ML18025B619
| ML18025B619 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 06/26/1981 |
| From: | Cantrell F, Chase J, Paulk G, Sullivan R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18025B609 | List: |
| References | |
| 50-259-81-14, 50-260-81-14, 50-296-81-14, NUDOCS 8109010524 | |
| Download: ML18025B619 (22) | |
See also: IR 05000259/1981014
Text
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NUCLEAR REGULATORY COMMISSION
REqION II
101 MARIETTAST., N.W., SUITE 3100
ATLANTA,GEORGIA 30303
Report Nos. 50-259/81-14,
50-260/81-14
and 50-296/81-14
Licensee:
Valley Authority
500A Che'stnut Street Tower II
Chattanooga,
37401
Facility Name:
Browns Ferry Nuclear Plant
Docket Nos. 50-259, 50-260,
and 50-296
License Nos. DPR-33,
and DPR-68
Inspection at Browns Ferry Site near Athens,
I
I
Inspector:
.
T
R.
F. Sullivan
c-.Z
G. L. Paulk
r
-C~
J
W.
hase
Approved by:
F. S. Cantrell, Sectj46
ief, Division of
Resident
and Reactor Project Inspection
Date Signed
Date Signed
z~ ei
Da
e Sig ed
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P/
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tg
SUMMARY
Inspection
on April 28 through May 25,
1981
Areas Inspected
This routine inspection
involved
246 resident
inspector-hours
in the
areas
of
operational
safety,
reportable'occurrences,
plant physical
protection,
reactor
trips,
surveillance
testing,
main'tenance,
fire protection,
review of star'tup
report, followup of primary leak Unit 3 and TMI action Items.
Results
Of the
10 areas
inspected,
no violations or deviations
were identified in seven
areas.
Three violations were found in three areas;
(Failure to follow procedures
for control
room emergency pressurization
(Units 1,
2 and 3), paragraphs
5 and 8;
Failure
to
have
high
pressure
coolant
injection
system
(Unit 3),
paragraph
8; and,
High pressure fire pumps auto-start
paragraph
12).
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DETAILS
Persons
Contacted
Licensee
Employees
H. L. Abercrombie,
Power Plant Superintendent
J.
R. Bynum, Assistant
Power Plant Superintendent
J.
L. Harness, Assistant
Power Plant Superintendent
R. T. Smith, equality Assurance
Supervisor
R.
G. Metke, Engineering Section Supervisor
D. C. Mims, Engineering
and Test Unit Supervisor
R.
G. Cockrell, Reactor Engineering Unit Superv'isor
J.
B. Studdard,
Operations Section Supervisor
A. L. Burnette, Assistant Operations Supervisor
R. Hunkapillar, Assistant Operations Supervisor
T. L. Chinn, Plant Compliance Supervisor
M. W. Haney, Mechanical Maintenance Section Supervisor
J. A. Teague, Electrical Maintenance
Section Supervisor
J.
K. Pittman, Instrument Maintenance Section Supervisor
J.'. Swindell, Overage Director
, B. Howard, Plant Health Physicians
R.
E. Jackson,
Chief Public Safety
R. Cole,
(}A Site Representative
Office of Power.
Other
licensee
employees
contacted
incl'uded
licensed
senior
reactor
operators,
reactor operators,
auxiliary operators,
craftsman,
technician,.
publ.ic safety officers,
gA personnel
and engineering personnel.
2.
Management Interview
Management
Interviews was conducted
on
May 1, 8,
15 and 22,
1981, with the
Power Plant Superintendent
and/or his assistant
power plant superintendents
and other
members
of his staff.
The inspectors
summarized
the
scope
and
findings of their inspection activities.
The licensee
was informed of the
four apparent
violations identified during the report period.
On June
12,
1981,
a
telephone
conference
was
held
between
Mr. James
P.
O'Rei lly,
Director,
Region II and Mr.
H. J.
Green, Director, Nuclear Operations
TVA.
The topics of discussion
were recent operational
events
and the effects that
plant
modifications
are
having
on
safety-related
systems
and
plant
operations.
The control of work activities at the plant was stressed
during
the discussions.
3.
Licensee Action on Previous Inspection Findings
Not inspected.
Unresolved Items
Unresolved items were not identified during this inspection.
Operati'onal
Safety
The inspectors
kept informed
on
a daily basis of the overall plant status
and
any significant safety
matters
related
to plant operations.
Daily
discussions
were held each morning with plant management
and various members
of the plant'operating staff:
The inspectors
made frequent visits to the control
room such that each
was
visited at least daily when
an inspector
was
on site.
Observation
included
instrument readings,
setpoints
and recordings;
status of operating
systems;
status
and alignments
of emergency
standby
systems;
purpose
of temporary
tags
on equipment controls
and switches;
alarms;
adherence
to
procedures;
adherence
to limiting conditions
for operations;
temporary
alterations
in effect; daily journals
and data
sheet
entries;
and control
room
manning.
This inspection
activity also
included
numerous
informal
discussions with operators
and their supervisors.
General
plant tours were conducted
on at least
a weekly basis.
Portions of
the turbine building,
each reactor building and outside
areas
were visited.
Observations
included..-valve
positions
and
system
alignment;
and
hanger
conditions;
instrument
readings;
housekeeping;
radiation
area
controls; tag controls on equipment; work activities in progress;
vital area
control,s;
personnel.
badging,
personnel
search
and
escort.
Informal
discussions
were held with selected plant personnel
in their functional area
during these'ours.
On May 20,
1980 during
a routine tour of the control building, the inspector
noted that the control
room emergency ventilation
(CREU) unit "B" was not
aligned correctly, in that switch 0-HS-31-152
was in the "on" position vice
"auto" as required
by Operating
Instruction (OI)-31, Air Conditioning
and
Heating .of Reactor Building Control Bay.'he
inspector reported this to the
Assistant
Operation
Supervisor
who in turn directed
the Unit 3 Assistant
Shift Engineer
(ASE) to investigate the problem.
The ASE;; an electrical
engineer
and the inspector,
determined
by review of
drawings, that by having switch 0-HS-31-152 in the
"on" position,
the
"B"
CREY unit
should
have
been
running
and .damper
31-152
should
have
been
opened.
The
"B"
CREY unit was
not running
because
the local start-stop
switch for the
fan
was in the
stop position.
31-152 was not open
because
on the ventilation duct
was binding the linkage for the
The
ASE freed the linkage for damper
31-152 to.allow the damper to operate
and
had the lagging
removed to prevent further binding.
The local control
switch
was
placed
in the start position
and 0-HS-31-152
was placed in the
auto position.
These actions
were performed within 30 minutes of the time
the inspector identified the problem.
The unit was then tested satis-
factorily to ensure operability.
The licensee
has
been
unable to determine
how long the "B" CREV unit was inoperable.
The "A" CREV unit was determined
to be
operable'n
May 22,
1981,
the inspector
identified that not having the "B" CREV unit
was
an apparent
violation to the Assistant
Plant Superintendent.
This event
was described
as
a failure to .follow procedure
(OI-31) which i s
required
by
Technical Specification 6.3.A. l.
The
Assistant
Plant
Superintendent
accepted
the
apparent
violation
without
comment
(259/81-14-01,
260/81-14-01
and 296/81-14-01).
The inspectors
reviewed activities associated
with the below listed reactor
trip during this report period.
The review included determination of cause,
safety sign'ificance,
performance
of, personnel
and
systems,
and corrective
action.
The inspectors
examined
instrument recordings,
computer printouts,
operations
journal
entries,
reports
and
had
discussions
with
operations,
maintenance
and engineering
support personnel
as appropriate.
On April 23,
1981, Unit 3 tripped at 5:31 a.m.
from full power due to low
reactor water level. 'uring the transfer of start
busses
a short inter-
ruption of plant preferred
and non-preferred
power resulted in recirculation
pump runback followed by
a rapid increase
back to
90% of full flow.
The
resulting reactor water level collapse
produced
the low water level reactor
trip and
MSIV closure.
and
RCIC initiation occurred
but both were
tripped
on high reactor water level before injection into the vessel.
The
main
steam relief valves were manually operated
to control pressure.
Plant
safety systems
responded satisfactorily.
No violations'or deviations were identified within the areas
inspected."
Reportable
Occurrences
The below listed licensee
event repor ts (LERs) were reviewed to determine if
the information provided met
NRC reporting requirements.
The determination
included
adequacy
of event
description
'and corrective
action
taken
or
planned,
existence
of potential
generic
problems
and
the relative safety
significance of each event.
Additional in plant reviews and discussion with
plant personnel
as appropriate
were
conducted
for those
indicated
by
an
asterisk.
LER NO.
259-81011
259-81015
Date
05-15-81
05-20-81
Event
Local fire protection panel
25-331
was deenergized
Continous air monitor for reactor/
turbine
building
ventilation
was
~260-81014
260-81016
"260-81017
"296"81015
~296"81016
05-11-81
04-07-81
04-27-81
05-05-81
04-08-81
04-08-81
2C Residual
Heat Removal
Heat
Exchanger
had leak on the inner head
Mode A of reactor water level
instrumentation
failed
upscale
resulting in turbine trip.
Scram discharge
instrument volume
switch
not
set
within
technical specification limit.
Reactor
zone ventilation system
isolated
during
normal
reactor
operation.
High pressure
coolant injection
turbine
inner
exhaust
disc
ruptured.
With 3C Residual
Heat Removal heat
exchanger
out for maintenance,
the
high
pressure
coolant
injection
pumps
were
determined
to
be
Within the areas
reviewed,
no violations or deviations were identified.
The inspectors
observed
the
performance
of the
below listed surveillance
procedures.
The
inspection
consisted
of
a
review of the
procedure
for
technical
adequ'acy,
conformance to technical specifications,
verification of
test instrument calibration,
observation
on the conduct of the test,
removal
from service
and return to service of the system
and review of test
data'.
SI 4.2.E.2
b.
S I 4.2.B. 27
c.
SI 4.7.A.2
d.
SI 4.9.A.2.C
Air Sampling System Drywell Leak Detection
Suppression
Chamber Level
Primary Containment Integrated leak Rate test
(Isolation Valves Feedwater
System).
Battery Discharge Test
The inspector
had
no
comments
on
the
above
surveillance
test
with the
exception of SI 4.9.A.2.C, Battery Discharge Test which is discussed
below.
On
May
5,
1981,
the
inspector
observed
Surveillance
Instruction
(SI)
.
4:9.A.2.C (Battery Discharge Test) for the Unit 2 battery.
The test started
at 1: 16 p.m.
The inspector
observed
the start of this test from the battery
discharge trailer and then left to observe
other testing areas.
A tour of
the Unit 3 control
room revealed that SI 4.9.A.2.C prerequisite
step 1.5 was
not satisfied.
The prerequisite
requires
that
each
operating
unit high.
pressure
coolant injection (HPCI) valve (73-44)
HPCI, discharge
valve to be
open
and tagged with a caution order when the battery discharge test is in
progress.
Unit
2
and
3 were operating
at full pow'er and Unit
1 was in a
refueling outage during the test.
Unit 2 HPCI discharge
valve was
open
and
tagged
and
the Unit
3
HPCI discharge
valve
was
shut
and not tagged.
The
inspector notified the Assistant Shift Engineer in Unit 2 of the discrepancy
and
he responded
that
he interpreted
the surveillance
procedure
to require
only
opening
the
discharge
valve for the unit under test.
The
inspector notified the Assistant Operations Supervisor 'of the discrepancy
at
2:30
p.m.
on
May 5.
He
responded
that prerequisite
step
1.5 was required
for all'operating units and
he immediately called the Shift Engineer to have
the discrepancy corrected.
The inspector
learned later that the Unit 3 operator
opened HPCI'valve 73-44
for unit 3 at 3:00 p.m.
on
May 5 and noted that the
HPCI suction
pressure
gage
pegged
high indicating that the air operated
check valve downstream of
the
HPCI discharge valve'as
leaking past its seat.
The operator
reclosed
HPCI discharge
valve
73-44 to prevent potential
overpressurizing
of the
condensate
system.
Operating Instruction (OI) 57
(II.G) requires that when
a unit battery is out of service
the
HPCI valve
73-44 must
be
opened to
consider
system
Unit
3
system
was
not
declared
on May 5,
1981,
as required
by OI-57 and Technical Specification
surveillance
requirements
4.5.E.2.
No further action
was
taken
by the
licensee
on this date.
On
May
6
at
9:00
a.m.
the
inspector
informed
the
Assistant
Plant
Superintendent
of the procedural
problems
encountered
the previous
day.
At
1: 15 p.m., the inspector toured the Unit 3 control room and noted
HPCI valve
73-44 was still shut, with the battery discharge test still in progress.
The
inspector
immediately advised
the Shift Engineer that the
HPCI Valve 73-44
was required to be open in accordance
with the test procedures
and if this
valve
could
not
be
opened
the
system
was required
to
be declared
in
accordance
with Operating
Instruction
57
and
Technical
Specification surveillance
requirement 4.5.E.2.
The Shift Engineer
said
he
would look into the matter.
At 4:00 p.m. the inspector
called the Assistant
Operations
Supervisor
to ask the status
of the Unit
3
system.
He
reported
the
system fully operational.
The inspector
expressed
his
concerns
over the OI-57 requirement
and the Assistant Operations
Supervisor,
concurred
and declared
HPCI system for Unit 3 inoperable at 4:02 p.m. which
is approximately
27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />
from the start of the test,
and
25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />
from the
initial attempt to open
HPCI valve 73-44 for Unit 3.
Procedures
OI-57
and
SI 4.9.A.2.C requires
discharge
valves
to
be
opened
in accordance
with the General Electric design analysis criteria step
10
on figures 8.6-4b
and 8.6-4c of the plant's
FSAR.
Several
operators,
assistant
shift engineers,
and shift engineers
were not familiar with the
requirement
of OI-57 or SI 4.9.A.2'.C to
open
HPCI valves
73-44
when
a
battery is out of service.
The failure to adhere
to procedures
is contrary
to Technical Specifications 6.3.A.6
which states
that detailed 'ritten
procedures
shall
be
prepared
and
adhered
to for surveillance
testing
and
requirements.
The
inspector
informed
the
licensee
of this
apparent
violation (260/81-14-01
and 296/81-14-01)
on May 7, 1981,
The failure to declare
high pressure
coolant injection system
inoperable is
contrary to Technical Specification 3.5.ED 1 which states
that
the
high
pressure
coolant
injection
system
shall
be
whenever
there
is
irradiated
fuel in the reactor vessel
and the reactor vessel
pressure
is
gr'eater
than
122 psig.
This matter
and other
events
involving compliance
with Technical
Specification
were discussed
in
a telephone
call
May 11,
1981,
from the Director,
Region II to the Director of Nuclear
Power,
TVA.
This is identified as
a violation (296/81-14-03.)
Plant Physical Protection
During
the
course
of routine inspection activities,
the inspectors
made
observations
of certain
plant
physical
protection
activities.
These
included personnel
badging,
personnel
search
and escort,
vehicle
search
and
escorts,
communications
and vital area access control.
No violations or deviations were identified within the areas
inspected.
10.
Review of Unit 3 Startup Report
The inspector
reviewed
Startup
Report for Unit
3 fuel cyclic four, dated
April 20,
1981.
The review was
conducted
to verify that the information
reported
was technically
adequate
and that the reporting
requirements
of
Technical Specification 6.7. l.a were satisfied.
u.
Within the areas
inspected
no violations or deviations were identified.
Maintenance
The
inspectors
observed
the
below listed
maintenance
activities
for
procedure
adequacy.,
adherence
to procedure
and
observed
the
actual
per-
formance of the work activity.
a.
Mechanical
Maintenance'nstruction
(MMI)-23 Quarterly Inspection
of
High-Pressure
Coolant Injection.
b.
Electrical Maintenance
Instruction (EMI)-78 Torquing of 480
V Shutdown
Board Normal Feeder
Busway Joint Bolts.
No violations or deviations were identified in the areas
inspected.
12.
Fire Protection
~
On May 1,
1981,
the licensee identified to the resident
inspector that the
auto-start capability for all four fire pumps
had
been defeated
by lifting
the auto-start 'circuit electrical
in relay board
52.
Plant staff
concluded
that these electrical
were lifted by
workman installing
circuits for the new 500
KV Cordova line sometime after April 14,
1981.
These electrical
had been identified by the engineer
in charge of the
modifications
as
not to
be lifted'y placing
"masking"'ape
over
the
terminals
and
the electrical
leads prior to the modification beginning.
Other electrical
leads which were identified in,this manner were not
disturbed.
In addition,
no other safety
systems
had
been disabled or worked
on because of this modification.
TVA's evaluation
showed that all four fire pumps
could
have
been started
manually if needed
and at least
one fire pump was running at all times since
April 14 to May 1,
1981 which wo'uld have provided automatic fire protection.
Under the IE new interim enforcement criteria for license identified items,
this item was presented
to the Plant Superintendent
as
an apparent violation
on
May 8,
1981
for
the failure to
have
the
automatic initiation logic
for the
high
pressure
fire protection
system
as
required
by
Technical Specification
3. 11.A. l.b.
The Plant Superintendent
was requested
to
address
the control
of plant modification
work in
response
to the
apparent violation (259/81-14-02,
260/81-14-03
and 296/81-14-04).
Primary Leak Unit 3
On May 21,
1981, at 11:45 p.m. after completing the pumping of nitrogen from
the torus to the drywell to maintain the differential pressure
greater
than
1.3 psig between
torus
and drywell, the operator
noted
a steady
increase
in
drywell
pressure
at approximately
0. 1
psig
per
minute.
The
operator
suspected
a loss of reactor building closed
cooling water
(RBCCW) to the
drywell fans.
He increased
the
RBCCW flow to the drywell..by isolating the
reactor
water cleanup
(RWCU) system.
This action
decreased
the rate at
which the drywell pressure
was increasing
to approximately
0.025
psig per
minute.
To prevent
a primary containment isolation, which occurs at
2 psig
drywell pressure,
the operator
cross
connected
the torus to the drywell via
the
stand-by
gas
treatment
system
to. equalize
pressures.
This
was
done
approximately
5 minutes
into the
event
and, after drywell
pressure
had
reached
1.6 psig.
This action
decreased
the -'drywell pressure
to approx-
imately 1.0 psig.
On
May 22,
1981,
at
1230
a.m.
the drywell equipment
drain
pumps
came
on
indicating
a total
leak rate
in to the drywell of 21.5
gpm.
(This gave
approximately
18
gpm unidentified
leakage
and
Technical Specification 3.6.C. 1 allows less
than
5 gpm'unidentified).
The operator
then
began
a
reactor
shutdown at 12:35 a.m.
and
had the reactor
shutdown at 1:23 a.m.
on
May 22,
1981.
At 12:45 a.m.,
the Senior
Reactor Operator declared
a site
alert and informed the
NRC via the red phone of the situation at 1:00 a.m..
At 2:30 a.m.,
TVA secured
from the site alert and went to an unusal
event
status
because
the
leak rate
was
less
than
25
gpm.
No radioactivity was
released
to the outside environment.
During the cooldown of the reactor,,the
leak rate into the drywell steadly
decreased
until it stabalized
out at approximately
7
gpm at 6:00
a.m.
on
May 22,
1981.
At 12:02 a.m.,
on May 23,
1981,
personnel
entered
the Unit 3
drywell and determined that leakage
was coming from "B" recirculation
pump
discharge
valve
(68-79)
packing.
The
valve
was
then
back
seated
and
repacking
commenced.
During the. repacking of the valve, it was determined
that the majority of the packing
had
been
blown out causing
the leak.
is currently evaluating the cause
and corrective action.
There was no
t
damage
inside the drywell as
a result of the leakage.
Unit 3 was returned
to service at 0410 on May 26,
1981.
Sequence
of Events
May 21,
1981
11:45 p.m.
11:48 p.m.
11:51 p.m.
Completed pumping nitrogen from torus to drywell, drywell pressure
begins to increase.
Increased
RBCCW system flow
Cross connected drywell to torus via SBGT maxium drywell
pressure
has increased
to 1.6 psig
May 22,
1981
12:30 p.m.
12:35 p.m.
12:45 p.m.
Drywell equipment drain pump started indicating leak of 21.5 gpm.
Commenced reactor shut down
Senior Reactor Operator declares
a site alert
NRC was informed that
a leak rate of 21.45
gpm was occurring into
the drywell.
1:23 a.m.
Reactor is 'shutdown.
Commenced
cooldown leak rate has decreased
to 15.83 gpm.
2:00 a.m.
2:30 a.m.
2:45 a.m.
3:00 a.m.
Con'ditions are stable, no-off site release
Secured
from site alert and went to an unusual. event status
Resident inspector arrived at the site.
Leak rate 16.5 gpm.
4:00 a.m.
4:30 a.m.
6:00 a.m.
May 23,
1981
12:02 a.m.
Leak rate 11.83 gpm.
Radioactivity in the drywell is 2.26
X E-3 uc/cc.
Leak rate is 7 gpm and steady
Entered drywel.l and determined leak to be from packing on
valve 68-79,
B recirc pump discharge
valve
May 25,
1981
3:20 a.m.
Repairs to the
B recirc pump discharge valve are complete.
Commenced startup of the reactor.
May 26,
1981
4:10 a.m.
Reactor
has been returned to power operation
In the above areas
no violations or deviations were identified.
14.
TMI Action Items
The inspectors
conducted
a review 'of the
licensee
response
and action
on
five TMI Action Items which are listed below
a.
I.A.1.3(1)
b.
I.C.5
c.
I.C.6
d.
II.K.3(22a)
e.
II.E.4.2(6)
Shift Manning (Limit Overtime)
Feedback of Operating Experience
Verifying Correct. Performance of Operating
Activities
Final Recommendations
B and 0 Task Force
(Procedures
for RCIC Suction)
Containment Isolation Dependability
Licensee
conformance with the Action Item requirements
was evaluated
against
the criteria established
in NUREGs-0585,
0660
and 0737.
Status of imple-
mentation
was verified through review of procedures,
examination of records
and discussions with various members of the plant staff.
The overall
requirements
were
met or scheduled
to
be
met with some minor
exceptions
on items 14.a,
b,
and c.
On item 14.d, there
are
no plans for
automatic
switchover of RCIC suction
and justification for this conclusion
was
provided
by the licensee.
The procedures
for manual
switchover
were
determined to be adequate.
The licensee
interim action concerning
item 14.e has been to provide admini-.
strative
controls
over
the
containments
purge
valves.
Revisions
to
procedures
have
not permitted
purging into containment
except during cold
shutdown
and also the purge valves are
cautioned
tagged.
TVA has
recently
conducted
an operability analysis
and
has determined that the purge valves
are adequate
for closure against
DBA,
LOCA forces ther'efore modificaiton of
the
purge
valves is not necessary.
Purge
valve closure
times
are
being
reduced
and debris
screens
are being installed during the current refueling
outage
on
Browns Ferry
1.
This information along with TVA's analysis
was
sent to T. A. IppoLito, ORB,
NRR, dated June
2, 1981.
The inspectors
intend to do further fo'llowup of implementation of items 14.a
and
14.b
and will leave
these
open.
Items
14.c,
d and
e are
considered
closed.
N
r
10
e
Within the areas
inspected
no violations or deviations were identified.
15.
Refuel Floor Airborne Radioactivity
1
On May 22,
1981, during work in Unit
1 reactor cavity in connection with the
installation
of
new
spargers,
a
routine air
sample
showed
increased
airborne activity which leads to an evacuation of personnel
(about
33)
from the
refuel floor.
Personnel
in the
Reactor cavity were
in
a
plastic enclosure'(tent)
wearing respiratory protection
and were exposed
to
below
MPC of airborn activity.
Air samples
outside
the plastic enclosure
showed. an increase
in level which was the basis for a precautionary
clearing
of all
personnel
from the
refuel floor.
Personnel
not
in respiratory
protection
were exposed
to
a maximum of 14%
MPC for a short period of time.
Surveys of personnel
including nasal
smears
were negative.
The activity was
fairly localized with no increase
evident
on the continuous air monitors,
nor was there any evidence of release
from the refuel floor.
The inspector
discussed
improved work control
measures
with plant manage-
ment.
No violations
or deviations
were
identified within the
areas
inspected.
~,
J