ML18029A779
| ML18029A779 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/01/1985 |
| From: | Brooks C, Cantrell F, Patterson C, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18029A776 | List: |
| References | |
| 50-259-85-36, 50-260-85-36, 50-260-895-36, 50-296-85-36, NUDOCS 8508130331 | |
| Download: ML18029A779 (30) | |
See also: IR 05000259/1985036
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.IN.
ATLANTA,GEORGIA 30323
Report Nos.:
50-259/8S-36,
50-260/85-36,
and 50-296/85-36
Licensee:
Valley Authority
SOOA Chestnut Street
Tower II
Chattanooga,
37401
Docket Nos.:
50-259,
S0-260,
and 50-296
License
Nos.
DPR-52,
and
Facility Name:
Browns Ferry 1, 2,
and
3
Inspection
Conducted:
June
21 - July 26;
1985
Inspectors:
G.
L.
Pau
, Senior
R si
nt
at
Signed
C. A.
Pa
erson,
Res
e
C.
R. Br
ks,
Reside t
D te Signed
P]
VS
D t
Signed
Approved by:
F.
S. Cantrell,
Section
C
f,
Division of Reactor
Proj cts
te Signed
SUMMARY
Scope:
This routine
inspection
involved
200 resident
inspector-hours
in the
areas
of operational
safety,
maintenance
observation,
reportable
occurrences,
program for control of measuring
and test
equipment,
surveillance
observation,
RPIP progress,
and organization
changes.
Results:
VIOLATIONS:
As
a result
of inspections
conducted
on
February 20-
March
1 (85-13)
and March 21-28,
1985, (85-20), violation ( 1) was identified.
For
administrative
purposes
this violation is
being
included
in
this
report.
(259/260/296/85-36-01).
( 1)
Technical Specification 6.3.A.
violation for failure
to
conduct
post
maintenance
testing
on
a control rod drive hydraulic unit and to perform
a
safety evaluation
on the High Pressure
Coolant Injection (HPCI) System
when
open
surge
suppression circuit resistors
were found.
8508130331
850807
pDR
hooch, 05000259
8
r,
(2).
10 CFR 50, Appendix B, Criterion
V violation for failure to have
HPCI torus
suction
valve
(73-27)
electrically
connected
in
accordance
with
drawings'3).
Technical Specification 6.3.A. for failure to have
an adequate
residual
heat
removal cross-tie
procedure
and to adhere
to high pressure fire protection
system valve lineups
(4)
Appendix
B, Criterion XII. for failure to adhere
to the program
for maintaining measuring
and test equipment.
DEVIATIONS: One deviation of FSAR section
10. 11.5. 1 for not maintaining portions
of the reactor building flood level switches
and seismically qualified.
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
J.
A. Coffey, Site Director
R.
L. Lewis, Plant Manager (Acting)
J.
E. Swindell, Superintendent
- Operations/Engineering
T.
D. Cosby,
Superintendent
Maintenance
(Acting)
J.
H. Rinne, Modifications Manager
J.
D. Carlson, guality Engineering
Supervisor
D.
C. Mims, Engineering
Group Supervisor
C.
G. Wages,
Mechanical
Maintenance
Supervisor
J.
C. Crowell, Electrical Maintenance
Supervisor (Acting)
R.
E. Burns,
Instrument Maintenance
Supervisor
A.
W. Sorrell, Health Physics
Supervis'or
R.
E. Jackson,
Chief Public Safety
T. L. Chinn, Senior Shift Manager
T.
F. Ziegler, Site Services
Manager
J .
R. Clark,
Chemical Unit Supervisor
B.
C. Morris, Plant Compliance Supervisor
A. L. Burnette, Assistant Operations'Group
Supervisor
R.
R. Smallwood, Assistant Operations
Group Supervisor
T.
W. Jordan,
Assistant Operations
Group Supervisor
S.
R. Maehr,
Planning/Scheduling
Supervisor
G.
R. Hall, Design Services
Manager
W.
C. Thomison,
Engineering
Section Supervisor
A. L. Clement,
Radwaste
Group Controller
Other
licensee
employees
contacted
included
licensed
reactor
operators,
auxiliary operators,
craftsmen,
technicians,
public safety officers, guality
Assurance,
Design
and engineering
personnel.
Exit Interview
(30703)
The inspection
scope
and findings were
summarized
on July 26,
1985 with the
Plant
Manager
and/or Assistant
Plant
Managers
and
other
members
of his
staff.
The licensee
acknowledged
the findings and took no exceptions.
The licensee
did not identify as proprietary
any of the materials
provided to or reviewed
by the inspectors
during this inspection.
Licensee Action on Previous
Enforcement Matters (92702)
a.
(Closed)
Deviation
(259,260,296/83-23-03)
Special
Test
High-Density
Fuel
Storage
System
Corrosion Surveillance
Program,
was
initiated October
26,
1983
and boral test
specimens
installed in unit
three
spent fuel pool
on October 25,
1983.
This item is closed.
b.
(Closed)
Open
Item (259,260,296/8Z-37-93)
- Contamination reports
have
been
revised
to include
the whole
body count date
and
number.
This
item is closed.
(Closed)
Violation.(260/81-18-05,
296/81-18-04)
The first example of
this violation was previously closed against unit one in Report 82-07.
A similar violation for failure to restore
fire protection
system
alignments after surveillance
(85-28-10) relates
to the
second
example.
For the third example,
similar problems
in the quality assurance
area
were noted in the Region II Inspection
Report
259/260/296/85-03
and
a
violation
was
issued
for "programmatic
breakdown
of the
program".
Future tracking in these
areas will be the recent violation.
This item
is closed.
d.
(Closed)
Unresolved
(296/85-25-07)
- Unit
3
High Pressure
Coolant
Injection (HPCI) System Motor Operated
Valve 73-27 timing discrepancy.
The inspectors
identified that the
HPCI valve 73-27 was noted to have
a
timing discrepancy
during
a review of the surveillance instruction,
4.5.E. 1.C., for stroke time testing.
The licensee
followed up on this
concern
and determined that the valve motor windings were miswired such
that the motor was operated
as s differential
compound
D.C. motor vice
a cumulative
compound
D.C.
motor
as
designed.
The licensee
=conducted
special
test
8508 to verify the valve would operate
adequately
under
stimulated
accident
conditions.
The
valve
operated
with
a
27
psig
differential pressure
across
the valve.
This item is closed
and will
be addressed
as
a violation of 10 CFR 40, Appendix
B, Criterion
V for
failure to
have
the valve electrically
connected
in accordance
with
TVA drawings
45N3711-3RA and 45N3711-5RA.
(296/85-36-02).
4.
Unresolved
Items* (92701)
Two unresolved
items
were identified during this inspection
period.
One
unresolved
item concerning
chemistry is identified in paragraph
eight.
The
second
unresolved
item is identified below.
The
licensee
discovered
on
June
28,
1985 that the
Standby
Gas
Treatment
(SBGT) charcoal
bed heaters
required resetting after operation of the
system.
The Vicensee
was previously unaware of this fact.
The charcoal
bed
temperature
is controlled at
125 degrees
F.
to prevent
condensation
while
the
system is idle.
The
licensee
has
placed
"Caution"
signs
at
the
SBGT control
boards
and
initiated
a change
request
to replace
the heater control switches with ones
that will automatically restart
the heaters.
"An Unresolved
Item is
a matter
about
which
more
information is required
to
determine
whether it is acceptable
or may involve
a violation or deviation.
On July 24,
1985,
the inspector questioned
how it was
known that the heaters
had been reset
and were operating
properly after
system
operation.
It was
learned
that
no
routine
log
readings
were
taken
for the
charcoal
bed
temperature
or otherwise
to verify system
operation.
It could
not
be
determined if the heaters
had
been previously reset.
Additionally, no tour
of the
SBGT room is made
on the operator
rounds
sheets.
A previous
problem
was identified on
a tour by the inspector
where the relative humidity heater
breaker
was found tripped.
( IE Report 85-15).
Discussions
with cognizant
maintenance
and
operations
personnel
revealed
there is
a general
lack of understanding
of how the
SBGT heater circuitry
works.
There is an additional
temperature
switch set at
150 degrees
F. for
the charcoal
bed which gives
an annunciation
in the control
room.
Once the
annunciation
is received
the temperature
switch must
be locally reset.
Train
C of SBGT has
an additional
safety switch set at 450 degrees
F. which
the other trains
do not have.
This
item will remain
unresolved
pending
a further
review of the
system
operation
and charcoal
bed history.
(259/260/296/85-36-03).
Operational
Safety
(71707,
71710)
The
inspectors
were
kept
informed on-a daily basis
of the overall plant."
status
and
any significant
safety
matters
related
to plant
operations.
Daily discu'ssions
were held each morning with plant
management
and various
members of the plant operating staff.
The inspectors
made frequent visits to the control
rooms
such that each
was
visited at least daily when
an inspector
was
on site.
Observations
included
instrument
readings,
setpoints
and
recordings;
status
of
operating
systems;
status
and
alignments
of emergency
standby
systems;
onsite
and
offsite emergency
power
sources
available for automatic operation;
purpose
of temporary
tags
on
equipment
controls
and
switches;
alarm
status;
adherence
to
procedures;
adherence
to limiting conditions
for
operations;
nuclear
instruments
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 their supervisors.
General
plant <ours 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;
containment
isolation
alignments;
instrument
readings;
housekeeping;
proper
power supply
and breaker;
alignments;
radiation
area
controls;
tag controls
on equipment;
work activities in progress;
radiation
protection
controls
adequate;
vital
area
controls;
personnel
search
and
escort;
and vehicle search
and escort.
Informal discussions
were held with
selected
plant
personnel
in their functional
areas
during
these
tours.
Weekly verifications of system status
which included major flow path valve
alignment,
instrument
alignment,
and
switch
position
alignments
were
performed
on
the
Containment
Atmospheric
Dilution
(CAD)
and
Standby
Gas
Treatment
(SBGT) systems.
A complete
walkdown
of the
accessible
portions
of the
system
was
conducted
to verify system operability.
Typical of the items
checked during
the
walkdown were:
lineup procedures
match plant drawings
and the as-built
configuration,
hangars
and
supports
housekeeping
adequate,
electrical
panel
interior conditions, calibration dates
appropriate,
system
instrumentation on-line, valve position ali'gnment correct,
valves
locked
as
appropriate
and
system indicators functioning properly.
During the
CAD system walkdown, the following discrepancies
were identified
and discussed
with lice~see
representatives:
1)
Host of the fasteners
for the electric
heater
enclosure
cover plate
were missing
on both
CAD trains.
2)
The "A" train electric heater controller was found TRIPPED.
3)
Valve 0-HCV-84-103
was
no longer installed
in the system.
This valve-
is
shown
on flow diagram 47W862-l.
Although an operator
had discovered
this condition
and
documented it on the
system
abnormal
status
data
sheet
on 10-29-83,
the licensee's
discrepancy
report
has just recently
been actively pursued.
4)
Both trains of the
CAD system
had sections of their piping covered with
ice apparently
from the
expansion
of liquid nitrogen
due to leaking
valves.
5)
Numerous valves were missing identification labels.
0-84-104,
0-84-562,
PCV-84-10
and 0-84-108).
FSAR Section
10. 11.5. 1,
Fire Protection
Systems
Seismic Analysis,
states
that failures of the non-seismically-designed
High Pressure
Raw Water Fire
Protection
System in the Reactor Building could allow raw water to enter the
building.
All such
failures
are
detected
by at least
two seismically
qualified meatus
such
as the initiation of the
Reactor
Building floor drain
system,
and the water level switches
six inches off the floor in the torus
area,
HPCI room
and
room.
An inspection
of the water level
switches
revealed
that
some
are
not seismically qualified.
The deficiencies
found
are listed below:
a.
Unit Three - Reactor
Core Isolation Coo'ling
Room Level Switch
(1)
The
top
mounting
plate
contains
only one of the four mounting
bolts.
,
(2)
The lower mounting plate contains
only two of the four mounting
bolts.
Unit Three
High Pressure
Coolant Injection
Room Level Switch
( 1)
The top mounting plate contains
only two of four mounting bolts.
One bolt is cocked
and
not fully inserted.
The plate is pulled
away from the wall one quarter of an inch.
(2)
The
lower mounting plate contains
only two of the four mounting
bolts.
The plate is pulled away from the wall and
one bolt is not
fully inserted.
Additionally, the inspector questioned
whether the level switches
were
routinely checked
for operability.
The switches
were not found to be
on any schedule
for a periodic functional test.
A functional test
was
performed
on all
three
units
and
the following instruments
did not
pass:
(1)
Unit One corner
room
residual
heat
removal
level
switch
(RHR)
LS-77-25C
(2)
Unit One corner
room
residual
heat
removal
level
switch
(RHR)
LS-77-25D
(3)
Unit Two corner
room - reactor
core isolation cooling level switch
- LS-77-25A
Unit one torus
level
switch was
found- to
be enclosed
in
a metal
box.
The inspector questioned
whether
the level
switch could still perform
its function.
The
licensee
conducted
an
evaluation
and
stated
the
switch was still operable.
The metal
box was installed to protect
the
switch while torus modifications
were
being
conducted.
The
box was
removed.
On July 24,
1985,
the inspector
was
informed that
a design
change
request
had
been initiated for specification of the
necessary
seismic
mounts.
The flood level
switches
were installed
per
a plant
drawing
which
specified,
"field to install".
Collectively,
these
deficiencies
were given as
a deviation in an exit meeting
on July 26,
1985 with plant
management
(259/260/296/85-36-04).
During
a routine
tour of the Unit one reactor building on June
17,
1985,
the inspector
observed water overflowing from
a drain
funnel
onto the floor of the
565 foot elevation.
Workers in the area
were performing
an annual fire
protection
system
surveillance
instruction,
SI-4. 11.A. l.a,
Simulated
Automatic
and
Manual
Actuation
of
High
Pressure
Fire
Pumps
and
Automatic
Valve Operability.
Simulated
operation
of deluge
valves
FCV-1-26-77
had just
occurred
when
the
flooding
occurred.
isolation valve 1-26-1082
was shut to stop the flooding.
The inspector
requested
an evaluation
of the
event
on June
17,
1985,
from the safety supervisor
and informed plant management
in a daily
NRC
meeting.
On June
25,
1985,
the inspector
was notified by the fire protection
engineer that
a one inch normally closed drain valve (26-77-SD)
on the
outlet of the deluge valve
had
been inadvertently left open in the past
which
resulted
in
the
flooding.
Also,
the
drain
line
was
not
completely
centered
over
the
drain
funnel
resulting
in
the
water
spillage
on the reactor building floor.
It was
not
known
how the drain valve (26-77-SD)
was misaligned to the
open
position prior to
performance
of the surveillance
instruction.
The valve is physically located
10 feet above
ground level.
This valve
is
checked
closed
during
a
monthly surveillance,
SI 4.11.D.1,
Fire
Protection
System
Inspection
(Monthly);
and
the
procedure
was
last
performed
on May 31,
1985.
Also, during the annual
surveillance after
testing
the
deluge
the drain -valve is
opened
to drain
the
piping
between
the deluge
valve
and
the outlet header
isolation valve.
The
valve
is
then
checked
closed.
The
annual
surveillance
was
last
performed
on June
12,
1984.
Independent
verification that
the drain
valve is closed
was not in either surveillance
procedure.
The inspector
expressed
the
concern
to plant
management
on June
25,
1985
that
there
might
be
other
system
valves
misaligned
and
the
significance of the
reduction
of available
flow through
the
deluge
valve
The fire protection engineer
stated that the drain valve being
open
was
estimated
to be equivalent to the addition of two to three additional
sprinkler
heads
to
the
system
but
no
formal
calculations
were
performed.
Also,
no additional
valve lineups
were
conducted
to check
for additional misaligned valves.
A review of Operating
Instruction
26 (High Pressure
Fire Protection
System)
revealed
that on'he
valve checklist,
valve
1-26-77-SD
is
required to
be in shut position.
This lineup was
shown
as current
on
May 16,
1985.
Plant
management
was
informed
in
an exit meeting
on
July 26,
1985,
this
was
a
second
example
of the violation against
T.S. 6.3.A. for failure to adhere
to plant fire protection
procedures
(259/85-36"05).
The
inspector
reviewed
the
licensee's
procedures
related
to
the
Residual
Heat
Removal
(RHR)
System cross-tie
feature
as
described
in
paragraphs
4.8.6.4
and F.7. 16 of the
FSAR.
The cross-ties
are provided
to maintain
long-term
reactor
core
and
primary
containment
cooling
capability irrespective of primary containment integrity or operability
of the
RHR system associated
with a given unit.
Suppression
pool water
which
has
been circulated
through the
RHR heat exchangers
on one unit
can
be
used
to
flood
the
reactor
core,
spray
the
drywell
and
suppression
chamber
or
return
to
the
suppression
chamber
of
the
adjacent
unit.
The
shared
feature
is designed
to provide continuing
core cooling in the
most degraded
state of the effected units
RHR and
Core Spray Systems,
namely, that of complete failure due to inundation
from tor'us,
torus
piping failure, or other causes.
The shared
system
is
normally valved off.
Valves
are
located
high
enough
to
insure
adequate
time
for
lineup
before
they
become
inundated.
Instrumentation
is provided to annunciate
a flooding condition to the
operators.
Operating
Instruction
74,
Residual
Heat
Removal
System,
addresses
the
cross-tie
function in Section
IV.F., cross
connecting
between
loops.
The procedure
specified
in this section
was
found to
be
unworkable.
The
pumps
are interlocked with their suction
valves
to prevent
damage
due to overheating
at no-flow.
The cross-tie
lineup specified
in OI-74
requires
the adjacent unit
pump suction
valves to
be closed
but does
not require bypassing
the suction valve inter lock in the
pump
start circuitry.
This cross-tie
procedure
is also limited for use
in
the containment
cooling mode only and does not'ddress
the reactor core
cooling
mode
discussed
in the
FSAR.
These
two problems
shall
be
identified
as
the first example
of
a violation for compliance with
T.S.6.3.A: (259/260/296/85-36-05).
1
The inspectors
also determined that the Reactor
Building Basement
flood
level
switches
(LS-77-25A,
B,
C,
D,
E
and
F)
are
not periodically
tested
to
assure
operability
and
that
the
response
procedure for these
instruments
contained
no reference
to the potential
for torus failure
and
the
need
to initiate
the
RHR cross-tie
valve
lineup
prior to
valve
inundation
from flooding.
Plant
personnel-
initiated
a maintenance
request to functionally test the level switches
and the annunciator
response
procedure
is to be revised.
The licensee
called
in
a
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report per
on July 19,
1985 regar ding the Containmant
Atmosphere Dilution (CAD) System.
While
investigating
the
cause
of the improperly installed pressure
switches
(PS-84-21
and PS-84-22)
the
licensee
discovered
that the flow element
orifices
and
were
not
in accordance
with the
original
system
design.
The
design
called
for orifices
sized
to
provide
a 20"
WC pressure
drop at
100
SCFM.
The installed orifices
were found to provide
a 20"
WC pressure
drop at 200
SCFM.
The licensee
additionally identified that
the
flow control
valves
( FCV-84-19
and
FCV-84-20)
to which
these
orifices
provide
flow sensing
input
are
over sized.
The ,combined effect of the as-found
discrepancies
is that
upon initiation of drywell/suppression
chamber
post-accident
venting
with the
CAD system,
a pressure
increase
in the
CAD system would occur
in excess of the
1 psig design
pressure
down-stream
of the orifice.
This condition would cause
the protective
pressure
switches
PS-84-21
~ and
PS-84-22
to isolate
the
CAD vent
valves
and
prevent
drywell/
suppression
chamber
venting.
The
licensee
was
unable
to determine
whether the error in buying the orifices
came
from the
purchasing
or
design
groups
but the
purchasing
contract
erroneously
specified
the
orifice was to provide
a 20"
WC pressure
drop at
200
SCFM.
The error
in buying
the
flow control
valves
was
suspected
to
be
due
to the
improper acceptance
of substitute
valves
by the
licensee
which were
provided
by the manufacturer.
The event
was considered
reportable
by
the licensee
since
the
CAD system
could
have failed to
perform its
~ l
intended
function
and
the plant
was considered
to be in an unanalyzed
condition.
6.
Maintenance
Observation
(62703)
Plant
maintenance
activities
of
selected
safety-related
systems
and
components
were
observed/reviewed
to ascertain
that they were conducted
in
accordance
with requirements.
The following items
were considered
during
this review:
the limiting conditions for operations
were
met; activities
were
accomplished
using
approved
procedures;
functional
testing
and/or
calibrations
were
performed
prior to
returning
components
or
system
to
service;
quality
control
records
were
maintained;
activities
were
accomplished
by qualified personnel;
parts
and materials
used
were properly
certified;
proper tagout clearance
procedures
were
adhered
to;
Technical
Specification
adherence;
and
radiological
controls
were
implemented
as
required.
Maintenance
requests
were
reviewed to determine
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
below listed maintenance activities during this report period:
a.
System
Instrument
Maintenance
Instruction
65 - Standby
Gas
Treatment
System Calibration
and Maintenance
b.
Electrical Maintenance
Instruction
90 - Reactor Building and
RHRSW pump
room flood level switches functional test
c.
Special
Operating
Instruction
12 - Jet
Pump
Instrumentation
Nozzle
Replacement
and Repair of Crack in Recirculation
Discharge
Piping
d.
Special
Mechanical
Maintenance
Instruction
20 - Repair of cracked
sensing
line from Penetration
N-28
e.
Mechanical
Maintenance
Instruction
107
TVA Test Procedure
for Target
Rock Valves Model 7567
F
The licensee
made
a one-hour report
on July
16,
1985 after declaring
loop
one of the residual
heat
removal
system
on unit three inoperable.
A snubber
(R-41)
was
found with the
rod disconnected
from the
cam
and
a restraint
(H-3)
had
twe- broken
causing
a one-half
inch
gap
at
the
break.
Vibration was suspected
as the cause of the fai lure.
An engineering
design
evaluation
was requested
by the plant to address
the vibration problem.
7.
Surveillance Testing Observation
(61726)
The
inspectors
observed
and/or
reviewed
the
below listed
surveillance
procedures.
The inspection
consisted
of
a
review of the
procedures
for
technical
adequacy,
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,
a review of test
data,
limiting condition
for
operation
met,
testing
accomplished
by
qualified personnel,
and that the surveillance
was completed at the requi red
frequency.
, a.
Surveillance
Instruction 4.2.B-26
Instrumentation
that initiates
or
controls the
CSCS Condensate
Low Level.
b.
Surveillance
Instruction 4.6.D - Main Steam Relief Valves
c.
Surveillance
Instruction
4.11.D - Fire Protection
System
Inspection
(Monthly)
d.
Surveillance
Instruction
4. 11.A. l.a - Simulated
Automatic
and
Manual
Actuation of High Pressure
Fire
Pumps
and Automatic Valve Operability
e.
Surveillance
Instruction
4. 10'. 1
Refueling
Interlocks
Functional
Test
No deviations or violations were identified in this section.
8.
Reportable
Occurrences
(90712,
92700)
The below listed licensee
events
reports
(LERs) were reviewed to determine-
if the
information
provided
met
NRC
requirements.
The
determination
included:
adequacy
of event description,
verification of compliance with
technical
specifications
and
regulatory
requirements,
corrective
action
taken,
existence
of potential
generic
problems,
reporting
requirements
satisfied,
and
the relative safety significance of each event.
Additional
in-plant reviews
and discussion
with plant personnel,
as appropriate,
were
conducted
for
those
reports
indicated
by
an
asterisk.
The
following
licensee
event reports
are closed:
LER No
"260/85-04
296/85-06
R1
Date
7-03-85
2-13-85
EVENT
Reactor
Water Chemistry-
Low pH
Unit 3 Reactor Water Level
Mismatch
"259/85-07
3-18-85
Unmonitored Stack
Gas
Release
0
The inspector's
review of LER 260/85-04 indicated that
a detailed
review of
the
low reactor water
pH incident was warranted.
The statement
in the
LER
indicating that
no corrective action
was planned
was found to be inaccurate
since
an ongoing evaluation
was still in progress.
The following inspector
10
concerns
were discussed
with licensee
representatives
and will be tracked
as
an unresolved
item (259/260/296/85-36-06)
pending resolution:
a.
No formal
procedure
exists for correcting
low pH coolant chemistry
or
additional
sampling
and analysis
requirements
for determination
of. the
cause.
b.
The action
level
assignments
in TI-38 provided insufficient margin to
allow corrective
action
of
degrading
chemistry
trends
prior
to
exceeding
technical
specification limits (only upon violation of the
technical
specification limit was the lowest action level triggered).
c.
Apparent
inadequacy
of sample flush volumes for the bottom drain
sample
location.
d.
Conflicting statements
in the event
memorandum
regarding the cause of
the
low
pH condition
(one
paragraph
indicates
than
an
RBCCW ingress
does
not match
the
observed
chemical
analysis
whereas
the conclusion
states
that
an ingress of
RBCCW is the most likely cause).
e.
The
possibility
that
repair
activities
caused
the
low
pH
condition.
f.
Lack of
a
formal
inspection
or -monitoring
program
to confirm the
suspected
leak in the
RWCU non-regenerative
heat exchanger.
g.
Lost
information
on
chemistry
trend
graphs
due
to off-scale
data
points.
h.
Loss of resin lot number traceabi lity due to incomplete demineralizer
data
sheets
(Log Sheet 754-1).
i.
The incident evaluation
failed to
address
the
source
of oxalate
(a
chemical
species
from degraded
resin)
which was found in a post event
sample.
j.
The
cause
for
the
month
long
downward
trend
in
pH
has
not
been
evaluated
(see
the attached
trend chart,
Attachment 1).
10.
Measuring
and Test Equipment
Program
(61724B)
The licensee's
program for control of measuring
and test
equipment
(MME)
was
inspected
to
assure
compliance
with Regulatory
Requirements,
TVA's
Topical
Report,
TVA-TR-75-1A, Quality Assurance
Program
Description
for
Design,
Construction
and Operations,
and
TVA's Nuclear Quality Assurance
Manual - Operations
(N-OQAM).
The
upper-tier
documents
were
found
to
be
general
in nature,
setting
requirements
and policies
which were
delegated
to the
various
sections
(Operations,
Mechanical
Maintenance,
Instrument
Maintenance,
Electrical
Maintenance
etc.) for detailed
implementation
through
section
instructions
and procedures.
As
a result,
each section's
program is different with some
sections
having
MKTE coordinators
and detailed
instructions with prepared
data
sheet
formats while other sections
lack
a coordinator
and pencil data
sheets
are prepared
as required.
This lack of consistency
presents
problems
in record
retrieval
and verification of adequate
program
implementation.
Accountability of the utilization of MKTE, which is necessary
for evaluating
the effect of an as-found out-of-tolerance
condition
on previously completed
work, is
a prime example of this concern.
All sections
maintain
some
form
of
use
log with the
exception
of the
mechanical
maintenance
small tool
repair
and
calibration
shop.
This
shop
uses
working
standards
for
calibration
and
calibration
checks
on
such
METE
as
micrometers,
dial
indicators
and torque
wrenches.
This oversight
shall
be identified
as
an
example
of
a violation for failure to carry
out the quality
assurance
program in accordance
with written instruction (259/260/296-85-36-07).
0
The
program for adjusting
the calibration
frequency
of
M&TE based
upon
experience
with the equipment
as required
by Section 3.2. 1 of the
N-OgAM is
implemented
in Browns Ferry Standard
Practice
17.5, Control of Measuring
and
Test Equipment.
BF-17.5 requires that when
an out-of-tolerance
condition is
discovered,
in addition to an investigation of all activities involving the
MME subsequent
to its previous acceptable
calibration,
an evaluation
shall
be
made to determine
the
need
to increase
the calibration
frequency.
Two
examples
of
a
breakdown
in this
program
were
discovered.
Oscilloscope
number
251425
was
found out-of-tolerance
on its last five annual calibra-
tion s
(11/5/80,
10/26/81,
10/19/82,
10/21/83
and
10/19/84) .
The
out-of-tolerance
investigation report for these
occurrences
either did not
address
the
calibration
interval
or
concluded
that
the
interval
was
adequate.
The last investigation
report stated
"past
performance
of this
instrument
has
been
good,
so there is
no need
to increase
the calibration
frequency
at
this
time."
Pressure
gage
number
E00895
was
found
out-of-tolerance
on
two consecutive
semi-annual
calibrations
(2/29/84
and
8/28/84) yet the 'out-of-tolerance
investigation
reports failed to address
the
adequacy
of the calibration interval.
This
breakdown
is
a
second
example
of
a
failure
to
carry
out
the
quality
assurance
program
(259/260/296/85-36"07).
11.
Organization
Changes
On July 19,
1985 the site director announced
the following management
change
effective July 22,
1985:
Robert
L.
Lewis wi 11
become
Acting Plant Manager.
Mr. Lewis has
been
with TVA 31 years.
He
has held
a Senior Reactor Operator license
and
formerly
was Assistant
Plant
Manager
at
Watts
Bar
Nuclear
Plant.
Following an 18-month period
as
an evaluation
team manager for INPO he
returned
to
TVA in
1985 to
become
a senior shift manager
at
Browns
Ferry.
George
T.
Jones
has
been
reassigned
as
an assistant
to the
Director of Nuclear Services
in Chattanooga.
0
12
John
R. Pittman,
Superintendent
of Maintenance,
has
been
reassigned
as
a -project
engineer
in
the
Instrument
and
Controls
Branch
in
Chattanooga.
Tom D. Cosby,
Supervisor of Electrical
Maintenance,
will
serve
as the Acting Superintendent
of Maintenance.
Robert
McKeon will become
Operations
Supervisor.
Mr.
McKeon comes to
he was
a Senior Plant Evaluator.
He previously was
, Manager of Operations
at Oyster Creek Nuclear Plant in New Jersey.
Ray
Hunkapi lier has
been
reassigned
as
a
senior shift
manager
on
the
7:00 a.m.
to
3:30
p.m. shift.
Mr.
Hunkapi lier's
reassignment
will
become effective August
19, 1985,'hen
Mr.
McKeon reports
to work at
Browns Ferry.
The site director gave the reasons
for the changes
as indicated below:
These
changes
provide
Browns Ferry with
a
new management
team in the most
critical
areas
of plant
operations
and
maintenance.
This action
is
an
integral
part of our efforts to strengthen
TVA's nuclear
program
and is
intended to bring performance
'at
Browns Ferry
up to the level
expected
by
TVA, NRC and the public.
12.
Regulatory
Performance
Improvement
Program
(RPIP)
The
responsible
Region II section chief reviewed
the status
of RPIP
and
'ctions
taken
by
TVA to
implement
specific
items
as
required
by
NRC
Confirmatory Order
EA 84-34 dated July 13,
1984.
TVA has assigned
a senior
manager
as
RPIP
Coordinator
at
the site.
His responsibilities
include
verifying that
each
task
has
been
implemented
as
described,
has
met
objectives,
and that the
necessary
programs
are
in place
to insure
that
objectives will continue to be met.
The status of RPIP
and action taken
by
TVA to
implement
specific
items
as
required
by
NRC Confirmatory
Order
EA 84-34
was
reviewed
during
a site visit July 10-12,
1985.
All of the
short
term items
and
most of the
long term
items
have
been
accepted
as
complete
by
TVA.
This
review
included
discussions
with responsible
personnel
and records of action taken to close the specific items.
Based
on
the above
review the following items are closed:
Short Term
Item Number
Descri tion
3.2
(84-SC"19)
Assign modification on
a project basis
Long Term
Item Number
5.1
(84-SC-70)
OgA review division and plant procedures
and
make
recommendation
for improvement
5.2
(84-SC-71)
Develop surveillance
and audit plant that
emphasizes
review of weak areas
0
n g!1
Vessel
Drain
RMCU
Out-of-service
.',9! j
I
.g,i I! ) g
Down
q
gN
Lt:~l
g
q
Li g
I
'
Vessel.
Flood-up
VII
'Y ~ w
~ ln-servic
I
Tech.
Spec. Limit Shutdown
(5.3)
I
I I
!
I
I
I
I
I
I
I
I I i I I
I '
I I
i
I
Q1
21 Apr
25 Apr
28 Apr
01 Hay
11 Hay
22 Hay
0
02 Jun
10 Jun