ML18036B129
| ML18036B129 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/22/1992 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036B127 | List: |
| References | |
| 50-259-92-41, 50-260-92-41, 50-296-92-41, GL-88-14, NUDOCS 9301200125 | |
| Download: ML18036B129 (21) | |
See also: IR 05000259/1992041
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-259/92-41,
50-260/92-41,
and 50-296/92-41
Licensee:
Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga,
TN
37402-2801*
Docket Nos.:
50-259,
50-260,
and 50-296
License Nos.:
and
Facility Name:
Browns Ferry Units 1, 2,
and
3
Inspection at Browns Ferry Site near Decatur,
Inspection
Conducted:
November
14
December
16,
1992
Inspector:
~
~
a
nt
nspector
/2-
2
ate
>
ne
Accompanied
by:
J.
Munday, Resident
Inspector
R. Musser,
Resident
Inspector
Approved by:
au
.
e
og
Rea to
c ion 4A
Division of Reactor Projects
SUMMARY
?
QQ CP~
ate
sgne
Scope:
This routine resident
inspection
included surveillance
observation,
maintenance
observation,
operational
safety
verification, modifications, Unit 3 restart activities, reportable
occurrences,
action
on previous inspection findings,
and nuclear
safety review board.
One hour of backshift coverage
was routinely worked during the
work week.
Deep backshift inspections
were conducted
on November
22,
and
December
12,
1992.
A two week
NRC plant design
change
team inspection
was performed.
An exit meeting
was conducted
on December
4,
1992.
The team
V30i200i25 92i223
ADDCK 05000259
8
concluded that
an adequate
design control process
was in place.
A
concern
was raised
about operator action required to open drain
valves in the hardened
wetwell vent modification.
Resolution of
this item is being pursued
by the licensee.
The results of the
inspection will be in inspection report 93-201.
One deviation
was identified for not meeting
a commitment in reply
Instrument Air Supply System
Problems
Affecting Safety-Related
Equipment,
paragraph
four.
The licensee
has failed to verify adequate
margin exits between
the ambient air
temperature
and
dew point range at dryer outlets.
Some vendor
recommendations
have not been followed and test results repeatedly
fail other criteria.
Unit 2 operated
at power coasting
down in power level
and
was
on-line for 77 days at 76 percent
power at the end of the period,
paragraph
four.
The licensee
continues to impose administrative
limits on recirculation
pump speed
due to vibration concerns with
small lines
on the recirculation
system.
Major pre-outage
modifications continue with significant scaffold installation in
the plant.
Plant modifications
has
implemented
a modifications performance
monitoring program,
paragraph five.
This consists of a checklist
that task managers
use to monitor in the field activities.
This
is an effective means to provide real-time feedback to management.
An inspector followup item was identified concerning the failure
of an environmentally qualified limit switch, paragraph
three.
The switch will be examined during the refueling outage
and
any
programmatic
issues
addressed.
Unit 3 activities continued
on
a limited scope,
paragraph
six.
A
reassessment
of the remaining engineering
work continues.
An
estimated
one-half of the design
change notices
have
been
completed.
,
Persons
Contacted
REPORT DETAILS
Licensee
Employees:
0. Zeringue,
Vice President
- J. Scalice,
Plant Manager
J. Rupert,
Engineering
and Modifications Manager
D. Nye, Recovery
Manager
- H. Herrell, Operations
Manager
J.
Maddox, Project Engineer
- H. Bajestani,
Technical
Support
Manager
A. Sorrell, Special
Programs
Manager
C. Crane,
Maintenance
Manager
- G. Pierce,
Acting Licensing Manager
R. Baron, Site guality Manager
- 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:
B. Wilson, Branch Chief
P. Kellogg, Section Chief
- C. Patterson,
Senior Resident
Inspector
- J. Hunday,
Resident
Inspector
R. Husser,
Resident
Inspector
A management
meeting
was conducted
on site
on November
19,
1992, to
review the project status.
NRC attendees
were S. Varga, Director
Reactor Projects I/II; G. Lanias, Assistant Director Region II Reactors;
T. Ross,
NRR; J. Williams,
NRR;
H. Thadani,
NRR;
P. Kellogg, Section
Chief, Region II.
- Attended exit interview
2.
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 of the SIs for technical
adequacy
and
conformance to TS, verification of test instrument calibration,
observa-
tions of the conduct of testing,
confirmation of proper removal
from
service
and return to service of systems,
and reviews of test data.
The
inspectors
also verified that
LCOs were met, testing
was accomplished
by
qualified personnel,
and the SIs were completed within the required
frequency.
The following SIs were reviewed during this reporting
period:
2-SI-4.3.c,
Scram Insertion Times
The licensee
conducted
a load reduction
on December
12,
1992, to
perform scram time testing
as
by required
TS and conduct control
rod drive insert
and withdrawal time testing
on 83 control rods.
The
CRD testing
was conducted
under 2-TI-20, Control
Rod Drive
System Testing
and scram time testing
under 2-SI-4.3.c.
Prior to
the test the inspector
reviewed the procedures
and identified that
2-TI-20 only addressed
testing
when the plant was not operating.
This item was discussed
with the licensee.
The licensee initiated
a procedure
change
on December ll, 1992, to allow the procedure to
be performed while the reactor is operating.
The TI is designated
a complex infrequently performed test that
must
be performed per
SSP 8. 1.
This requires
a test director and
pre-job briefing.
The inspector
attended
the 7:00 a.m., operation
shift turnover meeting
and these
upcoming evolutions were
discussed
and the test director identified.
The inspector
observed
portions of the scram time testing in the control
room
and auxiliary instrument
room.
Each rod was individual
scrammed
from the auxiliary instrument
room and then fully withdrawn from
the control
room.
Personnel
performing the test
used
good
communications.
No deficiencies
were identified.
No violations or deviations
were identified in the Surveillance
Observa-
tion area.
3.
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 certi-
fied parts
and materials,
proper
use of clearance
procedures,
and
implementation of radiological controls
as required.
Work documentation
(HR,
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:
a.
Leaks
On November
12,
1992, the inspector
observed
leakage
from the
reactor building ventilation duct on the
565
and
621 foot eleva-
tions in the reactor building as well as underneath
the torus.
The licensee
previously identified two steam or water leaks in the
main steam vault that they believed were being drawn
up into the
area ventilation exhaust
and then blown through the rest of the
vent duct work.
One leak appeared
to be
the 2-3-568, reactor feedwater
check valve and the other
a pres-
sure seal
leak on the 2-69-580,
RWCU return manual isolation
valve.
These
two leaks
account for about nine
gpm into the
reactor building floor drains.
The actual
source of the leaks in
the steam vault could not be verified due to the local radiation
field and the leak itself.
The inspector questioned
maintenance
personnel
about
when they were sure these
valves were in fact the
ones that were leaking.
The acting Maintenance
Manager
and the
inspector
viewed
a video tape previously made
by maintenance
personnel
that identified the leaks
coming from these
two valves.
The inspector
observed
the leaks
on November 23,
1992, to actually
be spraying
a steam
and water mixture onto other equipment in the
steam vault,
one of which is the outboard HSIV's.
During the
performance of 2-SI-4. 1.A-ll(II), Main Steam Isolation Valve
Closure Functional Test,
on November 28,
1992, the
D line outboard
HSIV, 2-FCV-1-52, failed to generate
a
RPS channel
B half-scram
when tested.
LCO 2-92-402-3. 1.A was entered
and the channel
was
placed in a tripped condition in accordance
with technical
specifications.
The failure was determined to be
a faulty valve
position limit switch that
may have
been
damaged
by this leak.
The switch is designed
to the environmental qualifications of 10 CFR 50.49
and therefore
should
be unaffected
by this type of
environment.
The licensee
intends to monitor the leaks until the
upcoming outage
when the leaks
and the HSIV limit switch will be
repaired.
The failure of the limit switch will be tracked
as IFI
260/92-41-01,
Failure of Environmentally gualified Limit Switch.
Equipment Drain
Sump Inleakage
The Reactor Building Equipment Drain sump is receiving approxi-
mately fifteen gpm inleakage,
eight of which is believed to be due
to hot water leaking past the seat
on the 2-69-577
and 2-69-578,
RWCU return line drain valves.
The inspectors
had previously
observed
steam rising from a drain in the
RHR Hx A room as well as
a four inch drain line that was hot to touch.
Following
investigation,
the licensee
determined
these
were tied to the
reactor building equipment drain
and that the
sump was
actually steaming
back into these lines causing
them to heat.
On
November
12,
1992 the inspector
observed
the
2B Reactor building
equipment drain
pump vibrating and making
a lot of noise.
The
pump was secured
by operations
and
a work order was generated.
The inspector
determined that since October,
1992, this
pump has
been
removed
from service for repair or rebuild three times.
The
licensee
believes
the increased
temperature
in the
sump is
contributing to the high failure rate.
A consultant is being
brought in to investigate
the problem further.
Currently, the
C.
d.
licensee
has
no plans to repair the leaking valves until the
upcoming outage.
Replacement
of Drywell Pressure
Transmitter
An inspector
observed
portions of licensee activities
on November
16,
1992,
associated
with
WO 91-29041-00,
which replaced
the
Drywell Pressure
Transmitter,
2-PT-64-0160B, with a refurbished
transmitter.
The replacement
was part of an on-going project in
response
to
Loss of Fill-Oil In Transmitters
Manufactured
By Rosemount.
The bulletin identified transmitters
from certain lots with model
number
1154
and manufactured prior to
July 11,
1989,
as needing replacement.
The old transmitter
was
a
model
1154 manufactured prior to July 1989, but was not from a lot
that was identified as exhibiting failure due to loss of fill-oil.
The licensee
had previously returned their old transmitters
from
stock to the manufacturer for refurbishment,
and
as
system
maintenance
allowed,
are replacing the old transmitters
with these
new ones.
The transmitter replaced
by this
WO had exhibited
no
indications of fill-oilloss.
The inspector
observed
portions of
the actual
replacement
and reviewed the
WO.
The
WO provided
adequate
instructions
and approvals for the intended work.
Post-
maintenance
testing
was specified in accordance
with 2-SI-
4.2.F.21(B),
Drywell Pressure
Wide Range
(Div. II).
The inspector
did not identify any deficiencies during observation of this
activity.
3A DG Corrective Maintenance
On December
15,
1992, the inspector
observed
work associated
with
corrective maintenance
activities
on the 3A DG.
More
specifically,
damaged
teeth
on the bull gear were repaired
using
files and applicable
honing tools in accordance
with work order
92-66478.
The damage
occurred during the performance of
surveillance instruction 3-SI-4.9.A. l.a (3A), "Diesel Generator
3A
Monthly Operability Test,"
when
an
AUO apparently failed to remove
a manual turning tool from the engine prior to it being started.
The licensee
has initiated an incident investigation into the
matter
and the inspectors will review the results of that
investigation.
In conjunction with repairs to the bull gear,
the
licensee
replaced
two engine jacket water heat exchangers
due to
leaking tubes.
Following these repairs,
the engine
was tested
and
returned to service.
No violations or deviations
were identified in the Maintenance
Observation
area.
Operational
Safety Verification (71707)
The
NRC inspectors
followed the overall plant status
and any significant
safety matters related to plant operations.
Daily discussions
were held
with plant management
and various
members of the plant operating staff.
The inspectors
made routine visits to the control rooms.
Inspection
observations
included instrument readings,
setpoints
and recordings,
status of operating
systems,
status
and alignments of emergency
standby
systems,
verification of onsite
and offsite power supplies,
emergency
power sources
available for automatic operation,
the purpose of 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.
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 selected
plant personnel
in their functional
areas
during these tours.
a ~
Unit Status
b.
Unit 2 operated
at power coasting
down in power level
and was
on-line for 77 days at 76 percent
power at the
end of the period.
The licensee
continues to impose administrative limits on
recirculation
pump speed
due to vibration concerns with small
lines
on the recirculation system.
Major pre-outage
modifications
continue with significant scaffold installation in the plant.
Drywell Control Air
The inspector
reviewed TVA's response
Instrument Air Supply System
Problems Affecting Safety-Related
Equipment
as it pertained to the drywell control air system.
The
response
stated that the system is designed to supply compressed
air with a dew point of 30 degrees
Fahrenheit.
It also states
that the MSIVs and the
MSRVs require supply air with a dew point
of -40 degrees
F,
much less
than the system
can provide.
gDCN
f18984 was written requesting clarification of this requirement
and to determine if the current drywell control air system is
capable of attaining this lower dew point.
The resolution
concluded that the
SRV vendor document
has since deleted
the
requirement to maintain
a specified
dew point for its supply air
and that
a change to the MSIV vendor manual to either delete or
raise the
dew point requirement is being pursued.
It further
stated that the system
can only produce air with a dew point of 35
degrees
F and that this is acceptable.
Testing in accordance
with
TI-34, Monthly Control Air System Dryer Dew point Test
and
Purge
Control, indicates that the 35 degree
F requirement
has not been
maintained.
The inspector
reviewed the tests
performed
on
6
February
21,
1992,
Harch 12,
1992, April 13,
1992,
and April 16,
1992,
and noted that the
2B drywell control air dryer failed to
meet the acceptance
criteria three times
and the
2A dryer once.
Engineering
has determined that the current temperature
switches
require replacement
due to improper deadband
and following
replacement
believe the 35 degree
F dew point can
be achieved.
In
TVA's response
to the
GL, they committed to revising TI-34 to
verify that adequate
margin is maintained
between
the ambient air
temperature
and
dew point range at air dryer outlets.
Contrary to
this, TI-34 was not revised to verify adequate
margin is
maintained for all components
supplied
by the system,
namely the
,
HSIVs.
This is
a deviation from the commitment
made in response
to
This item is identified as
DEV 260/92-41-02,
Drywell
Control Air Dew point.
c.
Unit
1 Hain Battery
During
a routine tour of the control
bay on December
7,
1992, the
inspector toured the Unit
1 main battery board room.
The
inspector questioned
the seismic mounting of the battery because
of styrofoam spacers
between
the battery cells.
Other batteries
in the plant use plywood spacers
that are firmer.
Also, several
of the unistrut locking devices
were secured
and not aligned in
the locknut grooves.
These
items were discussed
with SOS
and
system engineer.
A work request
was written to align the locking
devices correctly.
The vendor was contacted.
The vendor sent
a
letter to the licensee stating the styrofoam spacers
were supplied
with the battery
and rack and were acceptable
for seismic
protection.
These actions resolved the questions
regarding
seismic mounting of the Unit
1 battery.
One deviation
was identified in the operational
safety verification
area.
Hodifications
(37700,
37828)
The inspectors
maintained
cognizance of modification activities to
support the restart of Unit 2.
This included reviews of scheduling
and
work control, routine meetings,
and observations
of field activities.
Throughout the observation of modifications being performed in the field
gC inspectors
were observed monitoring and documented verification at
work activities.
The licensee
has developed
a program to assess
contractor compliance
with plant requirements for major maintenance
and modifications work.
In the past, this work had
been performed
by utility personnel.
The
modifications group for Unit 2 developed this program.
Key elements of
this program are task managers
and task manager
rounds.
A task manager
was assigned
to each design
change.
The task manager
remains in contact
with the design
change until the system is returned to service.
During
implementation of the design,
the task manager
makes daily rounds of all
projects
assigned
to them.
A field implementation checklist
was
developed to aid the task managers
and provide consistency.
The
checklist requires
review of proper work authorization
and permits,
work
documents
on site,
housekeeping,
productivity, craftsmanship,
safety
practices,
alarm,
and other items.
This data is compiled
and management
reports generated.
The inspector
reviewed several
reports
and program organization.
This
program provides
an effective means to provide real-time feedback to
management
on plant modifications.
This program is being extended to
Unit 3 recovery activities.
No violations or deviations
were identified in the modification area.
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
personnel,
skilled craftsmen,
supervisors,
managers
and executives.
a ~
Unit 3 Engineering
On December
9,
1992, the inspector
met with the Site Engineering
and HodificatIons Manager at the Bechtel
engineering offices in
Athens,
Discussions
were held with the
new Bechtel
project manager,
David Brannen
and
new Bechtel
engineering
manager
Rick Jackson.
The overall status of Unit 3 recovery
and Unit 2
Cycle
6 outage
were discussed.
DCN production
was reviewed.
For
Unit 3 and multi-unit DCN's about half of 500 total
DCNs are
complete.
This was accomplished
in the preceding year or year
and
a half.
A complete review of these
DCN's by the licensee
as part
of the transition to a single organization
was performed.
Consultants
were being
used to promote team building.
Some
88
DCN's were eliminated or determined
not needed.
The screening
criteria used
was that all commitments or commitment related
work
would be performed.
Also, uniformity would be maintained
between
Unit 2 and Unit 3.
The remaining
DCNs were being reviewed to see
if they could be completed
by the end of the Unit 2 Cycle
6 outage
consistent with productivity rates.
The current Bechtel staff had
been
reduced
from 1480 to 800-850 personnel.
All the
DCNs for the
Unit 2 Cycle
6 outage
were complete
except for CREVs
modifications.
A POD meeting is conducted
each
day at noon.
The inspector
attended
the meeting
on December
10,
1992
and December
15,
1992.
The meeting is conducted
by TVA management
with the Bechtel
engineering
manager
in attendance.
Emphasis
was placed
on meeting
the scheduled
DCN production for the week.
The inspector will continue to monitor the
new organization
and
attend
POD meetings.
The initial assessment
is that
TVA managers
have
assumed
the lead responsibility for Unit 3 engineering
recovery with emphasis
on working together with the contractor.
SPOC Walkdown of Cooling Towers
On December
7,
1992, the inspector
accompanied
the licensee
on
portions of the
Phase
I SPOC walkdown of the cooling towers, lift
pump stations,
and associated
4kV switchgear.
The walkdown team,
included persons
from TVA technical
support,
operations,
electrical
maintenance,
and the work control group,
conducted
the
walkdown in accordance
with OSIL number 64,
"System
Pre-Operability Checklist Walkdowns."
The operations
walkdown was
performed to satisfy the requirements
of step VI.3. of Appendix
C
in SSP-12.
In addition, four evaluators
from the Site guality
Audits and Assessments
organization
took part in the walkdown to
evaluate
the performance.and
adequacy of the
SPOC for the cooling
towers.
During the
SPOC,
each cooling tower cell was entered
and
inspected.
Emphasis
was placed
on the cooling tower fans
and
associated
electrical cabling.
The lift pump stations
were
examined for damage/defects
through
a visual walkdown.
The 4kV
switchgear
rooms were walked
down in a similar fashion.
Discrepancies
identified were recorded in Attachment
2 of OSIL
number 64.
Each discrepancy
was assigned
a work request
number
for dispositioning.
After the walkdown, the
SRO determined
in which phase of the
program each matter would have to be completed,
in order to
satisfy the
SPOC.
Items identified during the walkdown included:
Inadequate
sealing of power cables to the cooling tower fans
General
housekeeping
deficiencies
Loose or missing bolts in the fan stacks
Supports missing from cables
and small tubing
Loose ground cabling
Hissing tags
(a few)
A breaker
door that would not latch
Improper oil level for two cooling tower fans
Based
on the inspectors
observations,
the walkdown was adequate
and satisfied
the applicable portion
(Phase
I) of the
SPOC.
JTG Meeting
On December
10,
1992, the inspectors
attended
JTG meeting
92-005
in the plant engineering building.
The first item of discussion
was the approval of the previous
JTG meeting minutes.
The minutes
were approved
as proposed to the group.
Following discussion of
the meeting minutes,
a change to test procedure
3-RTP-027C,
"Condenser Circulating Water Test,"
was presented
to the JTG.
The
change deleted existing procedure
steps for the performance of
5 and
6 pump discharge
flow control valve
and bypass
valve interlock test.
These
items were previously performed
during the post modification test.
Furthermore,
steps
were
added
to the procedure to verify and review the post maintenance
test
records
and to attach
a copy of the records to the procedure.
Two
additional
steps
were
added to the procedure to verify that flow
was established
to the cold water channel
through the cooling
tower bypass
valve.
The safety
assessment
for the change
was also
presented
to the group.
The changes
were approved
and forwarded
to the plant manager for his approval.
During the meeting,
the
JTG chairman discussed
a Notice of
Violation issued
at Watts Bar in NRC Inspection
Report 390,
391/92-30.
The violation stated that contrary to the Watts Bar
JTG charter,
agenda material
was not being distributed prior to
the meeting.
The Browns Ferry JTG chairman stated that
no such
requirement existed at
BFNP,
however it was standard
practice to
distribute
agenda material prior to scheduled
meetings.
He
further stated that if a special
JTG meeting
was required,
ample
review time during the meeting would be provided for each group
member.
Reportable
Occurrences
(92700)
The
LERs 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.
(CLOSED)
Reactor
on Indicated
High Reactor
Water
Level
Caused
by Signal
Spike During Feedwater
Level Control
System
Troubleshooting
On July 28,
1992, during troubleshooting of the Unit 2
FWLC System,
a
main turbine trip and reactor
scram occurred.
Engineered
safety feature
actuations
including PCIS groups
2, 3, 6,
and
8 occurred
as well as
initiation of Standby
Gas Treatment
and
CREV.
The trip occurred
due to
an unexpected
level spike induced during the replacement
of a relay in
the
FWLC system.
The licensee
determined
the root cause of the event to
be due to an inaccurate
evaluation
and diagnosis of prior feedwater
system trouble symptoms,
and failure to anticipate the
FWLC circuit
response
to the relay replacement.
The licensee
revised Electrical
Generic Troubleshooting
Instruction EII-0-000-TCC106
and I
5.
C Generic
Troubleshooting Instruction SII-O-XX-00-3014, to include
a requirement
10
that activities involving high risk troubleshooting
receive
an
independent
technical
review.
Additionally this event
was reviewed with
technical
support,
maintenance,
and operations
personnel
and included
emphasizing that work involving the breaking of current loops must
be
evaluated for signal spiking during re-establishment
of the loop.
The
inspector determined that adequate
licensee
actions
have occurred to
preclude
a recurrence
of this event.
Action on Previous
Inspection
Findings
(92701,
92702)
a ~
(CLOSED) VIO 259,
260, 296/92-03-01,
Failure to Follow Procedure
for Diesel
Generator Surveillance
and Spent
Fuel
Pool Transfer
Canal Operation.
In the first example during the performance of a SI,
an
inadvertent
DG start occurred.
This was caused
by a communication
problem between
maintenance
and operations
personnel
during
altering of the hold order boundary for the
DG start circuit.
The
corrective actions for this violation were revision of the
equipment clearance
training program to include the circumstances
of this event, training of appropriate
personnel,
and revision of
the SI to include specific instructions
on equipment
alignment.
The inspector reviewed the licensee's
response,
supplemental
response,
and closure
package for this example.
The documentation
provided indicated the corrective actions
were completed
and
addressed
the cause of the violation.
The second
example
was for transferring material
through the spent
fuel transfer canal without utilizing an approved
procedure.
This
violation was caused
by inadequate training.
The corrective
actions taken included review of the event,
counseling of
personnel,
and revision of two other plant procedures
to reference
the procedure for the transfer canal.
The inspector
reviewed the
closure
package for this item and the procedure revision.
The
actions
addressed
the violation.
b.
(CLOSED) VIO 259,260,296/92-11-01,
Failure to Perform Independent
Verification.
The first example occurred during the performance of Surveillance
Instruction 0-SI-4. 11.B.2.a,
Diesel Driven Fire
Pump Operability
Test.
On April 15,
1992,
an
NRC inspector
observed that
independent verification steps
in the body of the instruction wer e
not performed "step
by step"
as required
by SSP-12. 1, Conduct of
Operations.
Six steps
in the SI required
IV following performance
of the step
and prior to continuing with the next step.
The
verification steps
were performed
upon completion of the test.
TVA reevaluated its program for IV and determined that SIs with IV
steps
located in the body of the procedure
cannot
have the
IV
performed
as required
by SSP-12.6,
Verification Program,
"step
by
step", without negatively impacting the performance of the
procedure.
To do this would require constant
stopping,
performing
11
the IV, and then recommencing
the SI.
Therefore,
TVA reviewed all
SIs to re-verify the need for IV and
remove if unnecessary,
and to
relocate
IV steps that are not necessary
to prevent detrimental
equipment operation to the end of the SI.
Two-hundred sixty-five
procedures
were revised
based
on this review.
Following these
revisions the Site guality organization
performed
a review of ten
percent to independently verify their accuracy.
No discrepancies
were identified.
The inspector reviewed the following revised
procedures
and found no discrepancies:
2-SI-4.2.A.22
Rev 5,
Group I PCIS Logic
2-SI-4.4.A.2
Rev 12,
SLC System Functional
Test
2-SI-4.5.B.l.a(I)
Rev 6,
Loop I
RHR Simulated Automatic
Actuation Test
2-SI-4.7.F. 1
Rev 3, Primary Containment
Purge
System Filter
Pressure
Drop Test
O-SI-4.11.B.l.c
Rev 12, High Pressure
Fire Protection
System
Flushes
0-SI-4. 11.8.2.a
Rev 10, Diesel
Driven Fire
Pump Operability
Test
2-SI-4.5.G
Rev 6, Automatic Depressurization
System
Simulated
Auto Actuation Test
2-SI-4.2.B-27
Rev 8, High Pressure
Coolant Injection Sup-
pression
Chamber
High Level Instrumentation Calibration
2-SI-4.2.B-24FT(II)
Rev 1,
Core Spray Sparger to Reactor
Pressure
Vessel Differential Pressure
Functional
Test
2-SI-3.2. 10.F
Rev 5, Verification of Remote Position Indica-
tors for Reactor
Core Isolation Cooling
2-SI-4.7.A.2.g-3/3b2
Rev 4, Primary Containment
Local
Leak
Rate Test Reactor
Line B: Penetration
X-9B
2-SI-4.7.A.2.g-3/32a
Rev 6, Primary Containment
Local Leak
Rate Test Control Air: Penetration
X-48
The second
example occurred
on February
25,
1992 during the
performance of Surveillance Instruction 2-SI-4.2.C-8FT
when
a step
requiring IV was not performed properly.
The individual
performing the IV relied on the observed
actions of another
individual rather than performing
a physical
hands
on check
himself.
This resulted in a pressure
transmitter isolation valve
for turbine first stage
pressure,
remaining closed for six days
following completion of the surveillance.
This individual
received
personnel
corrective action in accordance
with TVA
personnel
policy.
Based
on the above,
the inspector determined that adequate
licensee
actions
have
been taken to preclude recurrence
of this
event.
12
Nuclear Safety
Review Board
(40500)
On November 20,
1992, the inspector
met with the
NSRB Chairman at the
corporate office.
The organizational
structure,
membership,
and
use of
outside advisors
were reviewed.
The
NSRB Chairman functions
as both the
NSRB Chairman. reporting to the
Senior V.P. Nuclear
Power
and
as General
Manager; Materials, Contracts,
and Administrative Support; reporting to the V.P. Nuclear Assurance,
Licensing,
and Fuels.
This organization chart is in the N(AP.
A
proposed
change to the structure will change
the latter position title
to General
Manager Nuclear Support.
The present
NSRB makeup at each site includes the following:
a.
Site Members
1)
Site V.P.
2)
Licensing Manager
3)
guality Assurance
Manager
4)
Engineering
and Hodifications Manager
b.
Members from TVA Corporate
and other sites
1)
NSRB Chairman
2)
Six of 12 other members
each site is different and each of
the members
except for the senior consultant is
a V.P. or
reports directly to a V.P.
c.
Outside Advisors - three of seven outside advisors with expertise
in each plant design.
One advisor is also
an advisor to the
board
and serves
on all three boards.
On October
1,
1992, the membership
on
NSRB was changed to increase
the
number of TVA senior management
personnel
and reduce the number of
outside advisors
from five to three.
This change
was
made with the
philosophy that
TVA management
has strengthened
with the successful
return to operation of units at two sites permitting the reduction in
use of outside advisors.
The use of advisors to strengthen
the
NSRB was discussed
in TVA's
Corporate
Nuclear Performance
Plan,
Volume I.
The
NRC issued
an
SER as
Volume I, in July 1987.
In 'the
SER,
page
27, it was stated
that the
NRC staff will determine the acceptability of each
NSRB as part
of its plant-specific reviews.
The activities of the
NSRB were reviewed
in IR 90-14.
This included
a review of resumes
of the
NSRB members
and
outside advisors.
The membership
was determined to be acceptable.
The
T.S. requirements
of the
NSRB are in section G.5.2.
The inspector
reviewed the
TS and
a quorum is five members.
Stated
in TS is that the
use of consultants
shall
be utilized to provide expert advise
as
determined
by the
NSRB.
The inspector
concluded that the composition of
the present
NSRB exceeds
the
TS requirements.
In addition, the outside
13
advisors
are
on
NSRBs of other utilities.
This provides
a broad
perspective
of industry activities for TVA plants.
The effectiveness
of the
NSRB was documented
in
NRC IR 92-33
and 91-33.
The inspector
concluded that the recent
changes
made to the
reducing the number of outside advisors
was
a logical transition
based
on the demonstrated
effectiveness
of the board.
The
new structure still
exceeds all
TS requirement with senior
TVA personnel
with ample
seniority capable of challenging the plant staff on safety issues.
Exit Interview (30703)
The inspection
scope
and findings were summarized
on December
18,
1992
with those
persons
indicated in paragraph
one above.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection
findings listed below.
The licensee
did not identify as proprietary
any
of the material
provided to or reviewed
by the inspectors
during this
inspection.
Dissenting
comments
were not received
from the licensee.
Item Number
Descri tion and Reference
260/92-41-01
260/92-41-02
IFI, Failure of Environmentally gualified
paragraph
three.
DEV, Drywell Control Air Dew point,
paragraph
four.
Licensee
management
was informed that
1
LER and
2 VIOs, were closed.
and Initial i sms
BFNP
CFR
DCN
DEV
F
GL
GPH
IFI
IR
IV
JTG
LCO
LER
HSIV
Auxiliary Unit Operator
Browns Ferry Nuclear Plant
Code of Federal
Regulations
Control
Rod Drive
Control
Room Emergency Ventilation
Design
Change Notice
Deviation
Diesel
Generator
Fahrenheit
Flow Control Valve
Level Control
Generic Letter
Gallons
Per Hinute
Inspector Followup Item
Inspection
Report
Independent Verification
Joint Test
Group
Limiting Condition for Operation
Licensee
Event Report
Haintenance
Request
Hain Steam Isolation Valve
NQAP
NRC
OSIL
QDCN
TI
TS
Hain Steam Relief Valve
Nuclear Quality Assurance
Plan
Nuclear Regulatory
Commission
Nuclear Reactor Regulation
Nuclear Safety
Review Board
Operations
Section Instruction Letter
Primary Containment Isolation System
Quality Assurance
Quality Control
Quality Design
Change Notice
Residual
Heat
Removal
Reactor Protection
System
System
Safety Evaluation Report
Surveillance Instruction
System Pre-Operability Checklist
Senior Reactor Operator
Site Standard
Practice
Technical Instruction
Technical Specification
Valley Authority
Violation
Work Order
Work Request