ML17228B530
| ML17228B530 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 06/07/1996 |
| From: | Chou R, Mark Miller, Sandin S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17228B528 | List: |
| References | |
| 50-335-96-06, 50-335-96-6, 50-389-96-06, 50-389-96-6, NUDOCS 9606210165 | |
| Download: ML17228B530 (63) | |
See also: IR 05000335/1996006
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-335,
50-389
License
Nos:
Report
No:
50-335/96-06,
50-389/96-06
Licensee:
Florida Power
& Light Co.
Facility:
St. Lucie Nuclear Plant, Units
1
8
2
Location:
9250 West Flagler Street
Hiami,
FL 33102
Dates:
March 31 - Hay
1 1,
1996
Inspectors:
H. Hiller, Senior Resident
Inspector
S. Sandin,
Resident
Inspector
=R. Chou,
Reactor Inspector,
paragraphs
H1.2, H2.2,
H2.3
J. Coley, Reactor Inspector,
paragraphs
Hl.3, Hl.4,
H3.1
D. Lanyi, Project Engineer,
paragraph
02. 1
Approved by: K. Landis, Chief, Reactor Projects
Branch
3
Division of Reactor Projects
9606210ib5
960607
ADOCK 05000335
6
EXECUTIVE SUMMARY
St. Lucie Nuclear Plant, Units
1
& 2
NRC Inspection
Report 50-335/96-06,
50-389/96-06
This integrated
inspection
included aspects
of licensee
operations,
engineer-
ing, maintenance,
and plant support.
The report covers
a six week period of
resident inspection.
0 erations
~
A condition of unidentified
RCS leakage
through the
CVCS system
was
appropriately identified and addressed
by operators;
however,
operators
were nonconservative
in declaring
an
NOUE (paragraph
01.2).
~
Operators
responded
properly
and in
a timely fashion in shutting
down
the Unit
2 turbine in response
to low auto stop oil pressure
following
testing
(paragraph
01.3)
~
A non-licensed
operator
showed
good attention to detail during
RAB tours
in identifying an uncompensated
breach
in a fire-rated wall (paragraph
01.4).
Operators
performed well during
a Unit
1 shutdown for refueling
(paragraph
01.5).
Operators
performed well during reduced
inventory operations of Unit
1
(paragraph
01.6).
ESF system
walkdowns identified weaknesses
in the accuracy of operations
procedures
(paragraph
02. 1, 03. 1).
~
Management
changes
resulted
in the naming of an interim operations
manager
(paragraph
06).
Maintenance
Observations
of valve repacking
and modifications indicated acceptable
maintenance
activities
(paragraph
M1.2).
~
Maintenance of pressurizer
code safety valves
was performed in
accordance
with approved
procedures
by knowledgeable
personnel
(paragraph
H1.3).
Inspectors
identified one case of maintenance
being performed without a
properly verified procedure
at the job site
(NCV 96-06-02,
paragraph
H1.4).
Integrated
safeguards
testing resulted
in
a failure of the
1B
EDG output
breaker to close.
Operator
and test personnel
performance
was excellent
(paragraph
M2. 1).
Reviews of polar crane
load tests
and observation of reactor vessel
head
lift indicated satisfactory
performance
(paragraph
H2.2).
a
~
Reviews of main steam safety valve testing indicated proper performance
of test activities
(paragraph
H2.3).
Preparations
for the inservice inspection of the Unit
1 reactor
vessel
were found to be in accordance
with applicable
requirements
and
showed
'ood
outage planning
(paragraph
N3. 1).
~E
4
~
Engineering
personnel
showed
poor attention to detail in the preparation
of an engineering
package
which resulted
in an uncompensated
breach of a
(NCV 96-06-01,
paragraph
01.4).
Engineering
support in response
to
a failed motor for HVS-4A precluded
a
TS required
shutdown
(paragraph
E2. 1).
~
A failure of engineering
personnel
to promptly document
a nonconforming
condition affecting approximately seventy
instruments
was identified
(NCV 96-06-03,
paragraph
E4. 1).
~
A number of findings relating to configuration control resulted
in an
unresolved
item (URI 96-04-05,
paragraph
E7. 1).
~
P missing orifice plate
was identified in the
ICW system during as-built
verification inspections
(NCV 96-06-04,
paragraph
E7. 1).
Multiple examples of UFSAR inaccuracy
were identified
(URI 96-04-09,
paragraph
XI) .
Plant
Su
ort
An audit of turbine building fire extinguishers
identified differences
between
the plant
and the
UFSAR (paragraph
F2).
An audit of fire brigade
member qualifications resulted
in
a violation
for failure to maintain current physicals
(VIO 96-06-05,
paragraph
F5).
Re ort Details
t
Summar
of Plant Status
Unit
1
Unit
1 entered
the inspection period at
100 percent
power and operated
at full
power until April 29,
when the unit was shut
down for refueling.
The unit
entered
Hode
6 on Hay 7.
At the close of the inspection period the unit was
preparing for defueling.
Unit 2
Unit 2 entered
the inspection period at
100 percent
power and operated
at full
power until April 9,
when power was reduced to 85 percent
due to through wall
leaks in circulating water system piping.
The unit was maintained at 85
percent while repairs
were affected.
Following repairs,
the unit achieved
full power on April 20; however, difficulties encountered
with turbine
testing
on April 20 necessitated
removal of the turbine from
service.
The unit was maintained in Hode
2 until April 21,
when the generator
was tied to the grid.
The unit was returned to full power on April 22 and
maintained full power through the
end of the inspection period.
I. 0 erations
Ol
Conduct of Operations
Ol. 1
General
Comments
71707
Using Inspection
Procedure
71707, the inspectors
conducted
frequent
reviews of ongoi'ng 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
Unit 2
RCS Leaka
e and Unusual
Event Declaration
40500
71707
93702
Description of Event
On Harch 31, Unit
1 experienced
RCS leakage
in excess of TS limits and
ultimately declared
an Unusual
Event.
The timeline of the 'event
was
as
follows:
10:38 a.m.
11:55 a.m.
12:00 p.m.
12:25 p.m.
Operators
placed the
2A purification ion exchanger
in
service after securing the deborating
ion exchanger.
During logtaking th
RCO noted that
VCT level
had dropped
3
percent
over the previous hour.
This decrease
equated to an
approximate
1.6 gpm loss of inventory.
Operators
entered
ONOP 2-0120031,
"Excessive
System
Leakage."
Charging
and letdown flows were verified
to be matched
and
no containment radiation or leakage
collection increases
were noted,
indicating that the leak
was outside containment.
NLOs were dispatched
to look for
leaks.
An
RCS inventory balance
was
commenced.
Operators
logged the existence of a 1.6
gpm indicated leak.
12:45 p.m.
12:55 p.m.
1:00 p.m.
2:30 p.m.
3:02 p.m.
Annunciator N-5,
"Letdown Pressure
Hi/Lo," wa's received,,
letdown flow was noted to increase
to approximately
84 gpm,
and indicated
VCT level
change
was noted to increase
in
step-wise
fashion to 29 gpm.
CVCS ion exchangers
were bypassed
(isolated
from system)
and
VCT level decrease
stopped.
Results of RCS inventory balance
indicated that
an average
leak rate of 7.43
gpm had existed over the previous hour.
An NOUE was declared
and t'erminated
as
a result of the
observed
leak rate.
NRC Operations
Center notified per
10
CFR 50.72(a)(1)(i) for
a declared
emergency.
Classification of Event
The inspectors
responded
to the site
and found the plant in a stable
condition.
Discussions
with the
NPS and
ANPS indicated that the
was declared after discussions
with plant management
following the
completion of RCS inventory balance.
The inspectors
reviewed
3100022E,
Rev 29, "Classification of Emergencies,"
Event/Class
1.A,
"Abnormal Primary Leak Rate."
Classification
as
an
NOUE required the
following conditions:
RCS water inventory balance
indicates:
a.
greater
than
1 gpm unidentified leakage.
b.
greater than
10 gpm identified leakage.
2.
Inspection reveals
any
RCS pressure
boundary leakage.
3.
Indication of leaking
RCS safety'or relief valve which causes
pressure
to drop below 1600 psia."
The inspectors verified that operators
had properly implemented
ONOP 2-
0120031,
"Excessive
Leakage,"
up to, but not
including, step 2.L.2, which required isolating
CVCS letdown.
Additionally, the inspectors verified that
an
NOUE was not required
during the event,
based
upon
a strict reading of the applicable
EAL.
Operators
stated that the
NOUE was not declared
when unidentified
leakage
was determined to exceed
1 gpm because
the rate
was not
determined
by inventory balance;
rather, it had
been derived from VCT
level indications over time.
Additionally, operators
stated that
some
confusion existed over whether the leakage constituted
RCS leakage,
as
the operators
had confidence that the leakage
was occurring outside of
containment
(as evidenced
by charging
and letdown flows being matched)'.
Finally, operators
stated that,
as the condition had arisen shortly
.
after placing the purification ion exchanger
in service,
they had
a
strong
sense that the leak was related to that evolution.
The licensee
stated that the ultimate decision to declare
the
NOUE was
based
upon the
results of the
RCS inventory balance
(7.43
gpm at 1:00 p.m.), but that
the declaration
was delayed
due to the cessation
of the indicated
leakage
when the
CVCS ion exchangers
were isolated at 12:55 p.m., which
called into question the need for a declaration.
Notwithstanding the
accuracy of the operators'ecision
with respect to procedural
requirements,
the inspectors
concluded that the lack of an
NOUE during
the event represented
a nonconservative
decision
on the part of
operators
in that:
Operators
had indication of an approximate
1.6
gpm leak at ll:55
a.m.
Discussions
with the
NPS indicated that
a reluctance to
declare
an
NOUE based
upon
VCT level indication existed,
due both
to the specific
EAL criteria referencing
an inventory balance
and
concern that the level instrument might have
been inaccurate.
However, the inspectors
noted tha't two level transmitters
were
available which reported
VCT level to the control
room.
While
sharing
a common reference leg, the existence of two instruments,
and the ability to perform a channel
check (which would have
shown
agreement
between the two transmitters),
could have provided
confidence in the observed level decrease.
~
Operators
logged the 1.6 gpm leak rate at 12:25 p.m.
and noted
that searches
for the leak were continuing
and that the leak was
persisting'.
At this point, the leakage
had
been identified for
approximately
one half hour, allowing for assessment
and decision-
making.
~
At 12:45 p.m., leakage
was noted to increase
to 29 gpm.. At this
point, the leakage
source
had still not been identified and the
condition had clearly degraded.
The licensee
investigated
the occurrence with respect to Emergency
Plan
execution
(documented
on
CR 96-483).
The inspectors
found the
licensee's
evaluation.to
be comprehensive
and noted that the licensee
concluded that operators
were slow to declare the
NOUE.
As a result of
the'licensee's
investigation,
corrective actions
were developed
which
included:
~
Developing
a better definition for what constituted
RCS leakage.
~
Evaluating the need for an
EAL interpretation
document.
~
Revising
EAL 1.A to require
an
results in an entry into the
AS for TS 3.4.6.2
(which specified
RCS leakage limits) and submitting
a revision to the
Emergency
Plan to remove the I gpm unidentified
RCS leak rate criteria
from'he
EAL in deference
to
NUHARC guidance,
which allows
up to
10 gpm
unidentified leakage prior to an
NOUE.
~
Revising the
RCS inventory balance
methodology to allow shorter
calculational
periods for determining
RCS leakage during off-
normal conditions.
Root Cause
Determination
As a result of this event,
the licensee
formed
an Event Response
Team to
determine root cause
and corrective actions.
The inspectors
followed
the activities of the team
as they proceeded.
The team employed
a
methodology which delineated all possible
sources
of inventory loss
and
which systematically eliminated possibilities for which adequate
bases
existed.
In general,
the inspector
found the licensee's
actions well-
founded;
however,
the inspector
found that the timeliness of the team's
actions suffered
from a lack of obtaining input from the operating
crew
after the event.
The
ANPS and
NPS both provided written statements
detailing the event before leaving the site the day of the event.
Other
crew members did not prepare
such statements,
and data which was
key to
determining the most likely root cause
(concerning valve position
and
manipulation)
was not obtained in a comprehensive
way until the third
de of the investigation.
The team was unable to conclusively determine
the root cause of the loss
of inventory event;
however,
a plausible root cause
was determined.
Through reviews of existing plant data,=- the team concluded that the loss
of inventory occurred through the lifting of CVCS relief valve V2520,
which provided overpressure
protection to the low pressure
portions of
the letdown line downstream of the pressure
control valves.
Inventory
balances
of lost
VCT level versus
Holdup Tank level (the destination for
water relieved through V2520) confirmed this valve as the most probable
point of inventory loss.
The licensee
subsequently
the
relief valve and found its leakage
and setpoint to be within acceptable
values.
Consequently,
the licensee
determined that the valve lifted, to
varying degrees,
as
a response
to actual
high pressure
conditions.
Following the event,
the licensee
performed valve lineup verifications
of the
CVCS system.
In so doing, the licensee identified that
V2382
(ion exchanger
downstream isolation)
was not fully open
(as required),
such that
a backpressure
could have developed
which would approach
the
V2520 lift setpoint of 200 psig.
The licensee
theorized that
a slight
mispositioning of the valve could have led to
a less than fully opening
of V2520 (which would account for the initial 1.6
gpm leak rate),
which
was then exacerbated
when valve lineup checks
(to identify the source of
the leakage
during the event) resulted
in an operator checking the valve
in a closed direction, further increasing
the backpressure
and exceeding
the relief valve's setpoint.
The licensee verified, through
a system
pressure test, that no additi'onal
leakage
path existed in the affected
portion of the system,
thus limiting the possible
leakage
paths to the
relief valve lift described
above.
As corrective action for the identified root cause,
the licensee
installed
a local pressure
gauge in the low pressure
portion of both
units'VCS letdown lines to aid operators
in diagnosing
system
performance.
Additionally, the licensee
enhanced
-procedural
guidance
on
verifying valve positions to include
an emphasis
on ensuring that valves
which are to be open are left in a full open position following a
position check.
Conclusion
In conclusion,
the inspectors
found the following with respe'ct to this
event:
Operators
showed
good attention to plant parameters
in identifying
the subject leak and took actions consistent with ONOPs in
addressing it.
The failure to declare
an
NOUE while the subject leak was active
was considered
a nonconservative
decision
on the part of
operators;
however,
operators
were in strict compliance with EPIP
EALs.
The licensee's
investigations of both the decision making behind
operators'mplementation
of the
Emergency
Plan
and the root
causes
of the leakage
were comprehensive
and sound.
The timeliness of the Event Response
Team's efforts in determining
root cause
was
hampered
by a failure to debrief the entire
operating trew following the event.
01.3
Unit 2 Down ower
71707
93702
On April 20, Unit 2 operators
were performing testing of the turbine
overspeed trip function.
The licensee's
procedure for performing this
evolution required that the Overspeed
Test Handle
on the turbine front
standard
be held in the
"TEST" position during the test.
With the
Test Handle in "TEST," auto-stop oil pressure
was
hydraulically prevented
from decreasing
to
a point that would result in
a turbine trip when
a mechanical
overspeed trip was induced
as
a part of
the test.
Following a satisfactory test of the mechanical
overspeed trip function,
operators
were required to verify that,
upon placing the Overspeed Trip
Lever in "Reset," auto-stop oil pressure
returned to greater
than
90
psig;
however,
upon taking the specified action,
operators
noted that
pressure
returned to only 76-80 psig.
The evolution was repeated
several
times with the
same result.
Operators
maintained
the position
of the Overspeed
Test Lever in "TEST," and
a unit downpower
commenced
at
3:55 p.m. with the goal of reducing
power to below 15 percent,
where
a
turbine trip would not result in a reactor trip.
With the mechanical
system inoperable
(due to the Overspeed
Test Lever in the
"TEST" position),
protection
was provided
.
solely by OPC,
an electronic
system which energized oil dump solenoids
to close turbine control
and interceptor valves
on
an overspeed
condition.
TS Surveillance
Requirement 4.3.4.2 stated that the
protection
system required
by the associated
LCO would be
demonstrated
in part,
by cycling all stop, control, reheat
stop,
and interceptor valves through
a complete cycle once per month.
Operators
interpreted this requirement to imply that all of the
specified valves
must
be able to respond to an overspeed
condition for
the overspeed
protection
system to be considered
As the
would have only actuated
two of the four sets of valves specified
by the
Surveillance
Requirement
(due to the condition of the Overspeed
Test
Handle),
operators
considered
the turbine overspeed
system required
by
TS to be inoperable
and, at 4:30 p.m., entered
TS 3.3.4 Action b, which
required that the turbine
be isolated
from the Main Steam
System within
six hours.
A turbine downpower
was
commenced
and, at 4:55 p.m., the
licensee notified the
NRC Operations
Center that
a shutdown required
by
TS had
commenced,
as required
by 10
CFR 50.72.
The inspector
responded
to the site
and observed
the shutdown'.
The
inspector
found control
room conditions to be well-controlled, with a
minimum of noise
and crowding.
Operators
communicated well and the
cpnsistent=use
of repeatbacks
and formal communication
was noted.
The
only questionable
attribute observed
was the direct involvement of the
and
ANPS at portions of the control
boards at various times,
as
opposed to the expected
performance
standard that'hey maintain
a broad,
"big picture,"
command
and control position.
As electrical
load was reduced to minimal levels,
a main generator
reverse
power annunciator
was received
and,, at 7:04 p.m., operators
promptly tripped the turbine.
With the turbine isolated
from the Main
Steam System,
operators
exited the applicable
TS AS.
The licensee
performed troubleshooting
on the auto-stop oil system
and determined
that debris
had partially clogged
a flow restricting orifice in the oil
line supplying the system.
The debris
appeared
to remove itself from
the system in time,
and oil pressure
returned to pre-test levels.
In
evaluating the event,
the licensee
determined that the oil pressure
observed directly following the test would have
been sufficient to
prevent
a trip, and
OP 2-0030150,
"Secondary
Plant Operating
Checks
and
Tests,"
was revised to allow pressures
as low as
70 psig to be observed
before. prohibiting the release
of the Overspeed
Test handle.
The inspector
concluded the following with respect to this event:
Operators
properly interpreted
TS requirements
regarding
operability of the turbine overspeed .protection
system.
Operators
performed professionally in removing the turbine from
service.
command
and control was,
at times,
too narrowly focused.
~
01. 4
Un lanned
Breach in Fire Barrier
71707
37551
On April 22,
a Unit
1
SNPO reported to the control
room his
identification of two holes in a wall in the pipe penetration
room.
The
two 10 inch diameter holes were bored in the wall as
a part of the
implementation of PC/N 001-196,
"Containment Air Conditioning for
Refueling Outages,"
and supported
the installation of connections
to
piping for temporary chilled water which was to be directed to the
containment
fan coolers during outage
work to affect containmhnt
cooling.
The licensee. noted that
UFSAR Section 9.5A, section 3.11, described
the
wall in question
and stated that it was required to be functional in a
non-degraded
condition.
AP 1800022,
"Fire Protection Plan,"
was
referenced
and it was found to allow such
a breech,
provided that either
continuous fire detector
coverage
or
a continuous fire watch was
provided.
A continuous fire watch was established
and the holes were
covered with wooden barriers
(to support ventilation requirements).
The inspector
reviewed
ENG-gI l. 1,
Rev 0, "Engineering
Packages,"
and
found that requirements
were provided for preparers
of engineering
packages
to consider plant safety issues
during the implementation of
design
changes.
The inspector
reviewed the subject
PC/H and found that:
A section entitled "Plant Safety During
Implementation/Restoration"
discussed
the modification exclusively
from the standpoint of CCW system operability.
An attachment entitled "Fire Protection
Review Checklist" included
a specific line item prompting the preparer to consider whether
the engineering
package installed, modified, or altered the
function of fire barriers.
The question
was answered
"no."
The inspector
concluded that the licensee's
engineering
personnel
performed
an inadequate
review of the subject modification with respect
to fire protection considerations.
The licensee's
corrective actions
were documented
in
CR 96-551,
and included:
~
A review of pre-job barriers
which should
have prevented
the
event.
0
~
Fire protection process
reviews
and enhancements.
~
Strengthening
the engineering
process
and its potential
impacts
on
The inspector
concluded that the licensee's
failure to properly consider
the in-process
effects of the subject modification constituted
a
violation of the licensee's
procedures
covering engineering
packages.
However, the inspector
found that the licensee's
operators
were
effective in identifying the condition
and that corrective actions,
both
to the field condition
and the process
issue,
were appropriate.
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 335/96-06-01,
"Failure to Consider Fire Barrier Operability
in Engineering
Package" ).
Unit
1 Shutdown
40500
71707
On April 28, Unit
1 commenced
a reactor
shutdown to begin
a refueling
outage.
At 10:49 p.m., during the shutdown,
operators
experienced
difficulties when
1 failed to insert properly with the rest of the
CEAs in its group.
The shutdown
was placed
on hold at approximately
88
percent
power while I&C performed troubleshooting
on the
CEA.
Visicorder data
suggested
that the hold coil for CEA
1 was not releasing
to allow the
CEA to insert.
The inspector
was present
and verified that
the
CEA was still tripable
and was within 7.5 inche's of the other
in Regulating
Group 7, thus satisfying
TS requirements for continued
operation.
A troubleshooting
plan was assembled
under
AP 0010142,
Rev 19, "Unit
Reliability - Manipulation of Sensitive
Systems,"
which included placing
the
CEA on
a parallel
bus with CEA 68, replacing the timer module, the
pull down power switch,
and the lift power switch for CEA 1,
and then
divorcing the
CEA from the parallel
bus in accordance
with the vendor
technical
manual.
The inspector
attended
a
FRG meeting conducted to
review the troubleshooting
plan.
A quorum was present,
and the issue
was discussed
appropriately.
The inspector witnessed
the module
replacements
and the subsequent
operability tests
performed
by
operators.
No d'eficiencies
were identified.
Shutdown
recommenced
at 2:15 a.m.
on April 29.
Node.2
was entered
at
6:35 a.m.
and the reactor
was tripped
as
a part of a pre-planned test to
verify the mechanical
freedom of CEAs.
TS 3. 1.3.4 required
CEA drop
times of less
than or equal to 3. 1 seconds.
The inspector
reviewed the
data obtained
from the test
and found the average
drop time to be 1.97
seconds,
with the longest time being 2.50 seconds.
Overall, the inspector
found the conduct of the shutdown to be good,
with operators
communicating formally and with the consistent
use of
repeatbacks.
Particularly notable
were consistent
and conscientious
refe'rences
to annunciator
response
summaries
by operators
as
were received.
This performance
was repeated
by'everal
operators
involved in the shutdown
and was viewed as
a strength in
licensed operator
performance.
Reduced
Inventor
0 erations
71707
During the inspection period, Unit
1 entered
a reduced
RCS inventory
condition to support
nozzle
dam installation.
The
following items were observed
during this evolution:
~
Containment
Closure Capability - Instructions
were issued to
accomplish this;
men
and tools wer'e
on station.
A dry run of
closing the equipment
hatch
was performed prior to the draindown.
The inspector
reviewed penetrations
open at the time of the
draindown
and verified that closure capability was provided.
RCS Temperature
Indication - Two CETs were available
on each
channel.
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 in the containment
was
installed
and was visible to a dedicated
operator in the control
room via a television monitor.
During the draindown,
the camera
became
The inspector noted that the draindown
was
immediately secured
and
an operator
was dispatched
to the level
tube to provide direct input to the control
room via radio.
~
RCS Level Perturbations
- When
RCS level
was altered,
additional
operational
controls were invoked.
At plant daily meetings,
operations
took actions to ensure that maintenance
did not
consider performing work that might effect
RCS level or shut
down
cooling.
RCS Inventory Volume Addition Capability - The
B HPSI
pump and the
B charging
pump were available for inventory addition,
as were two
trains of shutdown cooling.
RCS Nozzle
Dams - The purpose of the draindown
was to install the
nozzle
dam's.
Vital Electrical
Bus Availability - Operations
would not release
busses
or alternate
power sources for wor k during this outage.
~
Pressurizer
Vent Path - The manway atop the pressurizer
has
been
removed to provide
a vent path.
02
Operational
Status of Facilities and Equipment
02. 1
En ineered Safet
Feature
S stem Walkdowns
71707
The inspectors
used Inspection
Procedure
71707 to walk down accessible
portions of the following ESF systems:
~
During the week of April 7, the inspector
performed
a walkdown of
the Unit
1 Intake Cooling Water System.
This consisted of a
review of the following procedures
and engineering
drawings
and
verification of current system alignment.
OP 1-0640020,
Rev 41,
"ICW System Operation"
ONOP 1-0640030,
Rev 19, "Intake Cooling Water System"
ONOP 1-0030131,
Rev 62, "Plant Annunciator Summary"
Other Procedures
10
'
Applicable Engineering
Drawings
~
UFSAR Sections
7.3, 7.4 and 9.2
A number of minor discrepancies,
involving procedural
typographical
errors
and omissions,
were noted.
These conditions
were documented
by the licensee
in PMAI 96-083.
Equipment
operability, material condition,
and housekeeping
were acceptable
in all cases.
A number of more significant items, involving
procedural
accuracy
and the maintenance
of the
UFSAR, were also
identified,
and are documented
in paragraphs
03. 1,
E7 and Xl,
respectively.
Of particular concern
were the following procedural
errors:
~
"SURVEILLANCE RE(UIREMENTS" for INTAKE COOLING
WATER SYSTEM
This surveillance required,
in part, that "At leapt two
intake cooling water loops are demonstrated
OPERABLE:
a 0
At least
once per
31 days
by verifying that each valve
(manual,
power operated
or automatic) servicing safety
related
equipment that is not locked,
sealed,
or
otherwise
secured
in position, is in its correct
position."
All valves supplying
ICW to safety related
equipment,
with
the exception of the temperature
controlled automatic valves
TCV-4A and 4B, were locked.
TCV-4A and
4B were verified
"Throttled" (verify flow per
SNPO log) as part of the
CCW A
and
B Train Tests
performed monthly
(AP 1-0010125,
Rev 107,
"Schedule of Periodic Tests,
Checks
and Calibrations,"
Check
Sheet 7).
As the temperature
controllers which actuated
these
valves
had both manual
and automatic
modes of
operation,
the inspector discussed
this method of
verification with the acting Operations
Supervisor
and
Licensing.
Although the initial and quarterly alignment
check specified the controller. in automatic,
Operations
still considered
the valve operable if the controller was in
the manual
mode.
CR 96-1148
was prepared to evaluate this
condition.
AP 1-0010123,
Rev 100, "Administrative Control of Valves,
Locks and Switches,"
Appendix J, "Intake Cooling Water Valve
List," checked the general
condition
and alignment of ICW
valves to the
TCW and
CCW heat exchangers.
The temperature
controlled automatic valves TCV-14-4A and
4B were verified,
by procedure,
to be in the automatic
mode,
the
same
as the
initial system lineup.
This appendix
was verified
quarterly.
The two different methods of verifying TCV-14-4A and
4B
'0
position, i.e. controller in auto
(OP 1-0640020
and
AP 1-
0010123)
and throttled
(AP 1-0010125),
were inconsistent.
CR 96-1148
was prepared to evaluate this condition.
~
1-EOP-99,
Rev
15
Table
1 Safet
In 'ection Actuation Si nal
(Page
4 of 4)
verified that
"Two (2)
ICW Pumps lA and
(1B or 1C) are
ON.
The
1C
ICW Pump could
be aligned to the
A ICW Header,
in
which case, this verification would be incorrect.
During the week of April 14, the inspector
performed
a walkdown of
the Unit 2 Intake Cooling Water System.
This consisted of a
review of the following procedures
and engineering
drawings
and
verification of current
system alignment.
~
OP 2-0640020,
Rev 28, "Intake Cooling Water System
Operation"
~
ONOP 2-0640030,
Rev 18, "Intake Cooling Water System"
~
ONOP 2-0030131,
Rev 51, "Plant Annunciator Summary"
~
Other Procedures
~
Applicable Engineering
Drawings
~
Unit 2
UFSAR Sections
7.3, 7.4
and 9.2
A number of minor discrepancies,
involving procedural
typographical
errors
and omissions,
were noted.
These conditions
were documented
by the licensee
in PMAI 96-084.
Equipment
operability, material condition,
and housekeeping
were acceptable
in all cashs.
A number of more significant items, involving
procedural
accuracy
and the maintenance
of the
UFSAR, were also
identified,
and are documented
in paragraphs
03.1,
E7 and Xl,
respectively.
Of particular concern
were the following procedural
errors:
~
"SURVEILLANCE REQUIREMENTS" for INTAKE COOLING
WATER SYSTEM
This surveillance required,
in part, that "At least
two
intake cooling water loops shall
be demonstrated
OPERABLE:
a ~
At least
once per 31 days
by verifying that each valve
(manual,
power operated
or automatic) servicing
safety-related
equipment that is not locked,
sealed,
or otherwise
secured
in position, is in its correct
position."
All valves supplying
ICW to safety related
equipment,
with
the exception of the temperature
controlled automatic valves
TCV-14-4A and 4B, wer e locked.
TCV-14-4A and
4B were
verified "Throttled" (verify flow per
SNPO log)
as part of
the
CCW A and
B Train Tests
performed monthly
(AP 2-0010125,
12
Rev 59,
"Schedule of Periodic Tests,
Checks
and
Calibrations",
Check Sheet 7).
As the temperature
controllers which actuated
these
valves
had both manual
and
automatic
modes of operation,
the inspector discussed
this
method of verification with the acting Operations
Supervisor
and Licensing.
Although the initial and quarterly alignment
check specified the controller in automatic,
Operations
still considered
the valve operable if the controller was in
the manual
mode.
AP 2-0010123,
Rev 69, "Administrative Control of Valves,
Locks and Switches,"
Appendix J, "Intake Cooling Water Valve
List," checked the general
condition and alignment of
ICW'alves
to the
TCW and
CCW heat exchangers.
The temperature
controlled automatic valves
TCV-14-4A and
4B were verified
in the automatic position, the
same
as the initial system
lineup.
This appendix
was verified quarterly.
The two different methods of verifying TCV-14-4A and
4B
position, i.e. controller in auto
(OP 2-0640020
and
AP 2-
0010123)
and throttled
(AP 2-0010125),
were inconsistent.
CR 96-1148
was prepared to evaluate this condition.
~
2-EOP-99,
Rev 12.
Table
1 Safet
In 'ection Actuation Si nal
(Page
4 of 5)
verifies that
"Two (2)
ICW Pumps
(2A or 2C)
and
2B are
ON.
The
2C
ICW Pump could be aligned to the
B
ICW Header,
in
which case, this verification would be incorrect.
The inspectors
performed
a walkdown of the accessible
portions of
the
HPSI system
on Unit 2 the week of May 6. 'his consisted of a
review of the following procedures
and engineering
drawings
and
verification of current system alignment including:
OP 2-0410020,
Rev 29,
"HPSI/LPSI Normal Operation"
ONOP 2-0030131,
Rev 51, "Plant Annunciator Summary"
ONOP 22-0410030,
Rev 9,
"High Pressure
Safety Injection"
Applicable Engineering drawings
UFSAR Section 6.3
Equipment operability, material condition,
and housekeeping
were
acceptable.
Equipment labeling was in good condition and easily
accessible.
The inspector did note that one of the dogged
doors
leading into the area
was left ajar while an operator
was
performing his rounds in the area.
A number of minor procedural
deficiencies
were identified and forwarded to the licensee for
disposition.
13
'2.2
E ui ment Clearances
71707
The inspectors
independently verified the following equipment clearances
for correctness:
a ~
b.
1-96-04-369
on
ICW A Header
CW Pump s'upply line - This clearance
consisted of three tags isolating the
ICW A Header
CW Pump supply
line.
All tags were in place
and the valves in the correct
position.
2-96-04-075
on HVS-4A centrifugal
fan for RAB main supply system-
This clearance
consisted of one tag isolating the electrical
supply to the HVS-4A.
The tag was in place
and the breaker in the
correct position.
03
Operations
Procedures
and Documentation
03. 1
Off-Normal 0 eratin
Procedures
Res
onse
Summaries
71707
During system walkdowns documented
in this report
and in IR 96-04, the
inspectors identified
a number of deficiencies
in ONOPs which described
actions to be taken
on the part of operators,
and included information
to help diagnose
problems,
when annunciators
alarmed.
The inspectors
reviewed the individual findings from the two IRs and summarized
the
findings in the table below.
System
Unit
1
Unit 2
Unit
1
ICW
Unit 2
ICW
Safety System Total
Unit
1 IA
Unit 2 IA
All Systems Total
ONOP
Set oints
10
15
ONOP
Other
18
24
"ONOP Setpoints,"
as referred to in the table,
are differences
between
the setpoint for a given annunciator,
as defined in the
ONOP,
and the
TEDB,
a design
document which contained setpoints for each instrument.
"ONOP Other,"
as referred to in the table,
are cases for which other
attributes of a given response
summary were incorrect.
Attributes in
this case
included'wrong specified
sensing
element,
wrong
CWD reference,
and wrong specified operator action.
14
06
If one
assumed
that the annunciator
response
summaries
were, at one
time, correct,
the errors identified would tend to imply weaknesses
in
.
the configuration control process,
as ongoing changes
to the plant were
not factored into procedures.
The inspectors
examined the licensee's
configuration control process,
and initial conclusions
are provided in
paragraph
E.7. of this report.
Weaknesses
in annunciator
response
summaries
have
been identified both
by the
NRC and the licensee for some time.
In response,
the licensee
dedicated
an individual to rewriting and verifying the summaries.
The
effort was estimated
by the licensee to take two man-years.
With the
exception of those
items described
in paragraphs
E.7, the deficiencies
totaled in the table
above were
deemed
as not representing
violations of
NRC requirements,
as requirements for these
instances
are,
under TS,
applicable only to safety-related
With very few
exceptions,
at St. Lucie are non-safety related.
Consequently,
the errors
noted were
deemed to represent
a weakness
in
operations
procedures.
Operations
Organization
and Administration
On April 4, the licensee
announced
the reassignment
of J.
West,
Operations
Hanager,
to the outage
management
organization.
Hr. West was
replaced,
on an interim basis,
by Hr. H. Johnson,
previously Operations
Hanager at Turkey Point.
Additionally, the licensee
announced that
an augmented
gA effort was
being initiated to support the Unit
1 refueling outage
and that
a
Hanagement-on-Sh'ift
effort was being initiated which would station
management
observers
in the plant's control
rooms to observe
operator
performance
in the areas of conduct of operations
and procedural
adherence.
08
08.1
Hiscellaneous
Operations
Issues
S ent Fuel
Pool Current Licensin
Bases
Review
On Harch
26 and 27, the
NRC St. Lucie Project Hanager
performed
an audit
on both St. Lucie Units'ompliance with the current licensing basis
regarding the spent fuel pool
and core offload activities.
Details of
the findings are in Attachment
1 (Spent
Fuel Storage
Data Tables).
No
discrepancies
were found at either unit.
However the licensee
has
stated that they intend to complete several
administrative
improvements.
These included:
~
Unit
1
Haintaining
SFP temperature
below 150'F - the licensee
intended to have
a procedure
in place prior to the
outage similar to Unit 2 procedure
OP 2-1600023,
Rev
58,
page
26 of 69.
The inspector verified that
OP 1-
1600023,
Rev 59, "Refueling Sequencing
Guidelines,"
included,
as step 1.C.3,
a verification that fuel pool
15
~
Unit
1
~
Unit
1
II. Maintenance
temperature
was less
than
140'F prior to off-load.
This change
was in place prior to the Unit
1 outage.
Maintaining
a minimum boron concentration
of 1720
ppm
in the
SFP - the licensee
intended to have
h procedure
in place prior to the outage.
The inspector verified
that
OP 1-1600023,
Rev 59, "Refueling Sequencing
Guidelines,"
as step 1.F, included
a verification that
boron concentration
was greater
than or equal to 1720
ppm prior to offload.
This change
was in place prior
to the Unit
1 outage.
Preparing
and producing
a heat load calculation to
verify the SFP's ability to accept
a full-core
offload.
The calculation could not be located during
the audit.
The inspector verified that this
calculation
(the results of which were included in
PC/H 054-196)
had
been prepared
and approved prior to
the Unit
1 refueling outage.
H1
Conduct of Maintenance
Ml. 1
Observation of In- rocess
Corrective Maintenance Activities
The inspectors
observed
maintenance activities
on the components listed
below to determine if the activities were conducted
in accordance
with
regulatory requi'rements,
technical specifications
(TS), approved
procedures,
and appropriate
industry codes
and standards.
H1.2
Observation of Valve Packin
and Modification
62700
The inspectors
observed
portions of valve repacking
and modification
activities to verify that the maintenance
and modification activities
were performed in accordance
with the applicable
procedures
and work
orders.
The procedure
used
was M-0043,
Rev 17, "Valve Packing."
The
inspectors
observed portions of the following valve maintenance
or
modification activities.
Valve
No.
Val ve
Function
Location
W/0 or Procedure
Used
Activities
1403
1405
1200
MV-02-2
.Isolation
Pressurizer
Isolation
Pressurizer
Safety
Pressurizer
Isolation
Charging
Pump
Discharge
M-0043
M-0043
PWO 61/3604
H-0043
Packing
Packing
Modification
Packing
Safety Relief Valve 1200
had previously been identified to be leaking.
The repair included replacement of the valve stem,
but the licensee
16
could not procure
an identical
stem.
Therefore,
the licensee
enlarged
the valve stem hole for a larger stem.
The modification process
and
requirement for a liquid penetrant
exam1nation
were stated
in work order
PWO 61/3604.
The inspectors
determined that all the valve repackings
and the modification stated
above were performed in an acceptable
manner.
Work Order:
95-02643-01C
Jack
and
La
New Pressurizer
Safet
Valves
62703
Due to seat
leakage
problems
experienced
with the previous design
pressurizer
safety valves,
FPL elected to replace these
valves with a
new, forged body, design
which accommodated
a flexi-disc seat
enhancement.
During site verification nitrogen seat set pressure
and
bubble tests
conducted
in accordance
with Work Order 95-026432-01B,
Crosby's Technical
Manual 8770-5460,
Rev 10,
and
HP H0017,
Rev 33, two
of the
new valves, Serial
Nos.
N84217-00-0002
and N84217-00-0004 failed
to pass
the seat leak test.
As a result,
the valve bonnets with the
valve internals for the two valves that failed were required to be
disassembled
from the valve body so the valve seats
could be .lapped.
From Hay 6-8, the inspector
observed
the "Jack and Lap" activities
conducted
in accordance
with
PWO 95-02643-01C
by a Crosby Valve and
Gage
Company representative,
FPL maintenance
personnel
and site engineering.
The inspector
also observed that the retest of both valves
was conducted
in accordance
with
PWO 95-026432-01B
and
HP M0017.
The valve retests
were satisfactory
and all work activities observed
were conducted
in
accordance
with the approved written instructions
by knowledgeable
personnel.
Clean
Com onent Coolin
Water Heat
Exchan er
62703
On May 8, the inspector
observed
maintenance
personnel
performing heat
exchanger
tube hydrolazing operations
on Component Cooling Water Heat
Exchanger
lA in accordance
with
PWO 95-028905-01.
During review of the
work package for this cleaning
and repair activity the inspector noted
that the information copies of the control procedures
had not been
verified as the correct revision with the control document, initialed,
and dated
as required
by Document Control
Procedure
gI 6-PR/PSL-1.
The
procedures
involved were HMP-14. 1,
Rev 6,
"Component Cooling Water Heat
Exchanger
Cleaning
and Repair,"
GMP-02,
Rev 13,
"Use of H&TE By
Mechanical
Maintenance,"
and
HP H-0064,
Rev 1, "High Pressure
Hydro-
Blasting of Heat Exchanger
Tubes
and Associated
Equipment."
The
inspector subsequently
verified that the procedures
in question
were in
fact, the correct revision.
However,
upon being notified,
maintenance
supervision
personnel
stopped all work on the Component
Cooling Water Heat Exchanger until the cause of this discrepancy
could
be determined.
Corrective actions
included replacing the lead
maintenance
technician
on this job and conducting briefings with
maintenance
personnel
on all shifts to ensure that outage
maintenance
personnel
knew they were personally responsible for ensuring
work was
conducted
in accordance
with current revision of procedures
and that
procedures
were stamped,
signed,
and dated
as required.
This failure
17
constitutes
a violation of minor significance
and is being treated
as
a
Non-cited Violation consistent
with Section
IV of the
NRC Enforcement
.
Policy.
The
NCV was identified as
NCV 335/96-06-02,
"Failure to
Document Verification of Current Procedure
Revisions."
Maintenance
and Haterial Condition of Facilities and Equipment
OP 1-0400050 "Periodic Test of the
En ineerin
Safe uards
Features"
61726
On Hay 2, the inspector attended
the infrequent test briefing given by
the Hanagement
Designee
and Test Specialist prior to the performance of
integrated
safeguards
testing
on Unit 1.
The overview portion of the
brief discussed
the purpose of the test
and emphasized
the importance of
using
STOP principles, i.e., Stop-Think-Operate-Prove.
All individuals
involved in the test then divided into groups for a detailed specific
test brief.
The inspector concluded that the brief was thorough
and
covered the necessary
items.
At approximately
11:30 a.m., all test personnel
were on-station
and the
safeguards
test
commenced.
Shutdown cooling was secured
and lineups
performed prior to inputing an
ESFAS signal concurrent with a
LOOP.
When the
LOOP was initiated by opening both startup transformer output
breakers,
operators
observed that the
1B
EDG started,
however,
the
output breaker failed to close.
The
ANPS immediately brought this
failure to the attention of both the Test Specialist
and
Management
Designee.
The Management
Designee directed the
ANPS to place
shutdown
cooling back-in-service
and restore offsite power.
To provide
as
much
information as pbssible for troubleshooting,
no attempt
was
made to
close the
1B
EDG output breaker.
Operators
took timely and appropriate
action in response
to a loss of the operating
instrument air compressor
which with degraded
instrument air pressure
caused
the
AOV FCV-3306
"SDC
return valve" to fail in the full open position.
This limited the
amount of RCS flow which could
be directed to the
SDC heat exchangers.
Operators
entered
the applicable Off-Normal Operating
Procedures.
Within minutes,
the 480
VAC AB swing bus
was realigned to the
A
electrical
side which allowed operators
to restore
instrument air.
By
approximately
12:44 p.m., operators
had restored offsite power.
The
safeguards
test
was secured
and exited at 1:29 p.m.
The inspector
judged operator
response
and support
by maintenance
as good.
The licensee
performed troubleshooting of the
1B
EDG output breaker
and
associated
circuitry throughout the day.
The root cause for the failure
was determined
to be
a failed relay in the bus undervoltage circuit.
The failure of the relay resulted
in a failure to satisfy
bus
interlocks required for the
EDG output breaker to close
onto the
1B3 bus.
The licensee
recommenced
testing the evening of Hay 2.
The inspector
witnessed
the conduct of the
LOOP/SIAS portion of the test.
Operator
performance
was found to be very good, with clearly centralized
command-
18
and-control
maintained
by the Unit ANPS.
Communications
were
formal,'nd
repeatbacks
were consistently
used.
The observed
portion of the
test produced satisfactory results.
Overall, the inspectors
found the coordination
and execution of the
observed portions of this test to be excellent.
Polar Crane Testin
Unit
1 Reactor Vessel
Head Lift
62700
The inspectors
reviewed the adequacy of load testing for the polar crane
(to verify that the maximum lifting load would not exceed
the maximum
rated load)
and subsequently
observed
the reactor
head lift.
Procedures
and documents
reviewed for both the polar crane testing
and reactor
head
lift were the following:
CR 96-613,
Rev 0, "Evaluation of Polar Crane
Load Test"
Procedure
1-LOI-HH-45, Rev 4, "Unit 1 Reactor Containment Building
Polar Crane
Load Test of Hain Hoist Gear
Box to 125 percent of
Rated
Load"
Procedure
1-M-0015,
Rev 27, "Reactor Vessel
Haintenance
- Sequence
of Operations"
The polar crane in the reactor building is used for the removal
and
installation of the reactor
head
and related parts.
The original rated
capacity for the polar, crane
was 350,000 lbs for the main hoist.
Recently,
the licensee identified problems with the polar crane gear
box
and decided to rhplace it.
ANSI B30.2 requires that the polar crane
with the replaced
gear
box be retested for load capacity.
Two tests
were performed.
In the first test,
the vendor scale
read 435,000 lbs;
but the scale
on the main hoist scale
read 356,000 lbs.
Because of the
discrepancy
in scale readings,
the licensee
had the vendor scale
sent to
a lab for verification.
The vendor scale
was determined to be reading
too high and
needed to be calibrated.
The final calibrated
load was
similar to the polar crane
main hoist reading.
In accordance
with ANSI
B30.2Property "ANSI code" (as page type) with input value "ANSI</br></br>B30.2" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., the licensee
used
80 perce'nt
(280,000 lbs) of the 350,000 lbs
reading
as the rated load.
The licensee
wanted to take full advantage
of the rated loads for the
crane
and performed
a second test.
The second test
was terminated
prematurely
because
a refilling hose for the water
bag test load was
broken.
The final reading for the scale before the hose
broke was
357, 180 lbs.
The licensee
used
80 percent
(285,744 lbs) of the tested
load
as the maximum rated load to lift the reactor
head.
In preparation of the reactor
head lift, the li'censee's
engineers
reviewed the previous loads lifted for the reactor
head
and identified
that the loads
were between
280,000
and 320,000 lbs for the reactor
head
and related
items
such
as bolts, nuts,
lead shielding, shielding support
frame, etc.
The engineers
also reviewed
CE Instruction Hanual
8770-
12276,
Rev 0, entitled "Hajor Component Lifting/Lowering Interfaces for
19
Reactor
Vessel
Head Upper Guide Structure,
ICI plate;
Core
Support'arrel
for the Florida Power
and Light Company,
St. Lucie Unit 1," which
stated that the estimated
load
on the crane for the reactor vessel
head
lift was 267,968 lbs.
From the sketches
included in the manual,
the
licensee
engineers
concluded that this weight included the
head
and the
lift device (tripod) but did not include the studs or lead shielding.
The licensee's
engineers
removed
as
many miscellaneous
items
as
practical prior to lifting the reactor
head to ensure that the rated
capacity of the polar crane would not be exceeded
during the lift.
The inspectors
observed
the preparation of the reactor
head,
removal of
the miscellaneous
items,
and installation of the lifting device
(tripod).
During the reactor
head lifting, the inspectors
observed that
the head
was effectively lifted and lowered onto three cribbings
on the
floor to support the reactor
head.
The maximum load cell reading during
the lift was 255,570 lbs.
The inspector determined that the preparation
and lifting of the reactor
head
was acceptable
and met all requirements.
Document
Review of Main Steam Safet
Valve Set ressure
Testin
62700
The licensee
completed setpressure
testing for 16 Hain Steam safety
valves for Unit
1 during the early part of the refueling outage..
The
procedures
used for the testing
and calibration of HLTE were:
GHP M-0705,
Rev 27,
"Hain Steam Safety Value Maintenancy
and
Setpressure
Testing"
gI-12-PR/PSL-l,
Rev 21, "Calibration of Measuring
and Testing
Equipment"
gI-12-PR/PSL-2,
Rev 20, "Control
and Calibration of Measuring
and
Test Equipment
(H&TE)"
The inspectors
reviewed
16 packages
of testing records
and found that
all of them met the requirements
of Procedure
GMP H-0705 and were
acceptable.
The
16 valves were divided into train "A" and "B" as
shown
below:
Train A
Train
B
Valve No.
8201,
8202,
8203,
8204
8205,
8206,
8207,
8208
8209,
8210,
8211,
8212
8213,
8214,
8215,
8216
The required records
and data for the setpressure
testing
are contained
in Appendix B, "Determining Safety Valve Setpressure
with Air
Setpressure
Device," of GHP M-0705.
The MME used
For testing the main steam safety valves included
a
Ten valves,
8203 to 8208 and 8213 to 8216,
as listed in
CR 96-597,
were
found to have
a setpressure
outside the acceptable
boundaries
during the
first test
and required evaluation for tolerance
change
based'on
fuel
analysis.
The acceptable
ranges
were defined
as
a
1 percent of
midpoints
985 psig or 1025 psig.
20
H3
specific pneumatic motor and several
pressure
The calibration
for the motor and most of the gauges
in the pre-calibration
occurred
one
week before work started
and in the post-calibration
one or two days
after the work was completed.
The exception
was the pre-calibration for
M-222 and M-288 six months prior to use.
The inspectors
questioned
the licensee
as to the pre-calibration validity for these
two
The licensee
explained that the pressure
had not been
used since the last calibration
and the effective calibration date
had
not expired.
Thus the previous calibration was still valid and could be
used
as
a pre-calibration.
The inspectors
concurred in the licensee's
explanation
and verified that all the gauges
had post-calibration
immediately after the tests
were completed
and that all the gauges
were
found to be within the allowable range
and acceptable.
The inspectors
also reviewed the
H&TE checkout log and history for the pressure
used in the testing
and identified that gauges
H-222 and M-288 had not
been
used since October
15,
1995 when they were post-calibrated.
The
inspectors
concluded that the licensee
performed
adequate
setpressure
tests for the main steam safety valves
and used validated pressure
gauges for this test.
Maintenance
Procedures
and Documentation
M3.1
Inservice
Ins ection
Unit
1
73052
The inspector
reviewed documents
and records,
and observed activities
as
delineated
below to determine
whether
ISI activities were conducted
in
accordance
with applicable
procedures,
regulatory requirements,
and
licensee
commitments.
The inspector's
objective
was to examine the
licensee's
steam'enerator
examination
and evaluation activities
and the
10-year ultrasonic examination of the reactor vessel.
The applicable
code for this ISI is the
Section XI, 1983 Edition with
Summer
1983 Addenda.
St Lucie Unit
1 is presently in the first outage
of the third 40 month period, of the second
10-year
ISI interval.
This
is the thirteenth refueling cycle for Unit 1.
Eddy current acquisition activities were conducted
by ABB/Combustion
Engineering.
Primary analysis of eddy current data
was conducted
by
Zetec in Issaquah,
and the secondary
analysis
was conducted
and Light NDE Laboratory in West
Palm Beach,
The Unit 1, 10-year Reactor Vessel
examinations
were conducted
by Southwest
Research
Institute (SwRI).
H3.1.1
Review of Procedures,
Guidelines,
and Licensee
Documents
The following documents
were reviewed
by the inspector during the
assessment
of ISI activities.
FPL Eddy Current Examination
Procedure
NDE 1.3,
Rev 8,
Entitled:
Eddy Current Examinations of Non Ferromagnetic
Tubing Using Multi-Frequency Techniques
HIZ-18/HIZ-30
21
FPL Document CSI-ET-96-11,
Rev A, Unit
Eddy Current Examination
Plan
FPL Letter of Response
to
Dated June
23,
1995
FPL Safety Evaluation JPN-PSL-SENP-95-112,
Rev 1, Entitled:
Cracking of Westinghouse
Alloy 600 Mechanical
Steam
Generator
Tube Plugs
PC/N 125-195M,
Rev 1, Entitled:
Tube
Plugging
and Plug Repair
St.
Lucie Unit
1 Eddy Current Data Analysis Guideline
and
Performance
Demonstration,
Dated
Hay 1996
SwRI Procedure
SLC-AUT-14,
Rev 1,
Change
1, Entitled:
Automated Ultrasonic Inside Surface
Examination of Pressure
Piping Welds
SwRI Procedure
SwRI-AUT2, Rev 9,
Change
1, Entitled:
Automated Ultrasonic Inside Surface
Examination Indication
Resolution
and Sizing
SwRI Procedure
SLC-AUT15, Rev 2,
Change
1, Entitled:
Automated Ultrasonic Inside Surface
Examination of Ferritic
Vessels
Greater
Than 4.0 Inches in Thickness
U
FPL Document
PSL-100-AOA-95-1,
Rev 0; Dated April 5,
1995,
Entitled: Request
For Authorization of Alternative
Examination
NRC Safety Evaluation of FPLs Request for Authorization of
Alternative Reactor
Pressure
Vessel
Examinations
For St.
Lucie Plant, Unit
1
SwRI Procedure
SLC-PDI-AUTI, Rev 0,
Change
1, Entitled:
Automated Ultrason'ic Inside Surface
Examination of Ferritic
Vessel
Wall Greater
Than 4.0 Inches in Thickness
SwRI Procedure
SLC-PDI-AUT2, Rev 0,
Change
1, Entitled:
Automated Inside Surface Ultrasonic Flaw Evaluation
and
Sizing
The inspector's
review of the above
documents
revealed
they were
in accordance
with the applicable
ASME Code,
Technical
Specifications,
licensee
commitments,
and industry guidelines.
In
addition, the inspected
noted that, the licensee's
augmented
eddy
current examination plan, plug-a-plug tube plugging activities
and
alternative reactor pressure
vessel
examinations
revealed
good
outage planning
had
been
performed
and component safety should
be
enhanced,
based
on these
defensive barriers.
22
Observation of Steam Generator
Eddy Current Acquisition and Steam
Generator
Plug-A-Plug Repair Activities (73753) Unit
1
From Hay 6 until Hay 9, the inspector
observed
portions of the
licensee
eddy current data acquisition
and the Westinghouse
tube
plug cleaning activities.
These activities were conducted
in
accorda'nce
with .the approved
procedures
delineated
above
and the
FPL Examination Plan.
Review of SwRI Ultrasonic Examiner Performance
Demonstration
Records
at the Electric Power, Research
(EPRI) In Charlotte
N.C.
On Hay 10, the inspector
and
a representative
from FPL frisited the
NDE Center to review the performance
demonstration
examination results for the four SwRI data analysts that would be
used
by FPL to examine the Unit
1 reactor
vessel.
This review was
necessary
because
FPLs relief request entitled "Request for
Authorization of Alternative Examination Hethods," which was
applicable for Unit
1 reactor pressure
vessel
and which had
limiting conditions that prevented
100 percent
examination
coverage,
had two alternative
examinations
proposed
by the license
that
had changed
since
NRC had approved the relief request.
The first change
was that the licensee
had initially stated that
a
full vee 45'hear
wave examination
would be performed to the
extent practical to compensate
for recorded limitations.
However,
the current
SwRI examination
procedures
did not have this
examination
method in them.
The second
change to the April 1995
Relief Request
stated that
FPL would employ (as they became
available) additional examinations,
inspections
and/or techniques
that would provide
a substantial
increase
in the examination of
areas currently missed
under the current examination techniques.
To comply with their commitment to employ examination techniques.
that provide
a substantial
increase
in the examination of weld
areas currently missed,
FPL had
SwRI qualify to the performance
demonstration
examinations
conducted
by the
NDE Center for a
single side weld access
examination.
These examinations
are
conducted
in accordance
with Appendix VIII of later editions of
the
ASHE Code.
The editions of the
Code which include Appendix
VIII have not been
approved for use
by NRC at this time.
The
applicable
ASHE Section XI Code presently requires that
a weld be
examined
from two directions
(both sides of a weld).
Therefore,
to supplement
the Unit
1 Reactor Vessel
examinations with these
new alternative techniques
the licensee
invoked paragraph
of the applicable
ASHE (ode which stated that "alternative
examination
methods,
or newly developed
techniques
may be
substituted for the methods specified provided the inspector
(the
Authorized Nuclear Inspector) is satisfied that the results
are
demonstrated
to be equivalent or superior to those of the
specified method."
23
Although the ANI had approved the single side weld examination
techniques,
the inspector
had the following questions
concerning
the single side weld access
test parameters
and the examiner's
performance.
How many of the defects were'n the test blocks were
on the
far side of the weld?
Was the depth location of the defects
represented
on both
sides of the weld?
How many of the far side weld defects
were notches
verses
cracks?
What was the effective focal length of the
SwRI Duplex Send
and Receive transducers?
How effective
had the
SwRI examiners
been during their
qualification effort on the far side weld indications?
Could an examiner
pass the test
and miss
one or more far
side weld indications?
Detection Criteria delineated
in Paragraph
8. 1.(2)(b) of
SwRI Procedure
SLC-PDI-AUTl stated that "if an indication
cannot
be confirmed with at least
2 channels, it will be
considered irrelevant."
SwRI one sided examinations will
only have two channels
active, representing
two different
exam1nation
angles.
Far sided weld indications should
be
oriented at
a slightly different angle than near side weld
indications
because
defects
tend to follow the weld heat
affected
zone
on both sides of the weld.
Is it logical to
presume that
100 percent detection capability will be
achieved with both angle
beam transducers
on indications
when weld location
and defect orientation differ?
EPRI's
Performance
Demonstration Administrator reply to the
inspector's first question
was that there
was
no weld in the test
blocks
used for the single side access
weld qualification test.
EPRI's position was that the weld would not make
a significant
difference in the ability to detect or size indications in the
carbon steel
reactor vessel.
The inspector
however,
was concerned
that the acoustical
differences
between the vessel
base material
and the weld,
and the defect orientation differences
had not been,
at least analytically defined
and factored into the difficultlyof
the performance
demonstration test.
Therefore,
the performance
test
may not be ultrasonically representative
of the reactor
vessel
24
Discussions
with EPRI personnel
and review of documents
and
examiner test results satisfactorily resolved the questions listed
above other than those that related to the failure of the test
sample to include
a weld.
On Hay,13,
the inspector returned to the St. Lucie facility to
continue his examination of inservice inspection activities.
At
that time, the inspector
addressed
this concern with the
appropriate
licensee
management
personnel
and determined
the
licensee position on this matter.
Continuation of the inspection
will be reported in
NRC IR 96-08.
H8
Miscellaneous
Maintenance
Issues
H8.1
, Closed
VIO 389 95-01-02
"Failure to Follow Procedure
2-LOI-T-89
ara ra
h 4.a.4"
92902
The inspector
reviewed the licensee's
corrective actions related to the
subject violation.
The violation described
the licensee's
failure to
follow procedure
2-LOI-T-89 in February,
1995, which resulted
in'econnecting
switched electrical
leads to E/P 2110(.
An inadequate
independent verification failed to identify the discrepant
condition.
This caused
a loss of letdown flow when LCV-2110( did not open after it
was returned to service
and required charging
be temporarily secured
until the redundant
level control
was placed in service.
The inspector verified that corrective actions to avoid further
violations were completed.
STARs 950119,
950339,
950341,
and 950342 were
issued to document corrective actions.
The new Administrative
Procedure,
ADH-17.06,
Rev 0, "Independent Verification" was issued April
4,
1995.
The inspector
reviewed training department
records
and
verified that Maintenance
Personnel, i.e.,
I&C, Electrical,
and
Mechanical disciplines,
completed training on this event
and that both
I&C and Electrical
completed training on the requirements for
independent verification (Mechanical did not perform independent
verification and, therefore,
did not receive training in this area).
.
All disciplines incorporated
the
STOP principles into the on-the-job
training/task performance
evaluation portion of the Maintenance
Continued Training Program.
Technical staff and Operations
did not receive training on this event or
Independent Verification as part of these corrective actions.
Operations
incorporated training on independent verification into their
routine requalification training program.
This violation is closed.
25
III. En ineerin
E2
E2.1
Engineering Support of Facilities
and Equipment
HVS-4A Motor Re lacement
37551
On April 6, Unit 2
RAB main supply fan HVS-4A experienced
a failed motor
inboard bearing which tripped the motor, alerting operators
to the
condition.
The licensee
entered
the action statement
of TS 3.7.8,
which
required that the inoperable ventilation train be restored
to operable
status
or that the unit be shut down.
As the licensee
had
no replacement
motor
on site, multiple corrective
actions
were pursued
which included finding a direct replacement
and
repairing
and rewinding the existing motor.
The licensee
pursued
parallel
paths to resolve the issue.
The licensee
located
a safety related
replacement
motor,
however,
the
motor was not qualified for a harsh radiation environment,
as required
by design.
The licensee
implemented
a plan to install the subject motor
and to erect
a shield wall between the motor and the Unit 2 shield
building ventilation system filters which were responsible
for the
majority of the predicted
dose to the motor.
The subject modifications
were conducted
under
10
CFR 50.59.
The inspector
reviewed JPN-SPSL-96-0130,
"10
CFR 50.59 Safety Evaluation
for Temporary
Use of Non-Eg Motor for RAB Supply
Fan HVS-4A," which was
approved
on April 10.
The
SE considered
the compatibility of the
new
motor to the application,
the required shielding design,
and the seismic
considerations
for the shielding installation.
While differences
existed
between
the motors,- the
SE found the replacement
to be
acceptable.
The inspector
compared the two motors'haracteristics
and
compared the
new motor to the specifications
in Equipment gualification
Documentation
Package
299-A-451-4.7,
Rev 1.
No deficiencies
were
identified with the licensee's
determination of the interchangeability
-of the motors (with the radiation shield installed).
Upon testing of the
new motor, the licensee
found that the motor's
supply breaker tripped
on the first start following the rotational
check
run.
The cause
was attributed to higher,
more prolonged, starting
cur rents
drawn by the
new motor by virtue of increased
efficiency 'in the
design.
The inspector
noted that the licensee's
SE evaluation
had
concluded that,
as the operating currents of the two motors were
identical,
no effects
on breaker settings
were required.
Revision
1 to
the
SE was subsequently
issued
which stated that the
Long Time Delay
setting of the breaker trip function may be increased
such that
approximately
10 seconds
would be allowed for starting currents to
subside.
The inspector witnessed
subsequent
testing
and verified proper
fan rotation
and the absence
of breaker trips.
The inspector
concluded
that the original
SE had inadequately
considered
the starting
characteristics
of the
new motor.
26
The inspector
reviewed the Procurement
Engineering evaluation of the
new
motor's vendor data.
The licensee
found that the vendor evaluation of
the motor's bearing rating did not consider the specific installation
arrangement
of the motor.
The vendor's evaluation
considered rotor
weight and seismic factors in establishing that bearing loading was
acceptable.
The licensee's
installation required the consideration
of
loading due to
a series of fan belts driven by the motor (changing
radial loading from the vendor's
assumption).
The loading was
reevaluated
by the vendor,
considering
the specifics of the application
and was found to be acceptable.
The inspector
found the licensee's
review of vendor data to be detailed
and effective in identifying this
concern.
E4
E4.1
, Concurrent with the acquisition of the
new motor, the licensee
forwarded
the old motor to Tampa Armature, with whom the licensee
had previously
established
a process for rewinding and repairing safety-related
motors
through its Procurement
Engineering organization.
Work on the motor was
completed
and the. motor arrived
on site
on April 12.
By this time, the
replacement
motor had
been installed
and was in the final phases
of
testing
and qualification.
However, in pursuing this parallel path,
the
licensee
demonstrated flexibility and timeliness in having
a second
motor available
should problems
have developed
in the replacement
motor.
The installation of the motor and shield wall were completed,
and the
fan returned to service
on April 13, allowing the licensee to exit the
subject action statement.
The inspector
concluded that the licensee's
organizations
had
been effective at addressing this failure and that
good prior planning,
including the development of multiple success
paths,
resulted
in avoiding
a TS-required
shutdown.
Engineering Staff Knowledge and Performance
Failure to Prom tl
Document
Nonconformance
37551
On April 29, the inspector reviewed
CR 96-589,
which documented
the fact
that containment air conditioning, recently employed
by the licensee
in
outages
on -both units,
had resulted in containment
temperatures
which
were lower than those
assumed
in instrument calibration uncertainty
analyses.
The
CR reported that reviews of strip chart data for
containment
temperatures
during the outages
had indicated that
temperatures
had
been
as low as 70'F,
whereas calibration temperature
had
been
assumed
to be no less
than 80'F.
The inspector
noted that the
CR had
been presented
to and signed
by the
NPS who, programmatically,
was to consider the
CR for oper ability
concerns.
However,
no list of affected
instruments
was included in the
CR.'he inspector
asked
the licensee
how the
NPS could have
made the
operability determination without more data,
to include the individual
affected
components.
- The licensee
stated that the
CR originated in
engineering
and that engineering
personnel
had performed
an evaluation
prior to preparing the
CR.
The evaluation
had determined that adequate
27'argin
existed in the uncertainty analyses
to accommodate
the noted
reduced
temperature.
The inspector obtained
a copy of the subject evaluation
and noted that
the affected
instruments
included
35 Unit
1 instruments
and
39 Unit 2
instruments,
many of which provided inputs to the
and
ECCS systems.
The evaluation
documented
the results of calculations
and evaluations
made to justify the continued operation of these
instruments with
calibration temperatures
as low as 70'F.
While the evaluation
concluded
that the operability of the affected instruments
was not challenged,
no
quantitative information was provided.
The inspector discussed
the issue with the licensee
and found that the
condition (the temperature disparity) was'dentified
approximately
10
days prior to the initiation of the
CR.
Criterion XVI, "Corrective Action," specifies that measures
shall
be
established
to assure that conditions
adverse
to quality, such
as
nonconformances,
will be promptly identified and corrected.
The
glossary of the
FPL guality Assurance
Manual
(an attachment to the
Topical guality Assurance
Report, defines
a nonconformance
as
a
"...deficiency in characteristic,
...documentation,
or procedure
which
renders
the quality of an item unacceptable
or indeterminate."
The
inspector concluded that the subject temperature
discrepancy constituted
a deficiency in characteristic
which rendered
the calibration
(setpoints) of numerous safety related
instruments
indeterminate.
The inspector
reviewed
Rev 3, "Implementation of Condition
Reports at Juno Beach,"
and IP-805,
Rev 0, "Condition Reports."
The
inspector
noted 'that both procedures
contained
guidance
which included
"...Any individual who becomes
aware of a problem or discrepant
condition should take immediate actions that they are qualified to take
and initiate
a Condition Report..."
Additionally, IP-803 included, in
step 5.1.2.2.3(l)A "In all cases if an operability assessment
is
required the
CR should
be transferred
to the appropriate site..."
IP-
805, Appendix 2, contained
examples of conditions requiring the
origination of a CR.
Example 6, "Discrepancies
Associated with Alarms,
Setpoints,
Calibration," required
a
CR for "Conditions that may affect
equipment operability."
As
a result of these
procedural
requirements,
the inspector
found that
a programmatic
weakness
did not exist regarding
requirements
to document the subject
nonconformance.
The inspector
concluded that the licensee failed to identify the subject
nonconformance
in
a timely manner,
as required
the licensee's
Topical guality Assurance
Manual,
and
and IP-805.
However, the inspector
concluded that this was the result of an
individual failure,
as
opposed to
a programmatic
one.
Additionally, the
inspector
noted that the conditions which constituted
the nonconformance
were licensee identified and were aggressively
addressed.
This failure
constitutes
a violation of minor safety significance
and is being
treated
as
a Non-Cited Violation, consistent with Section
IV of the
NRC
(NCV 335,389/96-06-03,
"Failure to Promptly Document
28
E7
E7.1
Non-Conforming Conditions" ).
guality Assurance
in Engineering Activities
0 en
Unresolved
Item 335 96-04-05
37551
URI 96-04-05
documented
a number of findings observed
during system
walkdowns in March that suggested
a potential configuration control
weakness.
In order to determine
whether or not
a programmatic
weakness
existed,
the inspectors
expanded
the walkdowns to include the
ICW
systems for both units.
After completing the
ICW system walkdown and
reviewing the results of previous
IA and
CS system walkdowns, the
inspectors identified
a design control issue.
On April 18, the inspector discussed
with engineering
the numerous Unit
1
ICW discrepancies
between
the
UFSAR, Engineering
Drawings,
and
PC/M
341-192
(which modified the
ICW pumps'ubrication
sources).
On April
23, the licensee
performed
an as-built configuration check at which time
it was determined that flow limiting orifice SO-21-5A on Unit
1
ICW.
A CW Pump supply line was not installed
(IHE 96-035).
SO-21-5A
and
5B were two orifices installed
by this
PC/M on both
ICW headers
to
limit the non-safety related
ICW flow to the
CW pumps should the non-
seismic piping fail during
a DBE.
The licensee
issued
Equipment
Qearance
number 1-96-04-369 which realigned
ICW header
B
CW pump flow
to all
CW pumps
and isolated the
ICW header
A CW pump supply line.
The
licensee
performed
(CR 96-554) which
concluded'hat
the
ICW system
was still within the design flow limits.
The
inspector
reviewed the subject
CR and found the results acceptable..
An investigation
by the licensee
was unable to definitively conclude
whether the orifice plate
had not been installed during the design
modification or had not been reinstalled during
a subsequent
maintenance
activity which replaced
a portion of piping.
The inspector
concluded
that the failure to ensure that the flow limiting orifice SO-21-5A was
installed
was
a configuration management
control problem.
This licensee
identified and corrected violation is being treated
as
a Non-Cited
Violation consistent
with Section VII.B.1 of the
(NCV 335/96-06-04,
"Unit
1
ICW Flow Orifice Found Hissing" ).
Three
PC/Ms reviewed
by the inspector during system walkdowns were not
properly implemented:
~
PC/M 109-294
On January
6,
1995, the licensee
closed out
PC/M 109-294 [Setpoint
change to the Hydrazine
Low Level Alarm (LIS-07-9)] without
assuring that affected procedure
ONOP 2-0030131,
"Plant
Annunciator Summary,"
was revised.
This resulted
in the summary
for annunciator
S-10,
"HYDRAZINE TK LEVEL LO," showing
an
incorrect setpoint of 35.5 inches.
29
~
PC/H 268-292
On February
14,
1994, the licensee
closed out
PC/H 268-292
[ICW
Lube Water Piping Removal
and
CW Lube Water Piping Renovation]
without assuring that affected
procedure
ONOP 2-0030131,
"Plant
Summary,"
was revised.
This resulted
in the
summary
for annunciator
E-16,
"CIRC WTR PP
LUBE WTR SPLY
BACKUP IN
SERVICE," incorrectly requiring operators verify the position of
valves HV-21-4A 5 4B following a SIAS signal
using control
room
indication.
These valves
no longer received
a SIAS signal,
were
deenergized,
and
had
no control
room position indication.
~
PC/H 341-192
On Hay 16,
1994, the licensee
closed out
PC/H 341-192
[ICW Lube
Water Piping Removal
and
CW Lube Water Piping Renovation].
The
as-built
Dwg. JPN-341-192-008
was not incorporated
in Dwg. 8770-G-
082,
"Flow Diagram Circulating and Intake Cooling Water System,"
Rev ll, sheet
2, issued
May 9,
1995, for PC/H 341-192.
This
resulted
in Dwg.
No 8770-G-082 erroneously
showing valves
I-FCV-
21-3A L 3B and associated
piping still installed.
In a majority of the cases,
the Engineering
Package
did not specifically
identify which documents
required updating
and in all cases
there
was
no
indication that
an as-built verification of drawings or procedures
was
either required or performed prior to closeout.
The inspector
identified this as
a weakness
in implementing
PC/Hs which failed to
assure
the correct translation of the design basis into drawings
and
procedures.
These failures to incorporate
design
changes
into applicable
drawings
and procedures
are identified as additional
examples of URI 96-
04-05.
At the close of the inspection period, the licensee
was aggressively
pursuing
a program to identify any other configuration problems
and
correct programmatic
weaknesses
in this area.
Activities initiated by
the licensee
included:
The Configuration Management
Control
Group revised gI 3-PR/PSL-l,
"Design Control," as part of corrective action to STAR 8952066
issued
December
4,
1995, which identified that the
PC/H closeout
process
was inadequate.
This revision incorporated
the process
employed at the licensee's
Turkey Point facility.
The process:
2.
3.
Revises
PWO closeouts,
gC reviews,
and completion of
walkdowns, if required.
Initiates
a more timely update to JPN drawings at
ITOP
completion.
Documents identification and completion of PHT, Procedures,
and Training for PC/M closure.
PHAI 96-03-311,
due June 8,
was to address
additional
concerns
in
this area.
30
S2
~
Engineering
issued
CR 96-798 to perform
a generic review of the
.
complete plant/engineering
change
process
and identify necessary
corrective actions.
The inspectors
broadened
the scope of this review to include instrument
setpoints
affected
by PC/Hs.
Pending completion of this phase of the
review, this will remain
an URI.
IV. Plant
Su
ort
Staff Knowledge and Performance
in EP (93702)
One non-conservative
emergency classification
was identified in this
report.
See
paragraph
01.2 of this report for details.
Status of Security Facilities
and Equipment
(71750)
On Hay 11, the inspector
conducted
an after hours walkdown of portions
of the protected
area perimeter.
The inspector
found the fence to be in
good repair, lighting levels to be adequate,
and gates to be properly
closed
and locked.
F2
Status of Fire Protection Facilities
and Equipment
(92904)
On Hay 6 and 7, the inspector
performed
a followup inspection of several
fire protection/prevention
program deficiencies
noted in IR 95-12.
Specifically,
items 5.a. 1.A (Fire Protection Training, gualification and
Requalification)
[see section
F5] and 5.a.3.B.(2)
(Routine monthly fire
protection surve'illances
on fire extinguishers
and hoses).
The second
item involved
a review of the monthly fire extinguisher
inspection
and included
an observation that the extinguisher installed
in Unit 2 Turbine Building lower elevation location T-44 was not the
kind described
in the Unit 2
UFSAR Table 9.5A-80 (Turbine Bui]ding Fire
Extinguishers).
The licensee
corrected this discrepancy.
The inspector
performed
a 100 percent audit of all installed fire
extinguishers
in the Unit 2 Turbine Building lower elevation.
Of the
eighteen installed,
three at locations T-13, T-16 and T-18 were not of
the kind described
in the Unit 2
UFSAR Table 9.5A-BD (Turbine Building
Fire Extinguishers).
This discr epancy
was identified to the Fire
Protection Supervisor.
The licensee identified two additional
instances
of installed fire extinguishers
not of the kind described
in the Unit
1
UFSAR Table 9.5A-BD at locations T-8 and T-12.
Both discrepancies
are
documented
in
CR 96-748
and 96-749.
The fact that
a previous discrepancy
of this nature
was identified in IR
95-12, led the inspector to conclude that
no apparent
followup was
performed.
The licensee
now documents
discrepancies
identified by
inspectors
using Condition Reports.
This issue will be tracked
under
a
URI.
See
paragraph
X.1.2.
1
F5
31
Fire Protection Staff Training and gualification (92904)
On Hay 6 and 7, the inspector
performed
a followup inspection of several
fire protection/prevention
program deficiencies
noted in IR 95-12.
Specifically,
items S.a. 1.A (Fire Protection Training, gualification and
Requalification)
and 5.a.3.B.(2)
(Routine monthly fire protection
surveillances
on fire extinguishers
and hoses)
[see section F2].
The first item involved
a review of the methodology
used to track the
status of Fire Brigade Medical Examinations.
The licensee
added
a
separate
data field to the
REHACS computer printout for Fire Brigade
Physicals.
The inspector reviewed both
a current
REHACS printout and,
the
Emergency
Team Roster
issued April 11.
The Emergency
Team Roster
was issued monthly listing Primary Radiation,
Primary First Aid 8,
Personnel
Decontamination,
Interim First Aid 5 Personnel
Decontamination
Teams
as well as the Fire Team members.
Eleven of the sixty-two Fire
Team members listed
showed expired annual
medical
examinations
on
REHACS.
The inspector verified through
an independent
review of
individual medical files that these
Fire Team members
medical status
shown by
REHAC was accurate.
Check Sheet
1
(AP 1-0010125,
Rev 107,
"Schedule of Periodic Tests,
Checks
and Calibrations"
- later converted to
OP 1-0010125,
Rev 0) was
, completed for each shift.
Item 2A of this check sheet listed the Fire
Team Leader
(NWE) and the five members of the Fire Team.
The inspector
reviewed all Check Sheet
1's for the month of April and determined
the
following:
1.
Nine of the eleven Fire Team members with expired medicals
were
assigned
a total of sixty shifts.
2.
Two Fire Team Leaders
not listed on the Emergency
Team Roster
were
assigned
a total of thirty-one shifts.
3.
One Fire Team member with an expired medical not listed
on the
Emergency
Team Roster
was assigned
one shift.
A cursory review of REHACs further
showed that not all licensed
operators
were not current
on the biannual respirator physical,
respirator fit, and
SCBA training.
The inspector notified the on-shift
NWE and
NPS of the
above findings.
The licensee
immediate corrective actions
included
a review of the
medical status of the on-shift Fire Team members
and initiation of a
root cause
investigation.
CR 96-679
was written to document the
results.
The licensee's
failure to adequately
monitor the status of the fire
brigade
members
annual
physical
examinations
is identified as
a
violation VIO 335,389/96-06-05,
"Failure to Maintain gualifications of
Fire Brigade Hembers".
f,
32
The inspector
reviewed
and agreed with the investigation results
documented
in the subject
CR.
This investigation
concluded that the
process
used to document
and track the qualification of the fire brigade
members
was fragmented,
and where available,
not effectively utilized.
The inspector
noted that
a large portion of the administrative control
was previously exercised
by an individual in the Operations
Department
who tracked
and scheduled training for operators.
This individual has
since retired from FPL in February of this year at which time medical
examinations,
respirator fits, and
SCBA training was
no longer tracked
by the Operations
Department.
V. Mana ement Meetin
s and Other Areas
Xl
Review of UFSAR Commitments
X1.1
A recent discovery of a licensee
operating their facility in a manner
contrary to the
UFSAR description highlighted the need for additional
verification that licensees
were complying with the
UFSAR commitments.
While performing the inspections
which are discussed
in this report the
inspectors
reviewed applicable portions of the
UFSAR that related to the
areas
inspected.
The inspectors verified that the
UFSAR wording was
consistent with the observed plant practices,
procedures,
and
'arameters.
Results
from System
Walkdowns
Minor deficiencies
were noted with respect to the Intake Cooling Water
System walkdowns performed during this period.
These
issues
were
forwarded to the'icensee
for resolution.
They were
as follows:
Unit
1
UFSAR Table 7.3-2 "ICW Hdr.
A Disch. to
TCW Heat Exchanger
Isolation Valve HV-21-2" is incorrect.
Should read
"ICW Hdr.
B
Disch...."
Unit
1
UFSAR Figure 9.2-1a,
"Flow Diagram Intake Cooling Water
Lube Water System,"
has not been revised to show
ICW/CW
modifications performed
by PC/M 341-192.
Unit
1
UFSAR Table 7.4-1,
"Instruments
Required to Monitor Safe
Shutdown,"
under Intake Cooling Water
System
has not been revised
to delete
1
"3)
Intake cooling water
pump lube water pressure
FIS-21-3A, 3B, 3C,
3D, 3E,
3F (Non-safety)"
Unit
1
UFSAR Figures 7.4-9,
10 and
11, "Intake Cooling Water
Pump
lA, 1B and
1C Logic," have not been revised to remove annunciator
E-15 logic which has
been
spared out.
33
Unit
1
4B operation
Section 7.4.1.5 describes
control of ICW system operation
as
follows:
"Following actuation of the pumps,
the intake cooling water system
is designed
to operate with automatic temperature
controlled
modulation of the intake cooling water flow through the component
cooling heat exchangers.
The heat
exchanger outlet flow control
valves
(TCV 14-4A and
TCV 14-4B) are controlled by pneumatic
temperature
controllers TIC-14-4A and TIC-14-4B which sense outlet
temperature
on the component cooling water side of the heat
exchangers.
The temperature
controllers
are provided for
efficient system operation during normal plant operation.
The
control valve pneumatic controls
have
been designed
and qualified
as seismic
Class
I to assure
proper operation of the control
valves during safe
shutdown.
As temperature
increases,
intake
cooling water flow is automatically increased.
The control valves
are pneumatically operated
and fail wide open
on loss of
instrument air.
In the event of loss of air the intake'ooling
system will operate
in the full unmodulated
flow mode."
Section 9.2. 1.5 describes
instrumentation
application
as follows:
"The second
automatic valve in the system is the butterfly valve
(one in each
at the outlet of the component cooling water
heat exchanger.
This valve automatically controls outlet water
flow from the heat exchanger.
It is modulated
opened
and closed
according 'to the outlet water temperature
of the shell side of the
component cooling water heat exchanger."
Although normally operated
in automatic,
the manual
mode of
controller operation is allowed.
Unit 2 UFSAR Table 9;2-3, "Intake Cooling Water System
Instrumentation Application," incorrectly lists the lubricating
water strainer differential pressure
instruments
as PDS-21-25AI,-
25A2,
-25B1,
25B2 with a range of 0-3 psig.
This should read
PDIS-21-25-1A1,
-1A2, -181,
-1B2 with a range of 0-3 psid.
This
also applies to the range for the
TCW inlet strainer differential
pressure
instruments
PDIS-21-7A, -78.
Unit 2 UFSAR Section 9.2. 1.2,
"System Description," in the first
paragraph
states,
"Butterfly valves
I-TCV-14-4A and 4B,
(one in
each header),
located at the outlet of the component cooling water
heat exchanger,
automatically control outlet water flow from the
heat exchanger.
They are modulated
by the outlet water
temperature
of the shell side of the component cooling water heat
exchanger."
Although normally operated
in automatic,
the manual
mode of
controller operation is allowed.
34
~
Unit 2
UFSAR Section 9.2. 1.2,
"System Description," in the second
paragraph
states,
"The turbine cooling water heat
exchangers
and.
blowdown heat exchangers
are supplied
by nonessential
which are automatically isolated
on SIAS by valves T-MV-21-2 and
3. If these
valve operators
were to be reopened locally after
a
postulated
accident,
an alarm and valve open indication is
produced
in the control
room.
Under administrative control
and
procedures,
the control
room operator in such
a case
would reclose
the valves from the control room."
The only alarms that the inspector identified were
E-22 and
E-23
ICW HDR A (B) MV-21-3 (2) OVRLD/SIAS FAIL TO CLOSE which under
Operator Action - Valid Alarm state:
2.
(B) Manually close valve (if required).
It was unclear
how the procedural
guidance
implemented the
described
design feature.
~
Unit 2 UFSAR Table 7.3-2,
"ICW Hdr.
A Disch. to
TCW Heat Exchanger
Isolation Valve MV-21-2," is incorrect.
Should read
"ICW Hdr.
B
Disch...."
10
CFR 50.71(e)
requires
the licensee to periodically update the
six months after each refueling.
The Unit
1
UFSAR Figure 9.2-la, Table
9.2-1,
Table 7.4-1,
Figures 7.4-9,
10 and ll were not updated following
completion of the Unit ICW/CW modifications.
These
items are
added to
URI 335,389/96-04-09,
"Failure to Update
UFSAR", pending further
NRC
review.
X1.2
Results
From Other Inspection Efforts
While performing inspections
described
in this report, the following
UFSAR inconsistencies
were identified:
-The inspector noted,
in reviewing
UFSAR section 4.2.3.2.3(b)(1),
that the minimum time required for CEAs to drop at normal
operation
and upset conditions from any withdrawn position to 90
percent of full insertion
was specified
as 2.5 seconds.
The
inspector
noted that this value differed from UFSAR Table 4.2-1,
which specified
a maximum time of 3. 1 seconds,
consistent with TS.
The inspector
brought this to the attention of the licensee.
The
issue
was documented
in
CR 96-0898.
~
An audit of Unit 2 fire extinguishers
identified three locations
which differed from the
See
paragraph
F2 of this report.
X1.3
Conclusion
These
items are
added to URI 335,389/96-04-09,
"Failure to Update
UFSAR", pending further
NRC review.
35
X2
Exit Heeting
Summary
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on Nay 13.
The licensee
acknowledged
the findings presented.
No dissenting
comments
were
received.
36
PARTIAL LIST OF
PERSONS
CONTACTED
Licensee
Bladow, W., Site guality Manager
Bohlke,
W., Site Vice President
Buchanan,
H., Health Physics Supervisor
Burton, C., Site Services
Manager
Dawson,
R., Business
Manager
Denver,
D., Site Engineering
Manager
Fincher,
P., Training Hanager
Frechette,
R., Chemistry Supervisor
Fulford, P., Operations
Support
and Testing Supervisor
Harple, C., Operations
Supervisor
Heffelfinger, K., Protection Services
Supervisor
Holt, J.,
Information Services
Supervisor
Johnson,
H., Operations
Manager
Kreinberg, T., Nuclear Material
Management
Superintendent
Harchese,
J.,
Maintenance
Hanager
O'Farrel,
C., Reactor Engineering Supervisor
Olson,
R., Instrument
and Control Maintenance
Supervisor
Pell, C., Outage
Manager
Scarola, J., St. Lucie Plant General
Manager
Weinkam, E., Licensing Manager
Wood, C., System
and Component
Engineering
Manager
White,
W., Security Supervisor
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
chemistry/radiation,
and corporate
personnel.
IP 37551:
IP 40500:
IP 61726:
IP 62700:
IP 62703:
IP 71707:
IP 71750:
IP 73052:
IP 73753:
IP 92902:
IP 92904:
IP 93702:
37
INSPECTION
PROCEDURES
USED
Onsite Engineering
Effectiveness of Licensee
Controls in Identifying, Resolving,
and
Preventing
Problems
Surveil,lance
Observations
Maintenance
Program
Implementation
Maintenance
Observations
Plant Operations
Plant Support Activities
Inservice Inspection
- Review of Procedures
Inservice Inspection
Followup - Maintenance
Followup - Plant Support
Prompt Onsite
Response
to Events at Operating
Power Reactors
~oened
50-335,389/96-06-05
Closed
50-389/95-01-02
50-335/96-06-01
50-335/96-06-02
50-335)389/96-06-03
50-335/96-06-04
Discussed
50-335)389/96-04-05
50-335)389/96-04-09
ITEMS OPENED,
CLOSED,
AND DISCUSSED
"Failure to Maintain gualifications of Fire
Brigade Members"
"Failure to Follow Procedure
2-LOI-T-89,
paragraph
4.a.4"
"Failure to Consider Fire Barrier Operability in
Engineering
Package"
"Failure to Document Verification of Current
Procedure
Revisions"
"Failure to Promptly Document Non-Conforming
Conditions"
"Unit
1
ICW Flow Orifice Found Hissing"
"Configuration Control
Management"
"Failure to Update
LIST OF ACRONYHS USED
Auxiliary Building
ASEA Brown Boveri
(company)
Administrative Procedure
38
ANSI
ASNE Code
ATTN
BRPV
CFR
CR
CWD
DWG
Eg
F
FR
FRG
GL
GHP
gpm
HVS
ICI
ICW
i.e.
IHE
IP
IR
JPN
lb
LCO
Authorized Nuclear Inspector
American National
Standards
Institute
Air Operated
Valve
Administrative Procedure
American Society of Hechanical
Engineers Boiler and Pressure
Vessel, Code
Attention
Boiler and Pressure
Vessel
Cubic Centimeter
Component
Cooling Water
Combustion
Engineering
(company)
Control
Element Assembly
Code of Federal
Regulations
Condition Report
Containment
Spray
(system)
Chemical
5 Volume Control
System
Circulatory Water
Control Wiring Diagram
Design Basis
Demonstration
Power Reactor
(A type of operating license)
Drawing
Emergency Action Level
Emergency
Core Cooling System
Emergency Diesel
Generator
Emergency Operating
Procedure
Engineering
Package
Emergency
Plan Implementing Procedure
Electric Power Research
Institute
Environmentally qualified
Engineered
Safety Feature
Engineered
Safety Feature Actuation System
Fahrenheit
The Florida Power
& Light Company
Federal
Regulation
Facility Review Group
[NRC] Generic Letter
General
Haintenance
Procedure
Gallon(s)
Per Minute (flow rate)
High Pressure
Safety Injection (system)
Heating
and Ventilating Supply (fan, system, etc.)
Incore Instrument
Intake Cooling Water
that is
In-House-Event
Report
Inspection
Procedure
[NRC] Inspection
Report
InService Inspection
(program)
(Juno Beach).,Nuclear
Engineering
pound
TS Limiting Condition for Operation
Level Control Valve
0
39
H&TE
MMP
HWO
NPF
NRC
NUHARC
NWE
ONOP
PC/M
PDIS
PHAI
psia
psld
Pslg
PSL
Pub
PWO
QI
RCO
.RCS
REMACS
Rev
RII
SNPO
St.
SwRI
Level Indicating Switch
Letter of Instruction
Low Pressure
Safety Injection (system)
Low Temperature
Overpressure
Protection
(system)
Measuring
& Test Equipment
Mechanical
Maintenance
Procedure
Motorized Valve
Haster
Work Order
NonCited Violation (of NRC requirements)
Non Destructive
Examination
Non-Licensed
Operator
Notice of Unusual
Event
Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor
Nuclear Regulatory
Commission
Nuclear Management
and Resources
Council
Nuclear Watch Engineer
Off Normal Operating
Procedure
Protection Circuit
Plant Change/Hodification
Pressure
Differential Indicating Switch
NRC Public Document
Room
Plant Management Action Item .
Post Maintenance
Test
Pounds
per square
inch (absolute)
Pounds
per square
inch
differential)
Pounds per'quare
inch (gage)
Plant St. Lucie
Publication
Plant Work Order
Quality Assurance
Quality Control
Quality Instruction
Reactor Auxiliary Building
Reactor Control Operator
Radiation
Exposure Monitoring and Access Control System
Revision
Region II - Atlanta, Georgia
(NRC)
Reactor Protection
System
Self Contained
Breathing Apparatus
Shut
Down Cooling
Spent
Fuel, Pool
Safety Injection Actuation System
Senior
Nuclear Plant [unlicensed]
Operator
Safety
Parameter
Display System
Senior Reactor [licensed] Operator
Saint
St. Lucie Action Request
Southwest
Research
Institute
TCW
TEDB
TS
VAC
40
Temperature
Control Valve
Turbine Cooling Water
Total
Equipment Data Base
Technical Specification(s)
Updated Final Safety Analysis Report
[NRC] Unresolved
Item
Volts A1ternating Current
Volume Control Tank
Violation (of NRC requirements)
Attachment:
Spent
Fuel Storage
Data Table
ATTACHMENT 1
UNIT 1 SPENT FUEL STORAGE DATA TABLE
Facility
SFP Related Technical
Specifications
Name: St. Lucia
Parameters:
Electrical Power Systems - Shutdown
(3.8.1.2)
Unit Number: Unit 1
Limiting Value or Condition:
Specifies required A.C. power during movemant of
irradiated fuel or crane operation with loads over tha
Decay Time (3.9.3)
?72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> prior to fuel rnovamant
Crena Travel - Spent Fuel Storage
Pool Building (3.8.7)
Loads > 2000 Ibs shell not be moved over irradiated
fuel eesemblias
in tha storage pool
Storage Pool Water Level (3.9.11)
Maintain a23 feet water over fuel seated in the
storage racks
Fuel Pool Ventilation System - Fuel Storage
(3.8.12)
Ona fuel pool ventilation system operabla whenever
irradiated fuel is in tha spent fuel pool
Spent Fuel Cask Crena (3.8.13)
Maximum load handled by cask crane shall be S25
tons
Decay Time - Storage Pool
(3.9.14)
Irradiated fuel assemblias
shell have decayed E1180
hours or ~1490 hours prior to movamant of cask into
cask compartment
Fuel Storage Criticality (5.6.1.e and
5.6.1.b)
Maintain k
S0.95, decor(bas nom)nai storage pitch,
pool boron concentration ) 1720 ppm, boreflax
installed in Region
1 end Region 2 storage racks;
specifies fuel assembly enrichment/exposure
limits for
storage in Region
1 end Region 2
Fuel Storage Drainage (5.6.2)
Fuel Storage Capacity (5.6.3)
Fuel pool can not be drained below elevation 56 feat
Storage oapacity is M1706 fuel essamblias
SFP Structure
Location: Above grade in fuel handling
building (FHB). Fuel pool floor elevation is
21.5'; cask area floor elevation is
18.0'8770.G.074
Rev 10)
Saismio Classification of SFP Structure and Building:
FHB & SFP designed
es e seismic Class
I structure
(UFSAR 3.8.1.1.2); Spent fuel racks designed to
~aisrrMO Category I requirements
(UFSAR 9.1.2.2.3)
Gross SFP Volume: 47008 fte (including
cask storage area) to 60'ormal water
level.
Derived from drawings 8770%965
Rav
1 & 8770-G-074 Rav 10.
SFP Temperature for Stress Analysis: Normal Operating
'hermal
loads analyzed with 150'
water at weil and
32'
external air temperature; Aocident oonditions
used bulk water temperature of 217'
with external
eir temperature of 40'. Both one)yeas assumed
linear
thermal gradients.
(PSL1 rereck lioansa amendment,
Safety Analysis Report. June 12, 1987, popes 4-9 & 4-
10)
Leakage Collection
Liner Type: Stainless'teal
type 304; fuel
pool floor 0.25
plate, liner walls 0.188
plate, cask pit floor 1.0
plate.
(8770-
4965
Rev
1 + UFSAR page 9.1-4e)
Leakage Monitoring: Network of stainless steel angles
attached to the outside of tha pool liner wells end the
underside of tha pool liner floor (8770-G-830 sh.2, Rev
2 & 8770.G-894 Rev 5).
Drainage Prevention
Location of Bottom Drains: Nona.
(8770.G.830 sheet 4, Rav 1. 8770.G 830
sheet 1, Rav'4, and sheet 2, Rav 2)
Elevation of Gate Bottom Relative to Stored Fuel:
Gate
bottom is et elevation 36.25'8770 G-830 sh. 2).
This is above the top of fuel seated in tha racks.
UNIT 1. SPENT FU EL STO RAG E DATA TABLE
Siphon Prevention
Lowest Elevation of Connected
Pipinp
Rolative to Fuel: Above top of fuol. Fuol
pool coolinp suction lino penatratas
pool
(inst at elevation 58.0'; return line
panatratas
pool liner et elevation
59.26'8770-G-830
sheot 1).
Fuel pool
puriflicotion ay<<tom piping panatratas
fuel
pool liner at an elevation of 68.0'nd
59.0'8770.G.830
sheet 2) Top of fuel
assembly seated in storage rocks is
35.0'.
Anti.Siphon Dovicos: Fuel pool return lino has 0.5
hole
and purification suction line has 0.25'olo p(acod
1'olow
normal water lovel.
(8770.G.078, sheet 140, Rav 9)
Make.up Capability
Safety.Related
Source:
intake coolinp
w<<ter
Normal Source:
on fuel pool boron concantr<<tion
(OP 1.
0350020 Rev 21, page 11).
Saismio Classification snd Quality Group:
Intake
cooling water makeup capability is Saismio Category
I
group C. (8770-G-082, sh. 1, Rev 43)
Reactivity
Limits on ~ and Enrichment: For both fuel
pool regions k~ 60.95 with the pool
flooded with unborotad water. Fresh fuel
limited to C4.6 w/o; Region 2 hea
additional restrictions booed on T.S. Figure
6.8-1
Soluble Boron Credit for Accidents: Yas, assembly
mislood (PSL1 rerack license emandmant,
Safety
Andysis Report, June 12, 1887, pages 3-2 & 6.8).
Reactivity Control
Solid Noutron Poisons:
Boraflax sheets
placed between storage calls in both
Region
1 ond 2.
Number of Fuel Storage Zones: Two based on
assembly bumup and initid enrichment.
ared or Split Spent Fuel Pools
SFP Design Inventory Cases
No. of SFPs:
Ona
Normah 1620 ossambliee
(PLA submittal
to support PSL1 fuel pool rerack, pages 3-
28 & 3-31, June 12, 1987).
No. of SFPs Recaivinp Discharge from a Single Unit:
Ona; all Unit 1 fuel is in Unit 1 pool.
Emergency/Abnormal:
1857 aasamblias
(PLA
submittd to support PSL1 rerack, pages 3-28 & 3-31,
June 12,'1987)
SFP Design Heat Load (MBTU/hr)
and Temperature
('F)
Normd: 18.42EB; 133.3'F with 1 fuel
pool cooling pump. (PLAsubmittd to
support PSL1 fuel pool rarock, page 3-33,
June 12, 1987)
Emergency/Abnormal: 33.71EB;
150.8'
with 2 fuel
pool cooling pumps; 187'
with 1 pump in oporation
(Sof<<ty Evd. by NRR rd<<tod to License Amendment
91, M<<di 11, 19SS)
SFP Cooling System
No. of Trains: 2 pumps in pardlel:
1 hast
exchanger.
No. of SFPe Served by Each Train: one
(8770-G-078, ah. 140, Rev 9)
ucensed to Withstand Single Active Component
Failure: Yes. Sae section 5.2.1, Hest Removal
~Ce sbitit)(, from SER issued by NRC offlica of NRR
related to Amendinent 91 to Unit 1, doted March
11,19SS.
Electrical Supply to SFP Cooling
System Pumps
Qualification ond Independence
of Power
Supply:
SFP Cooling pump 1A is a load on
the essential portion of 480V motor
oontrol oantsr 1A-8. SFP Coolinp pump 18
is a load on the essential section of motor
control oanter 18-8. These MCC's ore not
class 1E. (8770 G-275 sheet 8, Rev 8)
Load Shod Initiators: Undarvoltago or ovarcurrent.
(8770 G-2'76 sheet 1, Rev 12, & sheet 8, Rev 8)
Backup SFP Coolinp
System Nome:
None.
Qualification: N/A.
SFP Hast Exchanger Cooling Water
(8770 G-083, sheet 1, Rav 42)
System Noma: Component Cooling Water
Qualification:
Some portions of CCW important to SFP
coolinp are eeismio I safety class C; others ore safety
aloes D.
Attachment
3
UNIT 1 SPENT FUEL STORAGE DATA TABLE
Secondary Cooling Water Loop
(8770.G.082, sheet 1, Rev 43)
System Name: Intake Cooling Water
Qual(5cetion:
Seismio
I safety doss C
Ultimate Hest'Sink (UHS)
SFP Cooling System Hast
Exchanger Performance (Highest
Capability Hest Exchanger if not
identical)
(8770-2017 Rav 2)
Typo: Atlantic Ocean/Big Mud Creek
Design Heat Capacity (BTU/hr): 32.0E6
SFP Side Row: 1.50E6 Ibm/hr
SFP Temperature:
150'F
SFP Cooling Loop Return Tamp: 128.7'
UHS Design Temperature:
85'
(UFSAR p. 8.2-2)
Type: tube end shell
Cooling Water Row:
1.78ES Ibm/hr
Cooling Water Inlet Temp: 100'
Cooling Water Outlet Tamp:
118'FP
Related Control Room Alarms
(ONOP 1-0030131, Rev 62)
Parameter(s):
Fuel Pool High/Low Level,
Fuel Pool High Temperature,
Fuel Pool
Pump Discharge Header Pressure-Low,
Fuel Pool Pumps Motor Overload, Fuel Pool
Room High Temperature,
Fuel Pool Exh.
HVE Low Row/Motor Overload, CCW Flow
to Fuel Pool Heat Exchanger High/Low.
Noble Gee Radiation Alert.
Setpoint: a 2'rom nomind level, 137.5', 18 psig,
pump trips, 110~ F, (13800 ofm, W3600 gpm or
S 2850 gpm, ee established by Chemistry Dept.
Location of Indiootions
SFP Lovol: Nono
SFP Temperature:
Local roedout (8770-G-078, Sheot
140, Rav 8)
SFP Cooling System Autometio
Pump Trips
FP Boiling:
Parameter(s):
Nona other then tha
alactrioel trips listed obovo.
Staff Aooaptenoa of non-Seismio
Cooling System Based on Seismic
Category
I SFP Ventilation System: Fuel
pool oooling system end fuel pool
vontilation system era not seismio oetagory
I. (8770:G 879 Rav 28 & 8770.G-125 Sh.
FS.W-3)
Indapandanca:
independent alactriod tripe for each
pump. (8770.G-275, sheet 8, Rav 8)
Off.site Consequenoes
of SFP Boiling Evduetad:
Yae.
(L-87-537, December 23, 1887, Attachment 6)
If Yas, Was Filtration Credited: No.
SFP/Reactor System Separation
Heavy Load Handling
Separation of SFP Operating Boor from
Portion of Aux. or Reactor Bldg. that
oontains Reactor Safety Systems:
ares completely enclosed: ventilation
system directs dr to FHB stack.
SFP Ares Crone Qudified to Single Failure
Proof Standard IAW NUREG-0612 end/or
NUREG-0554: No. (FSAR Tables 9.1-6 and
8.6-1)
Separation of Units et Multi-UnitSites:
St. Lucis Units
1 & 2 have separate fuel handling buildings end
ventilation systems.
Routine Spent Fuel Assembly Transfer to ISFSI or
Alternate Wet Storage Location:
No
Attachment
UNIT 1 SPENT FUEL STORAGE DATA TABLE
Operating Practices
Administrative Control Limit(s) for SFP
Temperature during Refueling: None based
on most recent Rev to fuel shuffle
procedure.
Frequency of Full Coro Off loads: 650
percent of outapes
Typo of Off.load Performed durinp most
recant refueling: partial cora off-load (fuel
shuffle)
Administrative Control Umits for SFP Cooiinp System
Redundancy
and SFP Make-up System Redundancy:
OP
1-1600023, Rav 68, page 8, requires Fuel Pool Cooling
& Purification System to ba in normal operation prior to
baginninp refueling evolution.
This means that electric
power required to ba svaleb(e to both fuel pool coolinp
pumps (OP 1-0360020, Rav 21, pepe 2 & 3). No
requirements for redundancy of makeup source.
Administrative Controls on Irradiated Fuel Decay Time
prior to Transfer from Reactor Vessel to SFP:
Yes. (OP
1-1600023, Rev 68, page 20 of 60, Survaillances
Performed Durfn
Rafuelin
For Units with planned refueling outsgas scheduled to
begin before April 30, 1996, type of Off-load planned
for next refueling and planned shutdown date:
Full
core; expected shutdown 4/28lge.
Attachment
0
UNIT 2 SPENT FUEL STORAGE DATA TABLE
Facility
Nemo: St. Lucia
Unit Number: Unit 2
SFP Related Technical
Spacifioations
Parameters:
A.'C. Sources - Shutdown (3.8.1.2)
Limitinp Value or Condition:
Specifies required A.C. power durinp
movement of irradiated fuel or crane operation
with loads over the fuel storage pool.
Decay Time (3.8.3)
Reactor subcriticd a72 hours prior to fuel
movement in RPV.
Crane Travel - Spent Fuel Storage Pool
Buildinp (3.9.7)
Loads )1800 Ibs prohibitod from travel over
fuel assemblies
in fuel storogo pool.
Water Lava) - Spent Fuel Storage Pool
(3.9.11)
Maintain 823 feat water over top of irradiated
fuel sooted in storage racks.
Spent Fuel Cask Crone
(3.9.12)
Maximum load handled by cack crone shdl be
S 100 tons.
Fuel Storage Criticality (5.8.1.s)
Maintain k
~0.85, specifies nominal pitch of
assemblies
in storogo racks, raquiroe pool
boron concentration E1720 ppm, defines
Region
I end Region II enrichment/bumup
requirements for storoga.
Fuel Storepe Drainage
(6.8.2)
SFP ehdl not be drdned below elevation 68
feat.
Fuel Storage Capacity
(6.8.3)
SFP shdl contain <1078 eesembliee.
SFP Structure
Location: Above grade in fuel handling
buildinp (FHB). Fuel pool floor devotion ie
21.60';
oeek area floor devotion is 17.6'.
(2988-G-073
Rav 18 & 2998-G-074 Rav
12)
Seismic Classification of SFP Structure end
Building: FHB & SFP designed
oe eaiemio Class
I structure (UFSAR 3.8.4.1.3 & 2998.G.078
~heat 140, Rev 6). Spent fuel rocks designed
to seiemio Category
I requirements
8.1.2.1)
Gross SFP Volume: 62809.(ts (includinp
oosk storage ares) to 80'ormal water
level. (2998.8584
Rev 3 & 2998-G-074
Rav 12)
SFP Temperature for Stress Andysis: SFP
designed for s water temperature of 212'
during tho winter. (UFSAR p. 8.1-6a)
Leakage Collection
uner Type: 304 Stainless steel (UFSAR p.
8.1-4); pool liner wdls 0.188
plate, pool
floor liner 0.825 . Cask ares floor plots
1.0., ooek ares wdl plate 0.6
. (2998.G-
830 sheet 1, 2aaa-ea51
Rev 3, 2998-
8952
Rev 4,
& 2998.ea53
Rev 3)
Leakage Monitoring: Network of stainless steel
ongles attached to the outside of the pool liner
walls and underside of tha pool liner floor.
(2998-G-884
Rav 9)
Drdinape Prevention
Location of Bottom Drdne: None, (2998-
G-830 sheet 1, Rev 7)
Elevation of Gate Bottom Relative to Stored
Fuel: Above top of stored fuel. Gets bottom
elevation is 38.25'2888.6951
Rev 3) ~ Unit
2 fuel sesembliea
aro 168.6
lonp.
Top of fuel
sooted in the storage racks is elevation
35.2'.
(2998.18511
Rav 0)
Attachment
UNIT 2 SPENT FUEL STORAGE DATA TABLE
Siphon Prevention
Lowest Elevation of Connected
Piping
Relative to Fuel: Above top of fuel.
Fuel
pool cooling auction line penetretes
pool
liner et elevation 68.0'2998.6953
Rav
3); return line panatrstes
fuel pool liner at
eleVation 59.25'2998 6952
Rev 4).
Fuel pool purifioetion system piping
penatrstes
fuel pool liner et en elevation of
58.0'nd 59.0'2998-8951
Rev 3 &
2888-7415
Rav 2). Top of fuel storage
racks is
36.25'.
Anti-Siphon Devices:
Fuel pool cooling return
line hss 0,5
hole placed 1.0'elow the normal
pool water level.
Fuel pool purification suction
line has s 0.25
siphon breaker hola placed
1.21'elow the normal pool water level.
(2998 G-078 sheet 140, Rev 5)
Make up Capability
Safety Related Source:
Intake cooling
water
Normal Source:
on fuel pool boron concentration.
(OP 2-
0350020 Rav 17, page 10)
Seismio Clessificat)on and Ouslity Group:
Intake cooling water makeup capability is
Seismio category
I group C. (2898-G-082
sheet 2, Rav 40)
Reactivity
Limits on ~ end Enrichment:
For both
fuel pool regions ~ ~0.95 with the pool
flooded with unborated water.
Fresh fuel
limited to s4.5 w/o; Region II has
additional restrictions based on T.S. Figure
5.6-1.
Soluble Boron Credit for Accidents:
Yas.
(Safety Evaluation prepared by
NRR for PSL2 rarack license amendmant,
Section 2.1.3)
Reactivity Control
Solid Neutron Poisons:
No. Region I calls
contain unpoisonad
SS L-shaped inserts.
Racks use flux trap design.
Number of Fuel Storage Zones:
Two based on
assembly bumup and (nit(d enrichment.
tered or Split Spent Fuel Pools
No. of SFPs:
Ona
No. of SFPs Receiving Discharge from a Single
Unit: Ona; eil Unit 2 fuel is in Unit 2 pool.
SFP Design Inventory Cases
Normah 884 aesamblias
(12 refueling
batches) with tha most recant refueling
batch oooled for 5 days; other batches
discharged following an 18 month fuel
cycle. (CE latter L-CE-10558, September
7, 1984)
Emergency/Abnormeh
1113 aesamblias
comprising 11 refueling batches,
each of which
was discharged following an 18 month fuel
cyc(e end a full oora offload of 217 essemblias
which has cooled for 7 days.
(L-CE-10558)
SFP Design Hast Load (MBTU/hr)
end Temperature
('R (from Safety
Evaluation by Office of NRR
supporting rarack of the St. Lucis
Unit 2 fuel pool, October 16,
1984)
Normal: 16.9E6 BTU/hr; (137'
with one
pump in operation.
Emergency/Abnormal:
31.7E6 BTU/hr, (150'
with both spent fuel pumps operating.
SFP Cooling System
No. of Trans: 2 pumps snd 2 hast
axchangars.
Ehhar pump csn serve either
heat exchanger.
No. of SFPs Served by Each Train: Ona
(2998-G-078 sheet 140, Rev 5)
Ucansad to Withstand Single Active
Component Failure:
Not explicitly mentioned in
rerack Safety Evaluation prepared by NRR to
support fuel pool rereck. issued October
16,1884.
FPL's rereck PLA submittal
presented
results of both normal snd abnormal
cora offloads assuming a single failure.
Earlier
SE's (NUREG-0843, p. 9-5) give 160'
es
expected tamp. following a full cora offload
with 1 fuel pool cooling pump in operation.
Attachment
UN[T 2 SPENT FUEL STORAGE DATA TABLE
Electrical Supply to SFP Cooling
System Pumps
Backup SFP Cooling
Qualification and Independence
of Power
Supply: SFP Cooling pump 2A is e load on
tha essential portion of 480V motor
control oenter 2A-8. SFP Cooling pump
28 is a load on the essential portion of
me%or control center 28-8.
Fuel Pool
Cooling system is Class IE.
System Noma: Nona.
Load Shed Initiators: Undervoltage or
ovarcurrent.
(2988 G-276 sheet 39, Rev 3, sheet 42, Rev 4
& 2998 G-27S sheet A, Rev 5 + 2998.G.
274
Rev 12 & 2998-G-274 sheet 2, Rev 6)
Qudificetion: N/A
SFP Heat Exchanger Coding Water
(2898-G-083
Sh.1, Rav 31)
Secondary Cooling Water Loop
(2898.G-082 Sh. 2, Rav 40)
Ultimata Heat Snk (UHS)
System Noma: Component Cooling Water
System Name: Intake Cooling Water
Type: Atlentio Ocean/Big Mud Creek
Qualification:
Seismic I safety doss C
Qualification:
Seismic I safety class C
UHS Design Temperature:
86'F
(UFSAR p.
8,2.1a)
SFP Cooling System Hest
Exchanger Performance (Highest
Capability Heat Exchanger if not
identical)
(2988-16809, Rev 0)
FP Related Control Room Alarms
(ONOP 2-0030131, Rev 60)
Design Hant Capacity (BTU/hr): 32.0EB
SFP Side Flow: 1.60EB Ibm/hr
SFP Temperature:
160'
SFP Cooling Loop Return Temp: 128.7'
Parameter(s):
Fuel Pool Pump Discharge
Header Pressure Lo, Fuel Pool Pump
Overload, Hi/Lo CCW Flow to Fuel Pool
Hest Exchanger,
Fuel Pool Room Temp. Hi,
Fuel Pool Exhaust fane Lo Flow/Overload.
Fuel Pool High/Low Level or High Tamp (2
annuno. channels)
Type: tube end shell
Cooling Water Flow: 1.78EB Ibm/hr
Cooling Water Inlet Temp: 100'
Cooling Water Outlet Temp: 118'
Satpoint:
18 psig, N/A, a3700 gpm or
6 2860 gpm, 110', 0.08'g or 1130 scfm,
a138'
or RB deviation in pool water level
from nomind value (2 channels).
Location of Indications
SFP Level: Local coals
SFP Temperature:
Looal readout (2898.G-078
sheet 140, Rev 6 end 2998-G-078 sheet 100)
SFP Cooling System Automstio
Pump Tripe
Parameter(s):
Nona other then the
alectricd tripe listed above.'ndependenoa:
Independent alectricd tripe for
each pump.
(2898.G-276 sheet 23, Rev 4,
sheet 39, Rav 3, end sheet 42, Rev 4)
SFP Boiling:
Staff Acceptance of non-Seismio SFP
Cooling System Based on Seismio
Category I SFP Ventilation System:
Fuel
Pool Cooling System is Seismio Category I.
(2898-G-078 sheet 140,
Rav 6) Portions
of tha Fuel Pool Ventilation System ere
Seismio Close I, safety class 3. (2898-G-
878
Rav 22 and 2998 G.878 sheet 3,
Rav 20)
Off-site Consequences
of SFP Boiling
Evdueted:
No.
If Yee, Wae Filtration Credited:
SFP/Reactor System Separation
Separation of SFP Operating Floor from
Portion of Aux. or Reactor Bldg. that
contains Reactor Safety Systems:
area completely enclosed; ventilation
system directs air to FHB stack.
Separation of Units at Multi-UnitSitee:
St.
Lucio Unite 1 & 2 have separate
fuel handling
buildings and ventilation systems.
Attachment
UNIT 2 SPENT FUEL STORAGE DATA TABLE
Heavy Load Handling
Operating Practices
SFP Area Crane Qudifiad to Single Failure
Proof Standard IAW NUREG-0612 and/or
NUREG-0554:
No, (FLO-2999-751 snd UFSAR section
8.1.4.3.2)
Administrative Control Umit(s) for SFP
Temperature during Refueling: Yes, ensure
fuel pool temperature 6150'.
(OP 2-1600023
Rav 39, page 26)
Frequency of Full.Cora Off loads:
S50
percent of outagae
Type of Off-load Performed during most
recent refueling: full core offload
Routine Spent Fuel Assembly Transfer to ISFSI
or Alternate Wat Storage Location: No
Administrative Control Umits for SFP Cooling
System Redundancy
and SFP Makeup System
Redundancy:
OP 2-1600023
Rev 38, pages
25 & 26 requires that both fuel pool cooling
pumps and related systems be avd)able.
Makeup source from tha RWT to ths fuel pool
is also required to be available.
Administrative Controls on Irradiated Fuel
Decay Time prior to Transfer from Reactor
Vessel to SFP:
Yee. (Page 19 of OP 2-
1600023
Rev 39)
For Unite with planned refueling outages
~chedulad to begin before April 30, 1896 type
of Off.load planned for next refueling snd
planned shutdown data: N/A; next Unit 2
refueling outage tentatively scheduled for 4/97.
I,
Attachment