ML17229A032
| ML17229A032 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/31/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17229A030 | List: |
| References | |
| 50-335-96-11, 50-389-96-11, NUDOCS 9609170377 | |
| Download: ML17229A032 (34) | |
See also: IR 05000335/1996011
Text
i
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-335,
50-389
License
Nos:
Report
No:
50-335/96-11,
50-389/96-11
Licensee:
Florida Power
5 Light Co.
Facility:
St. Lucie Nuclear Plant,
Units
1
5 2
Location:
9250 West Flagler Street
Miami,
FL 33102
Dates:
July
7 - August 3,
1996
Inspectors:
M. Miller, Senior Resident
Inspector
J.
Munday, Resident
Inspector
P. Fillion, Reactor Inspector,
paragraph
E2.2
W. Bearden,
Reactor Inspector,
paragraph
M2.3
J. York, Reactor Inspector,
paragraph
El. 1
Approved by: K. Landis, Chief, Reactor
Projects
Branch
3
Division of Reactor Projects
9609i70377 96083i
ADOCK 05000335
6
EXECUTIVE SUMMARY
St.
Lucie Nuclear Plant, Units
1
8
2
NRC Inspection
Report 50-335/96-11,
50-389/96-11
This integrated
inspection
included aspects
of licensee
operations,
engineer-
ing, maintenance,
and plant support.
The report covers
a four week period of
resident
inspection.
~0erati ons
~
Unit
1 entered
reduced
inventory conditions
on July 9 and July 11.
Operations
exerted
appropriate controls during the evolutions.
Management
involvement in incorporating the movements of Hurricane
Bertha into the reduced
inventory plans
was noteworthy.
Reduced
inventory control continues to be
an operational
strength
at St. Lucie
(paragraph
01.2).
~
The licensee
was proactive
and responsible
in preparing for potential
impact from Hurricane Bertha
(paragraph
01.3).
~
An overspeed trip of the
Pump occurred during the
period
as
a result of operator error (paragraph
02. 1).
~
An event involving the isolation of charging
and letdown,
and
a minor
water
hammer event,
occurred.
The licensee's
root cause activities were
followed and were not complete at the
end of the inspection
period
(paragraph
02.2).
~
A gA audit was reviewed
and found to be thorough.
gA-identified
administrative errors resulted
in a non-cited violation (paragraph
07.1).
Maintenance
A review of Control
Element Assembly maintenance
indicated that the
licensee's
preventive maintenance
program
was adequate.
An increase
in
the amount of predictive maintenance
was found to have contributed to
a
reduction in the
number of rod drop events
(paragraph
M2.3).
A Unit 2 charging
pump discharge
check valve stuck open during the
period, resulting in a bypass
flowpath from the charging
pumps to the
volume control tank and the declaration of a Notification of Unusual
Event.
The licensee's
root cause
determination
and corrective action
were reviewed
and found to be acceptable
(paragraph
M2. 1).
A walkdown of the Unit
1 containment building at normal operating
temperature
and pressure
(prior to the Unit
1 startup
from a refueling
outage)
was performed.
Post-outage
cleanliness
was found to be
excellent
(paragraph
M2.2).
A review of freeze seals
applied during the Unit
1 outage identified one
instance
in which a freeze
seal
had
been left unattended
while an area
cleanup
was performed, resulting in a non-cited violation (paragraph
H3.1) .
En ineerin
An issue involving the prelubrication of valves prior to surveillance
testing,
which was identified in 1995,
was resolved.
The practice,
which had
been explicitly required in a procedure,
was found to be in
violation of the
Code of Federal
Regulations
(paragraph
E2. 1).
A review of engineering activities surrounding control element
assembly
reliability was conducted
and found to be satisfactory
(paragraph
E2.3).
Auxiliary Feedwater Actuation System setpoints
were found to be
nonconservative
due to an apparent failure to incorporate as-built
dimensiors
in a calibration calculation.
The issue
was designated
an
Unresolved
Item pending conclusion of the licensee's
root cause
investigation
(paragraph
E2.3).
The licensee
entered
due to the miswiring
of three channels of linear nuclear instrumentation
during the Unit
1
outage.
The miswiring error involved reversing
inputs from the upper
and lower detectors for the three channels,
which adversely affected
axial
shape
index values.
The issue will be tracked
as
an Unresolved
Item pending completion of inspection activities for this event
(paragraph
E2.4)
The licensee's
engineering
and the
gA organizations
performed thorough
inspections
and assessments
of the tube plugging process
that resulted
in a finding, recommendations,
and concerns.
Resolution of the issues
was satisfactory
(paragraph
E2.4).
Re ort Oetails
Summar
of Pl-nt Status
Unit
1 entered
the inspection period in Node
5 during
a refueling outage.
The
unit was taken critical on July 23 and entered
Node
1 on July 25.
Full power
conditions were achieved
on July. 29.
Unit 2 entered
the inspection period at full power and operated
at essentially
full power throughout.
I. 0 erations
01
Conduct of Operations
Ol. 1
General
Comments
71707
Using Inspection
Procedure
71707,
the inspectors
conducted
frequent
reviews of ongoing plant operations.
In general,
the conduct of opera-
tions
was professional
and safety-conscious;
specific events
and
noteworthy observations
are detailed
in the sections
below.
01.2
Reduced
Inventor
0 erations
71707
a ~
b.
Scope
On July 9, at 3:30 a.m., Unit
1 entered
reduced
inventory to inspect for
the existence of a tube plug in
1B (reviews
had indicated that this
plug may have
been left out following in-situ pressure testing).
The
RCS level
was restored
to normal level at ll:16 on July 10.
While the
RCS was at
a reduced
inventory,
a number of controls
and procedures
were
implemented to ensure
the safety of the unit.
Two procedures
implemented
were:
AP 0010145,
Rev 10,
"Shutdown Cooling Controls"
and
1-0410022,
Rev 27,
"Shutdown Cooling", Appendix A, "Instructions for
Operations
at Reduced
Inventory or Mid-loop Conditions."
Findings
The inspector
reviewed the following items during this evolution:
~
Containment
Closure Capability - The equipment
hatch
was closed
during the evolution.
The inspector
reviewed the penetrations
which remained
open
and verified that closure capability was
available.
~
RCS Temperature
Indication - Two
SPDS channels,
containing
multiple CET indications,
were available.
~
RCS Level Indication - Independent
RCS wide and narrow range level
instruments,
which indicated in the control
room, were operable.
An additional
Tygon tube loop level indicator was installed in the
containment
and
was visible to a dedicated
operator in the control
room via
a television monitor.
~
RCS Level Perturbations
- When
RCS level reduction
was initiated,
additional operational
controls were invoked.
Plant staff were
advised of the reduction in
RCS level
and Operations
took action
to ensure that maintenance
would not perform work that might
effect
RCS level or shut
down cooling.
~
RCS Inventory Volume Addition Capability - One
pump
and
one
charging
pump were available for inventory addition,
as were two
trains of shutdown cooling.
~
RCS Nozzle
Dams - The
RCS nozzle
dams
were not installed at the
time.
~
Vital Electrical
Bus Availability - Operations
did not release
busses
or alternate
power sources for work while the unit was in a
reduced
inventory.
Both
EDGs were available.
~
Pressurizer
Vent Path
- The manway atop the pressurizer
was
removed to provide
a vent path
and Operations verified that the
manway
was unobstructed
'every four hours.
Given the fact that Hurricane Bertha
was moving through the Carribean
during the evolution, the licensee's
evaluations prior to initiating
reduced
inventory evolutions involved basing actions
times
on projected
hurricane landfall predictions.
Schedules
prepared for the evolution
allowed for approximately
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of margin between
the time projected
for exiting reduced
inventory conditions
and worst-case
projected
landfall.
The inspector considered
the licensee's
scheduling for this
evolution to show good safety consciousness.
The Unit was again taken to reduced
inventory conditions
on July ll,
after it was clear that Hurricane Bertha
was not going to affect the
local area.
The purpose of this evolution was to inspect
two tubes in
the lA SG for the existence of tube stabilizers
which post-outage
reviews indicated
had
been left out following outage work.
The
inspector verified that the items
above
remained
in affect for this
second evolution.
Reduced
inventory conditions
were exited
on July 12.
Conclusions
Operations
exerted appropriate
controls while the
RCS was in reduced
inventory.
Hanagement
involvement in establishing
schedules
which
properly factored Hurricane Bertha into the initiation of reduced
inventory activities
showed
good safety consciousness.
Reduced
inventory controls continue to be
an Operations
strength at St. Lucie.
01.3
a 0
b.
C.
Hurricane Preparations
(71707)
Scope
During the week of July 8 through
12, Hurricane Bertha
was moving
through the Carribean with projected point of landfall ranging,
alternatively,
from southern to northern Florida.
During the period,
the inspectors'followed
the licensee's
preparations
for the storm.
Findings
While National
Weather Service projections
placed
low probabilities of
landfall near the site,
the licensee
began to perform selected
portions
of AP 0005753,
revision
18,
"Severe
Weather Preparations,"
throughout
the week.
Host activities involved long lead time evolutions
such
as
filling storage
tanks,
removing loose material
from outside
areas,
and
organizing storm crews.
By July 10, the licensee
had designated
personnel
to report to the site
at 8:00 p.m. that night and to remain through the storm.
The inspectors
performed
a walkdown of external
plant areas
and found conditions
generally satisfactory.
As conditions never actually materialized
which
would require entry into the subject
procedure
(Hurricane
Watch or
Hurricane Warning), the inspectors
found that the licensee
had
been
conservative
and
had exercised
good judgement in preparing early.
Conclusion
02
02.1
The inspectors
concluded that the licensee
had acted responsibly
and
conservatively
in the actions
taken to prepare
the plant for the
potential
impact from Hurricane Bertha.
Operational
Status of Facilities
and Equipment
2C Auxi1i ar
Pum
Overs
eed
71707
92902
'a ~
Scope
On July 16, the
Pump tripped
on electrical
following PM activities.
The system
had
been placed
under
clearance
to perform the
PM activities.
The clearance
isolated
the
turbine trip and throttle valve,
however the warmup bypass
valves were
left open.
This allowed
a short section of piping to pressurize
with
steam.
When the clearance
was lifted and 'the trip and throttle valve
was reopened
the residual
steam in the piping caused
the turbine to
increase
speed until it was exhausted
at which time it coasted to a
stop.
It was then restarted
and subsequently
tripped
on electrical
The inspector followed the licensee's
activities with regard
to. this event.
,
C.
Findings
The licensee initiated an In-House
Event Report
and preliminarily
concluded that the turbine was not allowed to remain idle
a sufficient
amount of time following the turbine roll when the clearance
was lifted.
A Condition Report
was initiated but had not been finalized at the
conclusion of this reporting period.
OP 2-070050 stated that
a minimum of three minutes
between turbine runs
was required to prevent
The reason for the idle time was to
allow entrapped
governor control oil to bleed out from under the main
speed piston within the Woodward governor.
Failure to observe
the three
minute period could cause
the turbine to overshoot to the overspeed trip
setpoint during
a subsequent
startup.
An alternate
method to bleed the oil was to lower the governor
speed
control
knob to its lowest
speed setting,
which would rapidly dump the
oil to its
own sump.
The inspector reviewed the procedure
being
used to
operate
the system
when the trip occurred,
OP 2-00700050,
revision 42,
Periodic Test,"
and concluded that adequate
guidance
was provided to prevent tr'ipping the turbine because
of this
condition.
In addition, the inspector
reviewed the licensee's
Offnormal
and
Emergency
Operating
procedures
and verified that adequate
guidance
existed for correcting this condition should the turbine trip and
need
to be immediately restarted.
The inspector questioned
the licensee
about system operability during
the period of time it takes the oil to drain back to the
sump.
The
concern
was that although the period of inoperability was short, if
another Technical Specification
(TS) required
system
was also
another
TS action statement
might apply and
go unnoticed.
The Operations
Manager agreed
and stated that the turbine driven
pumps would be logged out of service following future periods of
operation.
Conclusion
The inspector
concluded that the licensee
had appropriately
addressed
this issue.
02.2
Unit
1 Char in
Letdown Issues
71707
a ~
Scope
On July 20, Unit
1 was in Mode
3 and work was being performed
by IKC to
adjust temperature
alarm setpoint for TIA-1111X and TIA-1121X to new
values
as
a result of higher expected
values of hot leg temperature
due
to increased
levels of SG tube plugging which took place during the Unit
1 refueling outage.
During the calibration,
on TE-
1121X to place
a resistance
decade
box across
the temperature
indication
circuitry.
The act of lifting the leads
created infinite resistance
from the subject
RTD, resulting in a maximum indicated temperature.
Unknown to
IKC at the time was the fact that the
RTD in question
was
providing
a temperature
input to
RRS channel
2, which employed the
temperature
input to develop
a programmed pressurizer
level.
With
maximum temperature
input to
RRS 2,
programmed pressurizer
level rose to
a full-power-equivalent
(66%) value.
Operators
noted the increase
and
directed
IKC to restore
the channel
to normal.
During this action,
the
two operating
charging
pumps
(8 and
C) stopped
operating.
Operators
secured
letdown
as
a result of the secured
charging
pumps.
The
inspector followed the licensee's
actions
in response
to this event.
Findings
CR 96-1792
was initiated following the event.
The inspector discussed
the issue of charging
pump operation with the engineers
assigned
to the
project.
The engineers
found that the charging
pumps
had stopped
operating
due to selector
switch misalignment
on the control panel.
The unit had three charging
pumps.
Normally one
pump was in operation
and the second
and third pumps were preselected
by selector switch for
backup operation.
By design, if pressurizer
level fell below -3% of
programmed level, the first backup
pump would start
(when level
was
restored
to
-1% of programmed level, the
pump would stop).
If level
continued to drop, the second
backup
pump would start
when pressurizer
level fell below
-4% of programmed level
(when level
was restored
to
-2%
of programmed level the
pump would stop).
Prior to the event,
the licensee
was operating the IB and
IC charging
pumps,
and the backup
pump selector
switch was selected
such that these
two pumps were designated
as backups.
When I&C's actions resulted
in an
increase
in pressurizer
level program,
the
pumps continued to run in a
backup
mode.
When program level returned to normal
(matching
approximately actual level) the two pumps stopped,
as would be expected
by design.
The inspector reviewed the appropriate
CWDs with the
licensee's
engineer
and concurred with this conclusion.
Following the event,
operators
attempted to restore
charging
and letdown
to service.
Upon initiating letdown,
a loud noise
was heard
by
personnel
in the area
on the regenerative
heat exchanger
in containment
and operators
noted that letdown automatically isolated.
Concurrently,
a regenerative
heat exchanger
high differential pressure
alarm was
received in the control
room.
The system design
included
an automatic
letdown isolation under
such conditions.
The licensee
concluded that
a
probable
waterhammer
event
had occurred
when letdown was restored.
The
licensee
performed
an engineering
walkdown of piping associated
with the
regenerative
heat exchanger
and determined that
no damage
had occurred.
An engineering
evaluation
was
commenced
to--determine
the susceptibility
of the system to such
an event.
At the close of the inspection period,
the evaluation
was not complete.
At. the end of the inspection period,
the subject
CR was still open.
The
adequacy of the licensee's
overall investigation will be reviewed
upon
closure of the
CR.
Accordingly, this will be tracked
as
an inspector
C.
follwup item (IFI 50-335/96-11-01,
"Adequacy of Root Cause
Investigation
for Unit
1 Charging
System Anomalies" ).
Conclusion
07
07.1
The inspector
concluded that the licensee's
determination of root cause
for observed
charging
pump performance
was satisfactory.
Issues
relating to the overall evaluation of the event will be covered in
subsequent
inspections.
equality Assur ance in Operations
A Audit Re ort Concernin
The
STAR PMAI Conversion
Process
40500
a
~
b.
Scope
In April, the Condition Report
(CR) process
superseded
the existing St.
Lucie Action Request
(STAR) process for documenting
adverse
conditions.
The licensee's
goal
was to have
a uniform Nuclear Division Condition
Report process
to document,
evaluate,
track,
and correct conditions of
concern to site personnel.
During the period of transition from STARs
to
CRs the licensee
used the newly developed
Plant Manager's
Action Item
(PMAI) tracking system to document
any outstanding
actions
associated
with STARs.
This tracking system
was
implemented
in January
and
was
designed
to track action items
on
a plant wide basis.
During this
inspection period,
the inspector
reviewed
gA audit report 96-05,
which
evaluated this conversion
process.
Findings
In general,
the audit found that
STARs whose actions
had
been
completed
were simply closed.
For STARs containing outstanding
actions,
PMAI's
were initiated to track those actions
and then the
STAR was closed.
The
audit identified three findings.
The first finding stated that the
PMAI
procedure
lacked
adequate
guidance
and
was
implemented without first
providing training for the affected personnel.
The licensee
stated that
the procedure
was being successfully
used at Turkey Point and
was simply
implemented without considering
the impact it would have
on personnel
at
St. Lucie who had
no working knowledge of the process.
The inspector
reviewed
AP 0006129, revision
1,
"PMAI Corrective Action Tracking
Program,"
and noted that,
since the finding, the procedure
had
been
revised to clarify points of confusion.
The second finding identified that the Corrective Actions department
was
closing
STARs without first receiving concurrence
from the initiating
department
when required.
The Corrective Actions department
head
admitted that this had occurred
but stated that
an independent
review
was substituted for the originator's concurrence,
which was the method
used
by the
new
CR process.
He stated that
he
had submitted
a procedure
revision requesting that this requirement
be deleted.
However, the
procedure revision
was not approved
by gA and the Corrective Actions
group
was not made
aware that the revision
had
been denied.
As a
result,
the originator's concurrence
was not obtained in all cases
as
required
by 91 16-PR/PSL-2,
Rev.
4, "St. Lucie Action Report
(STAR)
Program,"
step 5.6. 1.B.
The licensee's
corrective action included
discussing
procedural
compliance
requirements
with the involved
individuals.
In addition, the Corrective Action group
has
been put on
distribution for the procedures
they normally use.
The inspector
concluded that the licensee's
failure to obtain the originator's
signature constituted
a violation of the licensee's
procedure.
However,
the inspector
noted that the issue
was administrative
in error,
appeared
to be limited in scope
and impact,
and did not impact the actual
disposition of the issues
described
in the affected
Therefore,
this licensee identified and corrected violation is being treated
as
a
Non-Cited Violation, consistent
with Section VII.B.1 of the
NRC
Enforcement
Policy
(NCV 335,389/96-11-02,
"Failure to Obtain
Originator's
Concurrence
During STAR Closeout" ).
The inspector
reviewed approximately seventy-five
STARs which had
been
converted to the
CR/PHAI process
and noted the
same deficiency
identified by gA.
In addition, the inspector
noted several
STARs for
which final approval
by the Plant General
Manager
(PGM) was provided
by
someone
other than the
PGM.
STARs 960355,
940428,
and
960459 were
identified as requiring
PGH approval prior to being closed;
however,
the
PGH blank was signed
by a member of the Corrective Actions group not
having
PGM signature authority.
The
STARs were closed with the
outstanding
actions
being transferred
to the
PMAI process.
In addition
the inspector
noted that the majority of the
STARs which didn't require
PGH concurrence
had
been
signed
by someone without his authority.
The
Corrective Actions group
head stated that this was not an attempt to
circumvent
PGM concurrence,
but rather to simply transfer documentation
and closeout to the
new process.
It would appear that the unauthorized
signatures
were simply a result of closing out
a large quantity of
documents
over
a short period of time.
Although not
a violation of
procedural
requirements
the inspectors felt this action
was not prudent.
This issue
was discussed
with the
PGH who stated that it did not meet
his expectations
either.
He stated that
he would discuss this with the
personnel
involved.
The inspectors
considered this course .of action to
be appropriate.
The third finding noted that near term corrective actions
associated
with three
STARs had the due dates
extended
when converted to PHAIs.
The issues
surrounding
the three
STARs were evaluated
and dispositioned
upon identification.
Additionally, in response
to this finding, the
affected
group reviewed approximately
20% of the nonconforming
STARs for
closeout
adequacy
and found no discrepancies.
Conclusion
The inspector
concluded that the
gA audit was thorough
and contained
findings of substance.
The responses
to the findings by the affected
organizations
adequately
addressed
the concerns.
One poor practice with
regard to the delegation of signature authority was identified.
II. Haintenance
maintenance
and Material Condition of Facilities
and Equipment
2C Char in
Pum
Dischar
e Check Valve Failure
62703
93702
71750
Scope
On July 13, while swapping charging
pumps to perform maintenance,
control
room operators
received
N-14, charging
pumps flow
low, and
upon observing charging flow decrease
to 0 gpm, isolated the
charging
and letdown flow paths.
The inspector followed the licensee's
activities in response
to this event.
Findings
Prior to this occurring the
2C charging
pump had
been
placed in service
so that the
2B pump could
be secured for lube oil addition.
Upon
completion of this activity, the
2B pump was restarted
and the
2C
pump
was secured.
It was at that time that the low pump flow annunciator
alarmed
and the operator
observed
flow to be decreasing.
In an attempt
to recover flow, the operator started
the
2A charging
pump,
however
as
the flow continued to decrease
the operator isolated the charging
and
letdown flowpaths
and requested
the
SNPO investigate.
Initial reports
indicated
a considerable
leak coming from the
2B charging
pump packing.
The
pump was isolated
and the leak subsided.
The
2C charging
pump was
placed
back in service
and normal charging
and letdown operation
was
restored.
Because
the charging flow had decreased
to 0 gpm with two
pumps in service,
the licensee
assumed
the cause
was
due to the
2B pump
and subsequently
declared
an Unusual
Event in accordance
with plant procedures.
In addition,
a one hour emergency notification
was
made to the
NRC in accordance
with 10 CFR 50.72(a)(1)(i).
Subsequent
investigation determined that the packing leak was not as
large
as originally thought
and
was not the cause of the loss of flow.
The licensee
concluded that
when the
2C pump was secured
the discharge
V2167, stuck open.
Because
the
pump recirculation valve,
which is located
upstream of the check valve,
opens
when the
pump is
secured,
a flow path
was established
from the
2B pump backwards
through
the stuck open check valve
and recirculation valve for the
2C pump to
the volume control tank.
An engineering
evaluation
was performed to
determine
the approximate
packing leakage rate
and
a value of 4. 1
gpm
was calculated.
On August 1, the licensee retracted
the
one hour
notification.
The licensee initiated work order 96018092 to disassemble
and replace
the valve disc which the inspector witnessed
on July 17.
When the valve
was removed,
the disc was observed to be stuck open approximately
one-half inch.
After the disc was removed,
the internal
was noted
to. have
a casting void between
the discharge
port and the top of the
valve bore approximately
1 - 1.5 inches wide.
The bore normally
measured
1.879 inches to 1.881
inches,
however,
in this void area the
bore was 1.887 inches.
A second
valve from the warehouse
was
disassembled
on July
18 and
was observed
to contain machining marks
on
the circumference of the valve bore in the
same location.
The licensee
subsequently
disassembled
a total of 35 check valves from the warehouse
and noted machining/casting
flaws in 23.
In each valve inspected,
the bore
had
a rough surface
adjacent to the
outlet port of the valve spanning
an arc of approximately
60 degrees.
Although the cause of the roughness
was not conclusively determined it
appeared
to be
a result of the manufacturing
process.
Possible
causes
included mis-registration of the piston bore core during casting of the
valve body blank, mis-positioning of the blank, or mis-positioning of
the fixture used to hold the casting blank during machining.
These
valves were two inch stainless
steel
Anchor Darling piston check valves.
The findings were documented
in the
CR 96-1774.
Following discussions
between
the license,
and the
NRC, Anchor Darling
submitted
a letter to the
NRC stating that
a potential
condition existed
and stated that the concern
would be shared with their
customers.
The licensee identified other systems
in the plant where this model
valve was located
and assessed
each application for operability.
The
valves were located in the HPSI,
AFW and
IA systems
on Unit
1 and the
CS,
LPSI,
HPSI,
IA, and
SA systems
on Unit 2.
The operability
assessments
were reviewed
and approved
by the Facility Review Group
(FRG).
A maintenance
schedule
was also developed for inspection
and
repair.
The inspectors
reviewed the licensee's
assessment
and after
conferring with the licensee,
Anchor-Darling,
and
NRR concluded that
actions
being taken
by the licensee
were appropriate.
While observing
Maintenance
personnel
disassemble
the V2167, the
inspector noted that the tools
and equipment
needed
to support the job
had
been laid out and arranged
on the floor.
This was discussed
with
the personnel
performing the task
who stated that this was to aid in
identification while performing the work and
was
a new management
initiative to improve job performance.
The inspector discussed
this
with the Haintenance
Hanager
who concurred
and stated that this practice
along with generally maintaining
a clean work area,
being prepared
to do
the work prior to starting, etc.,
would decrease
rework and ultimately
improve efficiency.
The inspector also discussed
this with the Health
Physics
supervisor
who stated that, with the efficiency increases,
overall
dose
expended
in maintenance
was expected
to drop.
The
inspector
concluded that these efforts were prudent
and that benefit
could
be attained
from them.
Conclusions
The licensee
reacted
properly to the subject
check valve failure.
Engineering evaluations
properly supported operability determinations.
10
RCS Walkdown
71707
Scope
On July 20, the inspector
accompanied
the licensee
on
NOP/NOT walkdowns
of the Unit
1 containment prior to return to service
from the Unit
1
outage.
Prior to the walkdown, the inspector
reviewed completed
procedure
OP 1-0120022,
revision 22, "Reactor Coolant
System
Leak Test,"
which reported
the results of the walkdowns performed at the beginning
of the outage,
and Technical
Department
Procedure
I-IPT-07, revision 3,
which described
the walkdowns to be performed.
Findings
With respect to the walkdowns conducted
at the beginning of the outage,
the inspector
noted that
a number of valve packing leaks
had
been
identified in the previous
walkdown and that
no pressurizer
nozzle leaks
were identified.
Personnel
performing the walkdowns documented
findings
in accordance
with the procedural
requirements
and documented
generated
as
a result of the findings appropriately.
With respect
to the post-outage
NOP/NOT walkdown, the inspector
attended
the pre-job briefing and found that topics,
including heat stress
limitations, required retest
inspections,
and tour path,
were covered
appropriately.
The inspector verified that the
had
been at
NOP for
at least
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />,
as required
by procedure.
The inspector followed
portions of the walkdowns
and found that the licensee's
personnel
diligently ensured
that required inspections
were performed.
No
leakage
was identified as
a result of the inspections.
During the walkdowns,
the inspector
performed
independent
observations
of the state of containment cleanliness,
inspecting for foreign
materials
which might impede satisfactory
post-LOCA recirculation.
Previous
NRC inspections
in this regard
had indicated that the licensee
had performed marginally in establishing
containment cleanliness.
Following the recent Unit 2 outage,
the
NRC identified that the
licensee's
efforts had resulted
in a better level of cleanliness.
During this most recent inspection,
the inspector
found that the
containment
had
been returned to an excellent state of post-outage
cleanliness,
indicating that the licensee
has continued to improve in
the effectiveness
of removing material
from containment.
Conclusions
The inspector
concluded that pre
and post-outage
NOP walkdowns of the
had
been
performed satisfactorily.
Additionally, the inspector
found that the post-outage
cleanliness
of the Unit
1 containment
was
excellent.
ll
H2.3
Rod Control
S stem Maintenance
62703
M2.3.1
H2,3,2
Scope of Review
The licensee
has experienced
a series of recent
CEA drop events
due to various Control
Element Drive Hechanism
and related control
and instrumentation failures.
The inspector
reviewed the
licensee's
maintenance
program for the
Rod Control
Systems
to
determine
adequacy of preventive
and corrective maintenance
activities performed
on the systems.
Due to significant
differences
in system design
between Unit I and Unit 2 each unit
Rod Control
System is assigned
to separate
System Supervisors
and
separate
maintenance
crews.
Additionally, the inspector
determined that the licensee
conducts
an extensive
preventive
maintenance
program
on these
systems.
Routine maintenance
includes periodic performance of CEA coil current traces, circuit
and coil insulation resistance
checks
and power supply breaker
testing.
Current Traces
H2.3.3
The licensee
performs routine coil current traces of each
CEDH.
These traces
are normally scheduled
concurrent with planned
motion.
Additionally current traces
are often performed for
individual
CEAs during troubleshooting activities.
In this case
an evaluation of the trace
can
be used
as
an aid in diagnosing
circuit or rod motion problems.
Coil current traces
represent
a
signature
record for actual
current loading
on each of the coils
throughout the complete withdrawal
or insertion
sequence
and serve
as the best available indication of CEDM and
CEDMCS performance.
Traces
are evaluated for indications of potential
CEDM and
problems
such
as
CEDH coil grounds or faulty CEDMCS components.
Evaluation of traces is performed
by one of the two system
supervisors.
Both personnel
have considerable
experience
in this
area
and demonstrated
good working knowledge of expected
current
traces
and system performance.
This information serves
as the
basis for licensee
decisions
in planning of troubleshooting
and
repairs during refueling outages.
The licensee
had previously
performed this testing in conjunction with scheduled
CEA motion
prior to and following each refueling outage.
However the
inspector
was informed that the licensee
had recently changed
their program to perform this testing every
90 days.
Circuit and Insulation Resistance
Checks
The licensee routinely performs circuit and insulation resistance
checks
on the
CEDHs.
These resistance
checks
are performed
from
the rod control cabinets
and provide the licensee
information
about the condition of the
CEDM coil stacks
and
CEDM cables.
12
Circuit Breaker Testing
The licensee
perforate
periodic testing of Rod Control
System
power
supply circuit breafers
to verify proper- operation
along with
correct overcurrent
and undervoltage
protection settings.
The
inspector determined that the licensee tests
25% of these circuit
breakers
each
outage.
Test Stand
The inspector
toured the licensee's
maintenance
training
facilities.
During this tour the inspector
observed
the
licensee's
CEDMCS test stand.
This test
stand is constructed
from
additional
Rod Control
System cabinets
and other components
procured for this purpose.
The test stand consists of a single
CEA coil stack with a modified/shortened
CEDH, power supply,
and
complete set of CEDMCS components
to allow moving the shortened
CEDM through the withdrawal
and insertion
sequences.
This
equipment is located outside the plant with other training
facilities and
was originally setup for training operations
and
maintenance
personnel.
However, it is also
used
by I&C
maintenance
personnel
as
an aid in troubleshooting
problems with
rod control components.
CEDHCS modules
suspected
of causing
problems
can
be removed
from the plant cabinets
and installed in
the test stand to determine
actual
source of the problem.
Corrective Maintenance
The inspector requested
that the licensee
provide
a list of all
corrective maintenance
performed
on the
Rod Control
Systems for
both units for the previous
two years.
The inspector
reviewed the
list and noted that the list included
a few WOs which specifically
addressed
dropped
CEAs,
some failure of CEAs to move, position
indication problems,
and various
component failures.
Additionally, numerous
WOs had
been
issued to correct problems
identified during predictive maintenance
(current traces
and
resistance
checks).
The inspector selected
several
completed
Work Orders
from this
list for review.
The Work Orders
were reviewed to determine the
adequacy of the licensee's
corrective maintenance,
and if the
maintenance
was successfully
performed within required Technical
Specification
allowed time limits.
Additionally the work
documents
were reviewed to determine if the licensee identified
any adverse
equipment
performance
trends for the
Rod Control
System
and initiated appropriate
actions to assess
the cause of
the trends.
The following WOs were reviewed:
~
This
WO was issued
by the licensee
on
February
22,
1996, to investigate
the cause of CEA No.
20
dropping while Unit I was operating at power.
During
troubleshooting
licensee
personnel
determined that
a Power
13
Switch
SCR for the
CEA upper gripper
had shorted
causing
a
blown fuse.
Since the shorted
SCR could not be replaced
within the time allowed by Technical Specifications
the unit
was shutdown
and the defective
SCR was replaced.
~
This
WO was issued
by the licensee
on March
1,
1996,
due to
apparent
rapid movement of CEA No.
1 on
Unit 1.
Operators
had noted indication of excessive
movement
between
129 and
133 inches with only slight
deflection of the control stick.
The
IEC technician
removed
the timer module
and lift power switch for CEA No.
1
and
tested
them on the test
bench.
The components
tested
as
acceptable.
The components
were reinstalled
and
a current
trace
performed during rod motion.
The current trace did
not
show any problems with the
However the
continued to indicate rapid motion between
129 and
133
inches.
The problem was subsequently
found to be
an
indication problem due to
a faulty position indication reed
switch rather than
a problem with actual
rod motion.
The
faulty reed switch was scheduled
to be replaced
during the
next outage.
The inspector verified that the reed switch
had subsequently
been replaced
under
PWO 3690.
~
This
WO was issued
by the licensee
on April
28,
1996,
due to problems with moving
CEA No.
1
on Unit 1.
This
CEA was experiencing unreliable rod motion with both
withdrawal
and insertion
commands.
The licensee
determined
that the timer, pulldown power switch,
and lift power switch
modules
were defective.
The modules
were replaced
and
functionally tested satisfactorily.
~
This.WO was issued
by the licensee
on May
13,
1996,
due to out of specification resistance
readings
on
the lower gripper coil and cable for CEA No.
2 on Unit 1.
During routine coil resistance
checks
the licensee
determined that the
CEA had higher than expected coil
resistance.
The licensee
cleaned
the pins
on both ends of
the
CEDH cable
and reterminated
the cable
and rechecked
the
resistance.
After cleaning the coil cable resistance
was
found to be acceptable.
~
This
WO was issued
by the licensee
on
February
16,
1995,
due to
CEA No.
79 not stepping
out
smoothly
on Unit 2.
Licensee
personnel
identified
a faulty
ACTM board associated
with the
CEA.
The
ACTH board
was
replaced
and
FLCEA rod testing performed including monitored
CEDM coil current traces while operations
withdrew and
inserted
the
CEA with satisfactory results.
This
WO was issued
by the licensee
on
November 25,
1995, to replace
a defective connector
socket
on Control Cabinet
2 on Unit 2.
The connector
socket
was
replaced
on December
4,
1995,
and satisfactorily tested
on
December
14,
1995.
~
This
WO was issued
by the licensee
on May
16,
1996, to investigate
and repair
a reported defect with
loss of phase for CEA No.
49 on Unit 2.
Licensee
personnel
removed various
CEDMCS Power Switch components for the
and tested
them in the test stand.
The licensee
determined
that the optical isolator board
had failed.
The board
was
replaced
and satisfactorily tested.
Vendor Bulletins
The inspector
reviewed the status of the licensee's
program for
evaluation
and implementation of vendor recommendations
related to
the Control
Rod Drive System.
As part of this review the
inspector
held discussions
with the St.
Lucie ABB-Combustion
Engineering Site Representative.
During these
discussions
the
inspector
was informed that vendor recommendations
are provided to
sites
through
a series of ABB-CE Technotes
and
ABB-CE
Infobulletins.
The inspector
reviewed the listing of all
Technotes
and Infobulletins issued
by ABB-CE since
1979
and
determined that only a few related to the Control
Rod Drive
System.
The inspector identified
a single item, Infobulletin 89-
02, which
described
a potentially significant problem related to
multiple dropped
CEAs at another site.
Infobulletin 89-02 was
issued to inform plants of a multiple
CEA drop/slip event that
had
occurred at Palo Verde Unit
1 on December
10,
1988.
Additionally
the Infobulletin recommended
that licensee
management
evaluate
the
potential for CEA slip or drop at their site due to
a single fault
intermittent ground of a
CEA stepping.
The
specific problem at Palo Verde had
been
due to
a break in
insulation in
a
CEDM lower lift coil electrical
lead which
permitted intermittent arcing between
the coil lead
and
an
adjacent nipple assembly
during
CEA stepping.
During
a subsequent
meeting with licensee
personnel
the inspector
was informed that ABB-CE vendor recommendations
were included
within the scope of the licensee's
Nuclear Experience
Review
program.
The inspector
requested
that licensee
personnel
provide
documentation
to demonstrate
satisfactory disposition of ABB-CE
Infobulletin 89-02.
The inspector
was provided
a documentation
package for this issue.
This documentation
package
was reviewed
by the inspector.
The inspector determined that the licensee
had
evaluated
the Palo Verde event
and determined that the issue
was
not applicable to St.
Lucie due to significant different designs
and operational
history.
This determination
was
based
on the
CEDMCS utilized at both St. Lucie units differing from the unique
design utilized at Palo Verde while neither unit at St.
Lucie has
the additional
lower lift coils.
Additionally Unit 2 had operated
through it's first fuel cycle with multiple grounded
CEDM coil
circuits due to faulty coil field cable design.
No multiple CEA
M2.3.8
M2.3.9
15
drops
were experienced.
The faulty CEDM coil field cables
were
subsequently
replaced.
The inspector determined that the licensee
had
an adequate
program for addressing
vendor recommendations
for
the Control
Rod Drive System.
Walkdown of System
Components
The inspector
performed
a walkdown of portions of the Saint Lucie
Rod Control
Systems.
Included in the walkdown were the Reactor
Trip Breakers,
CEDMCS power supplies,
and rod control cabinets for
Unit
1
and Unit 2.
No significant problems
were noted during this
tour and housekeeping
within cabinets
was acceptable.
Conclusions
The licensee's
preventive
maintenance
program for the
Rod Control
Systems
was adequate.
Corrective maintenance activities reviewed
by the inspector
were acceptable.
Additionally, the licensee's
decision to increase
the
amount of predictive maintenance
on these
systems
has contributed
toward
a reduction in the number of CEA
drop events
and less failures of system
components
during reactor
operation.
M3
Maintenance
Procedures
and Documentation
~
~
M3. 1
A lication of Freeze
Seals
62703
a
0
b.
Scope
The inspector
reviewed
GMP-10, revision 6, "Application Of Freeze
Seals,"
and several
work orders
completed during the recent Unit
1
refueling outage involving the
use of freeze seals,
Find'ings
The inspector
found that the procedure
contained
appropriate
guidance to
preclude
challenges
to the plant associated
with the use of freeze
seals.
Documentation
reviews of the following work orders
were
completed
as delineated
below.
All the packages
contained
the required
documentation
including implantation plans,
contingency plans,
inspection reports,
and temperature
monitoring logs.
Exceptions
are
as
noted below:
Work Order 96008441 installed
a freeze
seal
on
a six inch SI
system
The temperature
monitoring log had
been maintained
as
suggested
in the procedure;
however,
the inspector
noted two
periods of time on May 22 in which the readings
were not
documented.
In one case
a reading
suggested
to be taken every
twenty minutes
was not recorded
and in another
case
the reading
was taken every thirty minutes.
16
~
Work Order 96005107 installed
a freeze
seal
on another six inch SI
system
The temperature
monitoring log had
been maintained
as
suggested
in the procedure,
however,
the inspector
noted for a
period of one hour on May 22 that
no readings
were documented.
~
Work Order 96008029 installed
a freeze
seal
on
a twelve inch SI
system line.
~
Work Order 96005109 installed
a freeze
seal
on
a six inch SI
system
~
Work Order 96011512 installed
a freeze
seal
on
a 3/4 inch
instrumentation line.
The inspector discussed
the cases
involving readings
not logged with a
maintenance
supervisor
involved with freeze
seal
usage.
He stated that
recording the readings
every twenty minutes is
a guide
and not
a strict
procedural
requirement.
He further stated that the freeze
seals
were
never left unattended
and the readings
were probably not recorded
simply
because
the freeze
seal
attendant
forgot to do so.
Discussion with licensee
management
indicated that for a short period of
time, approximately
one hour,
work had
been
stopped to clean the area of
trash
and unnecessary
equipment.
Although the freeze
seal
personnel
were not located directly at the freeze
seal
they were in the area to
fulfillcontingency requirements, if necessary.
However, after further
discussion
with the Maintenance
Manager,
the inspector
concluded that,
although the freeze
seal
monitor was in -the area,
he was not actively
monitoring the seal
as evidenced
by the absence
of freeze
seal
temperature
data for the time in question.
This was
a violation of the
licensee's
procedure
which requires that at no time shall
a freeze
seal
be left unattended
for any reason until the system or component is
restored
or the Contingency
Plan is implemented.
However, this failure
constitutes
a violation of minor significance
and is being treated
as
a
Non-Cited Violation, consistent
with Section
IV of the
NRC Enforcement
Policy
(NCV 335/96-11-03,
"Failure To Properly Monitor Freeze
Seal" )
The inspector
reviewed the control
room logs
and noted that there were
no log entries
which would indicate that the freeze seals
were left
unattended.
In addition, the inspector verified that the thaw time of
each of these
seals
would have
been
on the order of two to three
hours
and therefore
concluded that the safety
impact
was minimal.
Conclusion
A review of freeze seals
applied during the recent Unit
1 outage
indicated that procedural
requirements
had not been
met in one case.
M8.1
17
Miscellaneous
Maintenance
Issues
(62703)
LER 389 96-001
"Manual Reactor Tri
Due to Hi
h Main Generator
Cold Gas
Tem erature"
a
~
b.
Scope
The subject
LER discussed,
in part,
anomalous
level indications in Unit
2
SGs following a unit trip.
The indications
were the result of
blockage
in the sensing lines to level transmitters for the
SGs.
As
part of their corrective actions,
the licensee
committed to performing
blowdowns of the Unit
1
SGs during the next outage of sufficient length.
Findings
The inspector
reviewed completed
01, prepared
to perform the
subject
blowdowns.
The
WO invoked procedure
I-IMP-09.07, which was
prepared
to direct the blowdown evolutions.
The inspector
found that
the blowdowns
had
been
performed consistent
with the licensee's
commitments.
C.
Conclusion
The licensee satisfied their commitments with respect
to blowing down
the Unit
1
SG level sensing lines.
III. En ineerin
El
E1.1
Conduct of Engineering
U date
Pro
ram
37550
a ~
Inspection
Scope
The inspectors
reviewed the adequacy of the licensee's
program for
reviewing their
UFSAR and evaluated
the corrective actions
taken for
these identified items.
b.
Observations
and Findings
As
a result of
a boron dilution event
on January
22,
1996, that resulted
in a violation/civil penalty,
the licensee
committed to several
long
term corrective actions.
One of these corrective actions
was to perform
a comprehensive
review of compliance with the
The purpose of
this review was to evaluate
the
UFSAR and to make the changes
identified.
At the time of the inspection
(July 22-26,
1996) the licensee
had
reviewed approximately
one third of the
Most of the review was
for Unit
1
UFSAR and
was in the text material
not for tables
and curves.
Approximately
170 findings
and
500 editorial errors
were identified in
this evaluation.
None of these findings were determined
to be
operability problems.
18
C.
The inspectors
reviewed the procedure
being used,
the experience
and
technical discipline of the reviewers,
some of the
UFSAR findings and
related corrective actions,
root causes/corrective
actions,
and process
improvement for future use/reviews
of the
On July 26,
1996,
the
licensee
had not made
a decision
on the extent
and details of the
remaining review for the
Conclusions
on Conduct of Engineering
The inspectors
did not identify any problems with the licensee's
review
of the first one third of the
E2
E2.1
Engineering
Support of Facilities
and Equipment
Prelubrication of Valves Prior to Testin
37551
92902
a
~
Scope
In August,
1995,
an
NRC inspector identified, through document
review,
that the Unit
1 containment
spray flow control valve,
1-FCV-07-1A,
was
being preconditioned prior to being tested.
Specifically, prior to the
performance of the surveillance
which verified proper stroke-time of the
valve, lubrication was applied to the valve stem.
Further inspection
identified that three other containment
spray valves were also
prelubricated, prior to being stroke-time tested.
As the inspectors
could not identify a clear violation resulting from
the practice of prelubrication at the time the practice
was identified,
a TIA was prepared
requesting
NRR to provide
an interpretation of the
code with respect
to the practice.
During the current inspection
period,
a response
was received
which stated that the practice
was in
violation of 10 CFR 50 Appendix B, Criterion XI requirements
that
testing
be performed
under suitable environmental
conditions
(the thrust
being that prelubrication altered
the environmental
conditions of the
test
such that the test could not assess
the ability of the valves to
perform their intended function).
b.
Findings
The licensee
had noted in a guality Assurance
(gA) assessment
that this
practice
was occurring;
however, it was not highlighted
as significant
nor was
a St.
Lucie Action Request
(STAR) written to document its
occurrence.
The
gA assessment
indicated that there did not appear to be
a correlation
between
frequency of lubrication
and test performance.
However,
when informed by the inspector that this practice could result
in not obtaining true as-found data
and would not provide reliable trend
information, the licensee
agreed
and revised the appropriate
procedures
to delete
the practice.
Violation 335/95-15-05
was issued
documenting
the fact that
a
STAR was not initiated as required
by plant procedures.
19
Corrective actions for this violation included documenting
the event in
STAR 951048
as well as revising the applicable
procedures
to remove the
practice of prelubricating other valves prior to surveillance testing.
In addition,
STAR 951063
was written to review other test
and
surveillance
procedures
to determine if similar conditions existed
elsewhere.
One additional
valve was identified that might be impacted
by this practice
and that problem was also corrected.
The licensee
stated,
in response
to
STAR 951063, that the
PMs which lubricated the
valves were performed
along with the stroke-time surveillance
because
the surveillance
was required
as
a
PMT following the
PM.
By scheduling
the
PM to be performed prior to the surveillance
the number of
surveillances
performed would be reduced.
The inspectors
reviewed stroke time testing data for the subject valves.
The reviews
examined the stroke times both before
and after the practice
of prelubrication
was initiated.
The inspectors
found that
no
identifiable change
in stroke times resulted
from the initiation of the
practice.
However, the inspectors
found that the failure of the
licensee's
procedure
change
review process
to identify the potential
impact of the change
(the addition of preconditioning)
indicated
a
weakness
in the process.
10 CFR 50, Appendix 8, Criterion XI, requires,
in part, that testing
required to demonstrate
that systems
and components will perform
satisfactorily in service shall
be performed
under suitable
environmental
conditions.
Prelubrication of valves prior to performing
stroke-time tests violates this requirement
and negates
the validity of
the test in assessing
the operational
readiness
of the valve,
and is
being identified as
VIO 335/96-11-04,
"Preconditioning of Valves Prior
to Surveillance".
Control
Element Drive Mechanisms
and Related
Control
and Instrumentation
Ins ection
Sco
e
37550
Due to the number of recent control element
assembly
(CEA) drop events
the inspector
reviewed these
and past events to determine if engineering
support to the system
was appropriate.
There were four CEA drop events
in 1996, three
on Unit
1 and
one
on Unit 2.
The
CEAs are
one of the
systems
which are
used to control core reactivity through insertion or
withdrawal of absorption
rods.
The scope of the inspection
was to
review the cause
determinations
and corrective actions for these
problems.
Historical information on dropped
CEA events
and system
upgrades
were reviewed.
Maintenance activities were also reviewed,
and
that portion of the inspection is covered in Section
M2.3.
Observations
and Findin
s
On Unit 1, the control
equipment for the control element drive
mechanisms
consisted
of discrete electronic
components.
On Unit 2, the
control equipment
was
a later version consisting of integrated circuits,
and
was referred to as the Advanced Control Timing Mechanism.
Unit 2
control equipment
incorporated
a feedback
(or checkback) circuit which
had the capability of blocking all movement signals if an error was
detected.
The
CEAs have
been operated
in manual
mode only.
20
Dropped
CEA events that occurred
between
the beginning of 1993
and the
time of this inspection
are
summarized
below.
DROPPED
CEA EVENTS JANUARY 1993
TO JULY 1996
Unit
CEA No.
Date
Cause
2
12
5/24/96
Unknown, suspect
bumped fuse.
1
1
3/4/96
Operator error, quick release
of bypass
switch.
47
20
63
2/23/96
Loose connection
in interconnecting
wiring.
2/22/96
Failed (i.e. shorted) silicon controlled
upper gripper
switch module causing
fuse to open.
11/1/93
Timer card not seated.
8/26/93
Unknown.
5/21/93
Ground faults at containment
coupled with failed circuit breaker.
Seven
CEAs dropped.
In all but two cases,
the root causes for the dropped
CEAs were
determined
and corrected.
In the two cases
where the root cause
was not
definitely established,
a momentary perturbation
in the timing sequence
was suspected,
and those
CEAs have operated correctly thereafter.
Review of statistics
on dropped
CEA events
and their causes
would
indicate that the Unit 2 system
has
been
more reliable than Unit 1.
Since at least
1990, with the exception of one
unknown cause,
the Unit 2
dropped
CEA events
were caused
by problems outside the boundary of the
control hardware.
The inspector
concluded that these
problems
would not
be expected
to recur in the future.
These facts support the licensee's
contention that the Unit 2
CEA System
has
been highly reliable.
However, this conclusion
based
on St.
Lucie specific data
was in
conflict with data obtained
from a broader
base.
Data gathered
by
Combustion
Engineering
on dropped
CEA events at all plants
where
CE was
the
NSSS supplier would indicate that the Unit 2 class of equipment
has
not been
as reliable
as the Unit
1 class
equipment.
The multiple dropped
CEA event
on Unit 2 in Nay 1993
was caused
by
insulation
breakdown of multiple conductors
at the containment
together with a failed
CEA circuit breaker.
The penetration
problem appeared
to be
an isolated
case.
The circuit breaker that
fai,led was
a four pole breaker.
The failure mode of the circuit breaker
was failure of two poles to open,
which resulted
in tripping of the
upstream
sub-group circuit breaker.
C.
21
Overall, the
known causes
of the dropped
CEA events listed in the above
table are all different.
Therefore,'he
data
does not indicate
any
negative
component
nor personnel
related trend.
The only modification implemented to upgrade
the reliability of the
System
has
been the changeout
of the
CEA 15
VDC power supplies with
power supplies built to
a stricter specification.
This modification has
been
completed
on Unit
1 during the current outage.
Also at Unit 1,
cables
which connect to the
CEAs themselves
(referred to as
head cables)
were replaced
during the current outage,
because
the prefabricated
connectors
were failing at
an increasing rate.
The licensee
has established
a team to analyze the
CEA System
reliability and propose
upgrades if warranted.
The team
had
a target
date of mid-September for issuance
of their report.
Conclusions
E2.3
The inspector
concluded that engineering
support
on
CEDHs
and related
controls
and instrumentation
was good.
AFAS Set pints
Found to be Nonconservative
37551
'cope
On July 18, Unit
1 operators
noticed that the
0 channel
level indicator
for SG
18 was indicating
3 to
4 per cent lower than the balance of SG
level channels.
CR 96-1768
was initiated to document the condition.
The inspector followed the licensee's
activities in response
to this
issue.
b.
Findings
In evaluating control
room observations,
engineering
personnel
determined that calibrations
performed
on the Unit
1
SG level
transmitters,
performed
as
a result of higher than expected
SG tube
plugging (which resulted
in different saturation
conditions in the
and
a subsequent
change
in
SG water density) during the ongoing
refueling outage
may have
used nonconservative
values for elevations
considered for the transmitters'eference
legs.
Specifically,
a
concern
arose that elevations for reference
leg taps
may have
been
used
in the development of calibration data,
as
opposed to as-built data
on
the elevations of the condensate
pots which provided the reference
columns for the transmitters
in question.
In parallel with the engineering activities
on the issue,
the licensee
proceeded
to modify the setpoints for AFAS actuation
from their existing
setpoints of 19.5 per cent to 24.5 per cent of narrow range.
PC/H 96-
119 was generated
to affect the setpoint
change with the goal of
ensuring that adequate
margin would exist between
the
new (24.5 per
cent) setpoints
and
any correction (resulting from the engineering
reviews being conducted)
to ensure that the
TS minimum allowable
22
setpoint of greater
than or equal to 18 per cent
was not violated.
With
the unit in Mode 3 at the time,
TS required that
a minimum of 3 AFAS
channels
be operable or that, for only 2 channels
that
one
channel
be tripped
and
one channel
be in bypass within one hour.
If
more thar, two channels
were inoperable,
TS required that the unit be
placed in Mode
4 per
The
new setpoints
were established
on
July 19.
After setpoints
had
been elevated,
the licensee
determined,
based
upon
the results of field inspections
of the as-built locations of condensate
pots, that nonconservative
errors existed
in the following level
channels:
~
1A
~
LT-9013C - . 1%
~
LT-9013D - . 8%
~
SG IB
~
LT 9023A
3.0%
~
LT-9023B -2.9%
~
LT-9023C -1.7%
c.
Conclusion
At the close of the inspection period, the licensee
was still
investigating the cause for the erroneous
calibration data.
As
additional, root cause-related,
information was required to determine
whether violations of NRC requirements
occurred, this issue will be
tracked
as
an unresolved
item (URI 50-335/95-11-05,
"Discrepancies
in
AFAS Calibration Data" ).
E2.4
Unit
1 Nuclear Instrumentation
Wirin
Errors
37551
a
~
Scope
On July 30, with Unit
1 at
100% power, the licensee identified
a
discrepancy
involving wiring errors in the safety,.related
linear NI
channels.
The errors resulted
in channels
A, C,
and
D reporting ASI
values
which were opposite of true values; that is,
an apparent wiring
error had reversed
upper
and lower detector
inputs to the NI drawers
such that ASI was misclculated.
The inspectors
followed the licensee's
activities relating to this event.
,
Findings
23
C.
At 1:00 p.m., Unit
1 operators
declared
the A, C,
and
D channels
OOS,
which placed the unit in TS 3.0.3
due to 3 of 4
RPS channels for THLP
and
LPD, which received
ASI inputs,
being inoperable
due to the
erroneous wiring.
The inspector
responded
to the control
room and found
that leads
were being reversed
on the
A and
C channels
in, an attempt to
restore
the channels
to operability.
Reactor
Engineering
support
was
available,
with new NI gain values
being calculated
in support of I8C as
the leads for the affected
channels
were properly aligned.
At 1:50 and
2:00 p.m.,
work was completed
on the
A and
C channels,
respectively,
and
operators
drove
CEAs into the core to verify proper ASI response.
The
inspector verified that proper channel
response
occurred,
and the
A and
C channels
were declared
at 2:00 p.m., leading to an exit from
The inspector
found that
I&C and Reactor
Engineering
response
was timely in preventing
a unit shutdown.
The apparent
root cause for the wiring errors
was errors in
CWDs
prepared for the Unit
1 NI upgrade.
The affected
CWDs conflicted with
the
VTH for the NI drawers
being installed, resulting in wiring errors.
The licensee's
root cause
investigation
was proceeding
at the close of
the inspection period,
as
was the inspectors'eview
of the event.
As
more information on root cause
was required to properly assess
the
failures leading to this event,
the continued inspection efforts will be
tracked
as
an 'unresolved
item (URI 335/96-11-06,
"Unit
1 NI Wiring
Errors" ).
Conclusion
Operators
properly characterized
the effects of the subject wiring
errors
on system operability.
I8C and Reactor Engineering
support in
preventing
a unit shutdown
was timely.
The root causes
of the event
will be tracked
as
an unresolved
item.
E7
E7.1
guality Assurance
in Engineering Activities
ualit
Assurance
in
En ineerin
Activities
37551
a
~
b.
Inspection
Scope
A review was performed
on the failure to replug
one of the steam
generator
tubes
and the failure of the vendor's quality group to detect
this problem.
Observations
and Findings
The licensee's
final review of the Unit
1
tube
plugging documentation
(on July 7,
1996)
by the Components/Supports
Inspection
Group
(CSI) identified that the vendor
had failed to replug
a
tube in the hot leg.
Additional discrepancies
were found by the vendor,
e.g.,
two stakes
used for whip restraints
were not installed.
The
licensee
gA group found two installed stakes that were not required.
C.
E8
E8.1
24
The licensee's
gA Independent
Technical
Review Group
( ITR) initiated
an
assessment
of the discrepancies,
The inspectors
reviewed the
preliminary results of this assessment
and considered it to be very
thorough.
A finding was issued
in licensee
surveillance
number
08.06.CEPSG.96.7
for failure to follow procedure with four examples,
e.g., failure to plug tube, failure to adequately transfer staking
information, etc.
Also, four recommendations
addressing
opportunities
for improvement
and concerns
identified during the
ITR Groups
independent
technical
reviews were issued.
The finding will have to be
answered
by the tube plugging vendor
and
some of the recommendations
and
concerns will be addressed
by some of the license'e
groups.
Conclusions
on guality Assurance
in Engineering Activities
The licensee's
CSI engineering
group
and the
gA ITR group performed
thorough inspections
and assessments
of the tube plugging process
that
resulted
in
a finding, recommendations,
and concerns.
The vendor
completed
the required work as
a result of the actions
by the licensee
groups.
Hiscellaneous
Engineering
Issues
(37551)
LER 50-389-95-005
"2A Emer enc
Diesel
Generator
Rela
Socket Failures
Due to Hi
h
C cle Fati
ue"
The subject
LER documented
the failure of the
2A
EDG to start locally
and
a subsequent
failure to operate
properly due to solder cracks
and
connection failures associated
with relay sockets.
Critical Unit 2
sockets
were replaced
at the time,
and
a commitment
was
made to replace
similarly susceptible
sockets
on Unit
1 during the next Unit
1 outage.
The inspector
reviewed
PC/N 030-196M, revision 0,
"EDG Relay
and
Mounting Socket
Replacement,"
which was executed
during the current Unit
1 outage.
Under the
PC/N, existing Curtis
RS-11 relay sockets/mounting
tracks
and Square
D KPD-13 relays
were replaced with new components.
The activities were affected
under
PWOs 96009958
01
and
96009957
01
and
were completed
June
8 for the
B train
EDG and
Nay
21 for the
A train
EDG.
These activities satisfied
the licensee's
commitments
under the
subject
LER.
This
LER remains
open pending completion of the licensee's
corrective actions
stated
in the
LER.
E8.2
Shutdown Coolin
Relief Valve Set oint Chan
es
IR 95-20 documented
an event in which
a shutdown cooling discharge
relief valve lifted and failed to reseat,
resulting in an approximate
4000 gallon loss of RCS inventory.
The cause of the event
was
a
nonconservatively
low lift setpoint,
combined with an excessive
blowdown
setting which resulted
in an inability of the valve to reseat
once
lifted.
One corrective action in response
to VIO 335,389/95-20-01,
"Failure to
Promptly Correct Conditions Adverse to guality," involved establishing
25
new setpoints
for Unit
1 relief valves
V-3468 and V-3483 (the
suction reliefs) from the existing 320 psig setpoint to 330 psig.
The
changes
were affected
under
PC/H 014-196, revision 0,
Relief Valves V-3468 and
V3483 Set Pressure
Increase."
The inspector
reviewed the licensee's
completed
package
and found that the changes
were affected consistent with the licensee's
commitments.
V. Kana ement Neetin
s and Other Areas
Xl
Exit Heeting
Summary
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on August 6.
The
licensee
acknowledged
the findings presented.
The inspectors
asked
the licensee
whether
any materials
examined during
, the inspection
should
be considered
proprietary.
No proprietary
information was identified.
5
26
PARTIAL LIST OF
PERSONS
CONTACTED
Licensee
W. Bladow, Site guality Manager
H. Buchanan,
Health Physics Supervisor
C. Burton, Site Services
Manager
R.
Dawson,
Business
Manager
D. Denver, Site Engineering
Manager
R. Frechette,
Chemistry Supervisor
P. Fulford, Operations
Support
and Testing Supervisor
C. Harple, Operations
Supervisor
K. Heffelfinger, Protection Services
Supervisor
J. Holt, Information Services
Supervisor
H. Johnson,
Operations
Manager
T. Kreinberg,
Nuclear Material
Management
Superintendent
J.
Harchese,
Maintenance
Manager
C. O'Farrel,
P, actor Engineering Supervisor
R. Olson,
Instrument
and Control Maintenance
Supervisor
C. Pell,
Outage
Manager
J. Scarola,
St.
Lucie Plant General
Manager
A. Stall, Site Vice President
E.
Weinkam, Licensing Manager
C.
Wood,
System
and
Component
Engineering
Manager
W. White, Security Supervisor
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
chemistry/radiation,
and corporate
personnel.
IP 37550:
IP 37551:
IP 40500:
IP 62703:
IP 71707'P
71750:
IP 92902:
IP 93702:
~oened
27
INSPECTION
PROCEDURES
USED
Engineering
Onsite Engineering
Effectiveness of Licensee
Controls in Identifying, Resolving,
and
Preventing
Problems
Maintenance
Observations
Plant Operations
Plant Support Activities
Followup - Maintenance
Prompt Onsite
Response
to Events at Operating
Power Reactors
ITEMS OPENED,
CLOSED,
AND DISCUSSED
50-335/96-11-01
IFI
"Adequacy of Root Cause
Investigation for Unit
1
Charging
System Anomalies"
335,389/96-11-02
"Failure to Obtain Originator's Concurrence
During
STAR Closeout"
50-335/96-11-03
50-335/95-11-05
50-335/96-11-06
Closed
335/96-11-04
Discussed
389/96-001
50-389-95-005
"Failure To Properly Monitor Freeze
Seal"
"Discrepancies
in AFAS Calibration Data"
"Unit
1 NI Wiring Errors"
"Preconditioning of Valves Prior to Surveillance"
LER
"Manual Reactor Trip Due to High Main Generator
Cold
Gas Temperature"
LER
"2A Emergency
Diesel
Generator
Relay Socket Failures
Due to High Cycle Fatigue"
335,389/95-20-01
"Failure to Promptly Correct Conditions Adverse to
guality"
'
ACTH
ASI
CEDHCS
CFR
CR
CWD
FLCEA
FR
FRG
GMP
gpm
IFI
IR
ITR
LPD
LT
NI
NOT
OP
PC/H
PGM
PH
PHAI
PHT
Pslg
PSL
PWO
QI
28
LIST OF ACRONYHS USED
Automatic
CEA Timing Module
Auxiliary Feedwater Actuation System
(system)
Axial Shape
Index
Combustion
Engineering
(company)
Control
Element Assembly
Control
Element Drive Mechanism
Control
Element Drive Mechanism Control
System
Code of Federal
Regulations
Condition Report
Control Wiring Diagram
Demonstration
Power Reactor
(A type of operating license)
Emergency
Diesel
Generator
Flow Control Valve
Full Length Control
Element Assembly
Flow Recorder
Facility Review Group
General
Maintenance
Procedure
Gallon(s)
Per Minute (flow rate)
High Pressure
Safety Injection (system)
[NRC] Inspector
Followup Item
[NRC] Inspection
Report
Independent
Technical
Review Group
Loss of Coolant Accident
Local
Power Density
Low Pressure
Safety Injection (system)
Level Transmitter
NonCited Violation (of NRC requirements)
Nuclear Instrument
Normal Operating
Pressure
Normal Operating Temperature
Nuclear
Steam Supply System
Out Of Service
Operating
Procedure
Plant Change/Modification
Plant General
Manager
Preventive
Maintenance
Plant
Management Action Item
Post Maintenance
Test
Pounds
per square
inch (gage)
Plant St.
Lucie
Plant
Work Order
Quality Assurance
Quality Instruction
Reactor Protection
System
Reactor Regulating
System
Resistive
Temperature
Detector
SNPO
TMLP
TS
VDC
VTM
Shut
Down Cooling
Safety Injection (system)
Senior Nuclear Plant [unlicensed]
Operator
Safety
Parameter
Display System
Temperature
Element
Temperature
Indicator and Alarm
Thermal
Margin Local
Power
Technical Specification(s)
Updated Final Safety Analysis Report
[NRC] Unresolved
Item
Volts Direct Current
Violation (of NRC requirements)
Vendor Technical
Manual
Work Order