drains.
The only moisture that
had
been
identified was from Unit I drywell.
The licensee
has identified
this as
an item for resolution prior to Unit I restart.
The paper
and tape over the
end of several
drains
was for painting in the
area.
This was
removed'o
violations or deviations
were identified in the Operational
Safety
Verification area.
h
TI 2515/115 Verification of Plant
Records
In response
to recent
NRC concerns
about falsified plant logs,
the li-
censee
conducted
a gA audit to determine if similar problems existed at
BFNP.
The
NRC issued
IN 92-30, Falsification of Plant Records,
to alert
licensees
of this potential
problem.
The licensee's
audit was conducted
during
a six week period from Harch
16 to April 27,
1992.
Sixty-four AUOs and operator
rounds
areas
were
included in the audit.
A comparison of a computer printout of security
key card entries
to operator
round logs
was conducted.
Four thousand
entrances
and exits of plant areas
were reviewed.
Some discrepancies
were identified.
Based
on the discrepancies
the licensee
reviewed re-
cords associated
with an additional six week period from January
I to
Harch
16,
1992.
Again,
some discrepancies
were identified.
The licensee
issued
a
SCAR to document
the findings and corrective
action associated
with the discrepancies
that were identified during the
audit.
Disciplinary action
was taken against
two AUOs due to the
results of the audit.
The inspectors
met with members of licensee
management
to discuss
the specific details
and audit results. 'everal
examples of deviation of TVA policy occurred
by non-licensed
operations
personnel.
The discrepancies
were
a question of whether
an adequate
entry and check of certain vital equipment
areas
had
been
made in
accordance
with established
policy.
Additional corrective actions
are
still pending which are intended to improve licensee
performance
in this
area.
These corrective actions include:
The licensee
is drafting
a new OSIL to require periodic audits
by
Operations
management
in this area.
Training for all non-licensed
personnel
on importance of operator
routines to be conducted
by each
SOS.
The licensee
has plans to implement
a new computerized
system to
take,
record,
and trend information present
on existing operator
routine sheets.
Additionally the inspector
noted that the licensee
has
had in place
an
operator
check program.
This program provides routine
observations/reviews
of performance
by operations
personnel.
This
program was started prior to Unit 2 restart.
One of the attributes
has
been monitoring the quality of routine rounds in the Unit 2 Reactor
Building and Turbine Building.
In addition to the above licensee
reviews,
NRC inspector
made
an
unannounced trip to the plant during the 2300-0700 shift on June
19,
1992, for the purpose of accompanying
the Unit 2 Reactor Building AUO on
the routine rounds.
Prior to starting the operator routine sheet
the
onduty
SOS informed the inspector that approximately
two hours
were
required for the
AUO to complete those routines.
During the period of
observation
the individual displayed excellent
knowledge concerning
the
status of operating
components
and maintenance
activities in the
building.
The
AUO was knowledgeable of existing firewatches
required in
the building and
knew the source of several
minor leaks that were
present.
The individual had
no trouble locating each of the inspection
items within the expected
period.
The operations
routine sheets
are covered in O-GOI-300-1, Operations
Routine Sheets.
TS 6.8. 1. 1 requires that written procedures
shall
be
established,
implemented,
and maintained
covering the applicable
procedures
in Appendix
A of Regulatory
Guide 1.33, Revision
2,
February
1978.
GOIs are procedures
required, in
This finding is being reviewed
as
an apparent violation of 10 CFR 50.9
concerning
completeness
and accuracy of information.
This will be
tracked
as 259,
260, 296/92-29-01,
Apparent Violation of Plant Records.
The inspector's
review in this area fulfills the inspection
requirements
for TI 2515/115
and this TI is closed.
Secondary
Drawing Status
The inspector
reviewed the post Unit 2 recovery work involved with the
updating of secondary
drawings.
Prior to the restart of Unit 2, the-
licensee
updated essential
drawings, referred to as primary/critical
drawings,
needed
to support Unit 2 operations.
Non essential
drawings,
9
referred to as normal
usage
secondary
drawings,
were to be updated prior
to the end of Unit 2 cycle
5 operations.
As of August 8,
1992,
a total of 3714 normal
us'age
secondary
drawings
had been issued,
with 957 still in process.
Of this amount,
131 were
ready,
67 were being researched,.
427 were in drafting,
227 were being
checked,
94 were being reviewed
and
11 were awaiting issue. 'F the
total of 4671 normal
usage
drawings in the. program,
the licensee
expected to have issued
4500 by the end of fiscal year 92.
Unit 3 Restart Activities
(30702)
The inspector
reviewed
and observed
the licensee's
activities involved
with the Unit 3 restart.
This included reviews of procedures,
post-job
activities,
and completed field work; observation of pre-job field work,
in-progress field work,
and
gA/gC activities;
attendance
at restart
craft level, progress
meetings,
restart
program meetings,
and
management
meetings;
and periodic discussions
with both
TVA and contractor person-
nel, skilled craftsmen,
supervisors,
managers
and executives.
a.
IGSCC Nitigation
1.)
Pipe Replacement
The replacement
of recirculation
system piping was completed
as scheduled
on August 1,
1992.
The ring header,
ten
risers,
and safe-ends
were replaced.
The
RWCU piping
replacement
is scheduled
to be completed
on August 31,
1992.
2.)
In other areas
of the recirculation
system
and
one
indication, weld overlays
were determined to be the most
feasible
method of repair.
Eight 28 inch weld overlays will
be applied to the recirculation
system
and
one
26 inch weld
overlay will be applied to the
RHR system.
GE has
been
contracted
to design
and apply the weld overlays.
This work
is tied to re-filling of the vessel
and piping system.
3.)
Nechanical
Stress
Improve'ment
Process
This process
is being used to provide
a means of mitigating
IGSCC by reducing the residual
stresses
of a weld.
The HSIP
is accomplished
by
a slight permanent contraction of the
pipe in the vicinity of the weldment.
This is accomplished
by using hydraulically activated tools.
56 welds in the
recirculation
system,
four in the
CRD system,
six in the
system,
15 in the
CS system,
and five in the
RWCU are being
treated
using HSIP.
This program is scheduled
to be
completed
on September
2,
1992.
10
The inspector
met with applicable licensee
management
and
reviewed the status *of these
programs.
These
programs
are
being conducted
in accordance
with NUREG-0313,
Rev.
2,
Technical
Report
on Haterial Selection
and Processing
Guidelines for BWR Coolant Pressure
Boundary Piping.
The
inspector
reviewed the
NUREG for discussion of the HSIP.
On
page 2.5,
two processes,
IHSI and HSIP,
are considered fully
qualified to provide
IGSCC mitigation from residual
stresses
in welds.
The inspector concluded
the repairs
and
mitigation techniques
are being performed in accordance
with
the technical
recommendations
of the
Pilot/Prototypical
Program
The inspector continued to monitor and review the cooling tower
activities associated
with the pilot/prototypical program.
The
inspector
documented
in report
IR 92-24,
numerous
problems
in this
area.
Oue to the difficulties encountered
in returning the
status
the Unit 3 restart organization
cutback significantly on the resources
dedicated
to the cooling
towers.
The inspector
was informed by Unit 3 management
that the
cooling tower work was to continue
and
a new schedule
was to be
issued.
The activities reviewed
and observed
by the inspector
involved testing of cooling tower components
performed
by test
directors. in order to closeout
DCNs.
Design Activities
The inspector
reviewed the design activities associated
with the
drywell chiller installation.
The work involved numerous
AA FDCNs
generated
during the implementation of DCNs W17695
and
W17913.
The inspector
was informed that
98
FDCNs were initiated by the
constructor for disposition
by design engineering
during the
installation.
The dispositioning of a large
number of FDCNs would
require
a considerable
amount of work by design engineering.
The
inspector
was also informed that the system could
be
preoperationally
tested
before disposition of the
FDCNs
and would
not be turned over to plant operations until th'e significant
FDCNs
were dispositioned.
The inspector considered this
a weakness
in
the team approach, that the Unit 3 project managers
were attempting
to implement.
The inspector
also considered
the inadequate
tracking of the
FDCNs
as
a failure to oversee
and review
contractor activities.
This action
by the constructor
had the
potential of having
a system fully functional, not being able to
operate
due to change
paper closure,
and its final as-built
configuration being undetermined.
The inspector discussed
this
problem with licensee
management.
Construction Activities
2.)
Equipment Clearances
The inspector
reviewed the activities documented
by
IIER-B-92-05, Contractor
Employee Failure to Fully Obtain
a
Clearance
Prior to Performing Work.
The report stated that
this was the third occurrence of contractor personnel
not
receiving
a completed
clearance
issuance prior to performing
work.
The report also stated that
WP 3169-92
was revised to
include re-routing of unscheduled
lighting conduit to
facilitate installation of a horizontal tube member.
On
July 21,
1992,
a clearance
request
was submitted for this
activity.
On July 28,
1992, the contractor supervisor
was
informed that the clearance,
3-92-277,
was in-place.
After
a satisfactory
walkdown of the boundaries,
the supervisor
obtained
a copy of the clearance
sheet
but he failed to have
the clearance
assigned
to him.
The following morning, July
29,
1992,
the job was performed.
SSP 12.3,
Equipment Clearance
Procedure,
required that
clearances
be issued,
using
From SSP-139,
Clearance
Sheet,
and personnel
performing the wor k must receive authorization
from the
SOS,
and insure that the clearance
was assigned
to
the proper person.
In IR 92-17,
the inspector
documented
a
NCV 296/92-17-01,
when
on April 15,
1992,
a contractor
supervisor failed to sign onto
a clearance
for work
performed
on
a Unit 3 drywell blower.
After this event, all
of the contractor supervisors
were interviewed
and trained
in clearance
procedures.
Accordingly, this example
although
identified by the licensee
is
a repeat
and does
not meet the
criteria for a non-cited violation.
This item is identified
as violation VIO 259,
260,
296/92-29-,02,
Failure to Sign Out
a Hold Order Prior to Performing Work.
As
a result of the review of the II the inspector discovered
that
WP 3169-92
was written to install two DCNs,
numbers
W17975A,
Upgrade of the Unit 3
Rad
Con Issue Station,
and
W18019A, Install Tool
Room for Unit 3 Personnel.
The
inspector discussed
this activity of using
one
WP to install
more than
one
DCN with Unit 3 management.
The inspector
was
informed that this was not
a normal practice
and that is
usually requires
approximately six
WPs to install
a
DCN.
Drywell Chiller and Automatic Tap Changer Installation
The inspector
observed
and reviewed the construction
activities associated
with the drywell chiller installation.
The field activities observed
and reviewed involved
WPs
.
0583-92,
3103-92,
3104-92,
and 3155-92 which installed
electrical
equipment,
piping, supports,
and mechanical
equipment.
Additional observations
and reviews were
12
performed which involved
DCNs 17666A,
Stage I:
Change
Capacitor
Bank Control Logic and Setpoints,
Stage
2:
', Install Automatic Load Tap Changer
on
CSS Transformer
A,
and
17667, Install Automatic Load Tap Changer
on
Transformer
B.
Pre-Operational
Testing/Return
to Service Activities
The inspector
reviewed the pre-operational
test for DCN W17695A,
PMT 236, Drywell.Outage Cooling Pre-Operational
Test.
The test
objectives stated:
The objective of this test is to verify the capability of
the drywell outage cooling system to circulate chilled water
through the Unit 3 drywell coolers with the remainder of the
RBCCW system isolated.
and further stated:
This instruction will perform the
PMT for DCN W17695A.
This
DCN provides
supplemental
chilled water cooling for the Unit
3 Drywell via connections
to,the existing
RBCCW system.
The
drywell outage cooling system
-is intended for use only
during outages
to control high drywell ambient temperatures.
The inspector
noted during the initial walkdown of the procedure
steps
5.2.5(a)
and 5.2.5{b) required that starts of chill water
pumps
A and
B respectively
be performed.
The electrical
control
system start logic appeared
to indicate that
when the chill water
pumps were started
the applicable chiller would also start.
Discussions
with the Test Director clarified this item in that
chiller electrical
disconnects
would be used to prevent starting
of the chillers until the factory authorized representative
is
ready to perform the pre-initial startup
checks,
panel
checks,
and
initial startup
and commissioning
on the chillers in accordance
with the manufactor's
installation,
operations
and maintenance
manual.
This was to be documented
on Appendix
L of the
preoperational
test.
Section
5 of the procedure,
Test Instructions,
contained
two
subsections
which gave step
by step instructions to test
the
pump/chillers
A and
B combinations.
The procedure
in section
6
contained clearly stated test
acceptance
criteria.
The procedure
also contained
pump
and chiller performance
sheets,
and valve
checklists for initial fill line-up, pre-test line-up
and post
test line-up.
The inspector
concluded
from this review that the
pre-operational
test procedure for the drywell chiller system
was
written in accordance
with BFN pre-operational
testing
program.
0,
13
Pressure
Locking of Motor Operated
Flexible
Wedge
Gate Valves
The inspector discussed
this issue with the licensee
and the possibility
of valves existing at
BFNP that are subject to hydraulic pressure
locking.
BFNP Engineering
had previously evaluated
pressure
locking/thermal
binding at
BFNP in response
to
and
They identified the
RHR-LPCI and-Core
Spray inboard
and
outboard injection valves
as susceptible
to this phenomenum.
While
pressure
locking has not yet been
observed
at
BFNP, engineering
feels it
prudent to modify the valves to ensure satisfactory operation
in the
future.
The modification will include drilling a hole through the valve
body bridge between
the reactor vessel
side of the valve
and the bonnet
cavity.
This will vent the bonnet to the piping and prevent
pressure
locking the valves.
Furthermore,
hydrostatic testing procedures will be
revised
as applicable to include steps to drain trapped water from the
Additionally, operations
and maintenance will receive training
on pressure
locking and
how to recognize
and recover
from this problem.
The valves
on Unit 2 are scheduled
to be modified during the upcoming
refueling outage.
The Units I and
3 valves will be modified prior to
restart.
9.
Site Organization
(40500)
The inspector
reviewed the organizational
structure of engineering,
modifications,
and contractor interfaces.
Unit 2 engineering
and
modifications is under
a single manager.
This structure
has functioned
as
a cohesive
group with contractors
being
used
as additional
personnel
while TVA retained
ownership
and responsibility for the programs.
In
engineering,
this has
been primarily supplying additional
people.
In
modifications,
a task manager
approach
has
been
used with a
TVA manager
or supervisor
shadowing
a contractor
employee.
Over the past several
weeks
a transition to
a single site engineering
organization
under the project engineer
has occurred.
A Unit 3 restart
project engineer
component
has
been
added to the organization.
This was
done to increase
the
TVA ownership
and responsibility of Unit 3 design
activities rather than relying primarily on contractors.
The inspector
reviewed the preparations
for the Unit 2 Cycle
6 outage
and concluded
that preparations
were proceeding
in time to support the outage.
Most
of the
DCNs were issued
and over half the
WPs written.
Progress
was not
as far along for the activities performed
by Unit 3 to support
the Unit
2 outage.
This was being closely monitored
by TVA management
and with
increased
awareness
and controls executed
under the
new engineering
structure.
However,
one area of concern
was the Unit 3 modification activities.
These
are still primarily contractor controlled functions.
Significant
problems
were encountered
with the cooling tower refurbishment.
Likewise, delays
and numerous
FDCNs were encountered
with the drywell
chiller modi fications.
TVA management
was
aware of these
problems
and
continues
to assess
the organizational
structure.
Some
changes
have
14
occurred including Unit 3 contractor modifications
management
changes,
and shifting of some Unit 2 Cycle
6 outage
work from Unit 3 modification
to Unit 2 modifications.
Exit Interview (30703)
The inspection
scope
and findings were summarized
on August
14,
1991
with those
persons
indicated in paragraph
I above.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection
findings listed below.
The licensee
did not identify as proprietary
any
of the material
provided to or reviewed
by the inspectors
during this
inspection.
Dissenting
comments
were not received
from the li'censee.
Item Number
Oescri tion and Reference
259,
260,
296/92-29-01
259,
260,
296/92-29-02
Apparent
VIO, Apparent Violation of Plant
Records,
paragraph
fi've.
P
VIO,,Failure to Sign Out
a Hold Orders
Prior to. Performing Work, paragraph
seven.
Licensee
management
was informed that
one TI was closed.
BFNP
CFR
DCN
FDCN
GL
GOI
GPH
IFI
II
IN
IR
LCO
HSIP
NRC
and Initialisms
Advanced Authorized
Auxiliary Unit Operator
Browns Ferry Nuclear Plant
Code of Federal
Regulations
Control
Rod Drive
Design
Change Notice
Diesel
Generator
Electric Hydraulic Control
Environmental Qualification
Field Design
Change
Notice
Level Control
Generic Letter
General
Operating Instructions
Gallons
Per Minute
High Pressure
Coolant Injection
Inspector
Followup Item
Intergranular Stress
Corrosion Cracking
Induction Heat Stress
Improvement
Incident Investigation
Information Notice
Institute of Nuclear
Power Operations
Inspection
Report
Limiting Condition for Operation
Low Pressure
Coolant Injection
Hechanical
Stress
Improvement= Program
Nuclear Regulatory
Commission
OSIL
PHT
SCAR
SOS
TI
TS
WP
Operations
Section Instruction Letter
Primary Containment Isolation System
Plant Operations
Review Committee
Post Modification Test
Quality Assurance
Quality Control
Reactor Building Closed Cooling Water
Residual
Heat
Removal
Reactor-Mater
Cleanup
Significant Condition Adverse to Quality Report
Surveillance Instruction
Service Information Letter
Shift Operations
Supervisor
Significant Operating
Experience
Review
Site Standard
Practice
Technical
Instructions
Traversing
In-Core Probe
Technical Specifications
Valley Authority
Violation
Work Order,
Work Plan
Work Request
~O
'