ML17228B361
| ML17228B361 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 12/07/1995 |
| From: | Landis K, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17228B359 | List: |
| References | |
| 50-335-95-21, 50-389-95-21, NUDOCS 9512180382 | |
| Download: ML17228B361 (59) | |
See also: IR 05000335/1995021
Text
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UNITED STATES
t
NUCLEAR REGULATORY COMMISSION
REGION II
'01
MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report Nos.:
50-335/95-21
and 50-389/95-21
Licensee:
Florida Power
& Light Co
9250 West Flagler Street
Miami,
FL
33102
Docket Nos.:
50-335
and 50-389
Facility Name:
St. Lucie
1 and
2
License
Nos.
and NPF-16
Inspection
Conducte
ctobe
through
December
2,
1995
Lead Inspector:
. Prevatte,
Senior Resi ent
Inspector
D
e Signed
Approved by:
W. Kleinsorge,
Reactor Inspector,
RII
E.
Lea, Project Engineer,
RII
M. Miller, Resident
Inspector
S.
San
'n
nior Operations Officer,
K. Lan is,
C ief
Reactor Projects
Section
3
Division of Reactor Projects
t ~
SUMMARY
Da e
igned
Scope:
Results:
This routine resident,-.inspection
was conducted onsite in the areas
of plant operations
review, maintenance
observations,
surveillance
observations,
plant support,
and followup of previous inspection
findings.
Inspections
were performed during normal
and backshift hours
and
on
weekends
and holidays.
Plant operations
area:
Two violations involving system clearance
problems
were identified.
A non-cited violation involving the failure to maintain the
log was also identified by the licensee.
'Four
weaknesses
involving not documenting deficiencies,
weak corrective
action
and procedures
were also identified.
The above problems
are
very similar to other recent inspection findings and indicate
weaknesses
in operations ability to identify and correct
deficiencies.
Operations
response
to events involving a loss of
and
a loss of main transformer cooling was good.
Overall
95i2i80382 951208
ADOCK 05000335
6
performance
in operations
was found to be in need of strong
management
and supervisory attention.
Maintenan'ce
and Surveillance
area:
One violation involving a missed surveillance for Reactor Coolant
System
boron concentration
was identified.
A non-cited violation
for this
same surveillance
occurred in October
1995.
This indicated.
a weakness
in the licensee corrective action program to prevent
recurrence.
A'large number of planned
and emergent
work activities
were completed during this refueling outage.
An emergent
problem
involving cracking of solder joints in Emergency Diesel
Generator
(EDG) control relay bases
added challenging corrective maintenance
on the EDG's.
Overall, outage
work quality was found to be
satisfactory.
Engineering
area:
No specific observation
worthy of noting was identified.
Plant Support area:
Performance
in this area continued to be satisfactory.
Within the areas
inspected,
the following violations were identified:
VIO 389/95-21-01,
"Failure to Follow Clearance
Procedures,"
paragraph
3.a.3)B.
VIO 389/95-21-02,
"Failure to Follow the Equipment Clearance
Order
Procedure
and ReqUire Independent Verification of a Technical
'Specification Related
Component,"
paragraph 3.d.2).
VIO 389/95-21-03,
"Failure to Perform Reactor Coolant System
'urveillance,"
paragraph
4.b.2).
Within the areas
inspected,
the following non-cited violation was
identified associated
with events reported
by the licensee:
NCV 95-21-04,
"Failure to Maintain Penetration
Logs," paragraph
3.a.4)B.
1.
Persons
Contacted
Licensee
Employees
REPORT DETAILS
- R.
- W.
L.
- H.
C.
R
- D
J.
~ H.
p.
R.
p.
K.
- J
- R.
W.
- D
- J
~ * J
. *
W.
Ball, Mechanical
Maintenance
Supervisor
Bladow, Site guality Manager
Bossinger,
Electrical Maintenance
Supervisor
Buchanan,
Health Physics Supervisor
Burton, Site Services
Manager
Dawson,
Licensing Hanager
Denver, Site Engineering
Manager
Dyer, Maintenance guality Control Supervisor
Fagley,
Construction Services
Manager
Fincher, Training Manager
Frechette,
Chemistry Supervisor
Fulford, Operations
Support
and Testing Supervisor
Heffelfinger, Protection Services
Supervisor
Harchese,
Maintenance
Manager
Olson,
Instrument
and Control Maintenance
Supervisor
Parks,
Reactor Engineering Supervisor
Pell,
Outage
Manager
Rogers,
System
and Component
Engineering
Manager
Sager,
St. Lucie Plant Vice President
Scarola,
St. Lucie Plant General
Manager
West, Operations
Manager
Wood, Operations
Supervisor
White, Security Supervisor
R. Ball, Mechanical
Maintenance Supervisor
'Other licensee
employees
contacted
included engineers,
technicians,
operators,
mechanics,
security force members,
and office personnel.
NRC'Personnel
.
H. Miller, Resident
Inspector
R. Prevatte,
Senior Resident
Inspector
S. Sandin,
Senior Operations Officer,
E. Lea, Reactor Inspector,
Reactor Projects
Branch,
Region II
W. Kleinsorge,
Reactor Inspector,'aintenance
Branch,
Region II
E. Herschoff, Director, Reactor Projects Division, Region II
- Attended exit interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
Plant Status
and Activities
a.
Unit
1 entered this reporting period at
100 percent
power.
Significant changes
during the inspection period included:
.0
~
November
9
- November
13:
~
November
16
~
November
17 - November 18:
~
November
21 - November 23:
I
Reduced
power between
60 and
90
percent for main condenser
waterbox cleaning
Manual reactor trip - entered
Mode 3
Reactor startup
- entered
Mode
1
Reduced
power to 60 percent
due
to loss of main transfo'rmer lA
cooling
b.
Unit 2 entered this reporting period in Mode
6 defueled.
Milestones
during the
RFO included:
~
November
16 - November 19:
Core reload completed
~
November
20
Upper Guide Structure set
~
November
25
Reactor Vessel
Head set
~
November
27
Entered
Mode
5
c.
NRC Activity
E. Lea,
Reactor Projects
Engineer from Region II, visited the site
during the week of October 30.
His inspection efforts are
~
documented
in this report.
~ *
K. Landis,
Region II Branch Chief, St. Lucie Plant, visited the site
on November
20 and 21, reviewed resident
inspection activities
and
held meetings with senior site management.
M. Kleinsorge,'ngineering
Branch Inspector
from Region II, visited
the site during the week of November
27.
His inspection, efforts are
documented
in this report.
E. Merschoff, Director, Division. of Reactor Projects,
Region II,
visited the site
on December
1.
His a'ct,ivities included
a site
tour,
a review of resident
inspector activities
and meetings with
licensee
seni.or management.
3.
Plant Operations
'a ~
Plant Tours
(71707)
The inspectors periodically conducted plant tours to verify that
monitoring equipment
was recording
as required,
equipment
was
-properly tagged,
operations
personnel
were aware of plant
conditions,
and plant housekeeping
efforts were adequate.
The
inspectors
also determined that appropriate radiation controls were
properly established,
critical clean
areas
were being controlled in
accordance
with procedures,
excess
equipment or material
was stored
properly,
and combustible materials
and debris were disposed of
expeditiously.
During tours, the inspectors
looked for the
existence of unusual fluid leaks,
piping vibrations,
pipe hanger
and
seismic restraint settings,
various valve and breaker positions,
equipment caution
and danger tags,
component positions,
adequacy of
fire fighting equipment,
and instrument calibration dates.
Some
tours were conducted
on backshifts.
The frequency of plant tours
and control
room visits by site management
was noted.
The inspectors
routinely conducted
main flow path walkdowns of ESF,
ECCS,
and support systems.
Valve, breaker,
and switch lineups
as
well,as equipment conditions were randomly verified both l'ocally and
in the control
room.
The following accessible-area
ESF system
and
area
walkdowns were
made to verify that system lineups were in
accordance
with licensee
requirements for operability and equipment
material conditions were satisfactory:
I)
On November
13 and .14 the inspector performed
a walkdown of the
Unit
1
CCW System in the control room,
CCW surge tank area
behind Unit
1 control
room and
CCW platform area.
The walkdown
included
a review of OP 1-0310020,
Rev 43,
"Component Cooling
Water - Normal Operation,"
ONOP 1-0310030,
Rev 27,
"Component
Cooling Water - Off Normal Operation,"
and Engineering
Drawing
8770-G-083
Sh
1 -.,Flow Diagram Component
Cooling System.
Both
trains were aligned to support full power operation.
All major
flowpath valves were verified in the correct position using
both control
room and local indication,
when available.
The
following deficiencies
were identified:
A.
V14154 A-B CCW supply crosstie
header drain valve had
PWO
¹68795 tag issued
June
7 attached
due to the. stem being
broken at the handwheel
nut.
The licensee
intends to work
this valve the next outage.
B.
V14492 and V14494 Radiation Monitor supply from lA CCW HX
and
'were described
as being
'ocated
"at monitor" on the Initial Valve Alignment of OP
1-0310020,
Step 8.1.1.A.
These
val'ves were actually
located
on top of the
CCW Platform Upper
Level while the monitors were located in the Lower Level.
C.
V14456 was identified in the Initial Valve Alignment of OP
1-0310020,
Step 8.1.1.B,
as "PI-14-27A Isol."
The
nameplate
attached
to the valve said "lA CCW Pump Suet
Vent."
D.
V14188 Chemical
Feed
Tank drain to Liquid Waste
Management
System
was
shown in the Initial Valve Alignment of OP 1-
0310020,
Step 8.1.1.C,
as "Closed,"
rather than the
actual position of Locked Closed.
Also, Engineering
Drawing 8770-G-083
Sh
1 - Flow Diagram Component
Cool-ing
System did not show this valve as
Locked Closed.
E.
V15500 Fire Protection
System to
CCW surge tank was
shown
on Engineering
Drawing 8770-G-083
Sh
1 - Flow Diagram
Component
Cooling System
as normally closed,
rather than
the actual position of Locked Closed.
The above
items were discussed
with the Operations
Supervisor
who indicated that appropriate corrective actions
would be
taken.
2)
On November 30 the inspector performed
a walkdown of the Unit 2
CCW System in the control
room,
CCW surge tank area
behind Unit
2'ontrol
room and
CCW platform area.
The walkdown included
a
review of OP 2-0310020,
Rev 34,
"Component Cooling Mater-
Normal Operation,"
ONOP 2-0310030,
Rev 18,
"Component Cooling
Water - Off Normal Operation,"
and Engineering
Drawing 2998-6-
083
Sh I - Flow Diagram Component Cooling System.
The
CCW A
and
B train Cross
Over Valves SB14169
and
SB14439 were
LOCKED
OPEN and
SB14177
2B
Over Isolation valve
LOCKED CLOSED due to
ICW being secured
to the
2B
All
major flowpath valves were verified in the correct position
using both control
room and local indication,
when available.
The inspector
found that not all deficiencies previously
identified in IR 95-14 had
been corrected.
The following new
deficiencies
were identified:
~
A review of the control
room copy of OP 2-0310020,
Rev 34,
"Component Cooling Mater - Normal Operation"
found three
TCs attached.
Two of the
TCs cor ected deficiencies
identified in IR 95-14,
however,
the third was
a one time
use
TC writteh against
Rev 32.
This was pointed out to the
ANPS who.removed i.t from the binder
and initiated
a TC cancellation.
3)
On November 20, during a routine plant tour the inspector
identified the following. violations or deficiencies:
A.
In the Work Control Center'the
inspector
reviewed the Unit
2 Working Equipment'Clearance
Order
Log and found that the
index had not be updated
since
November
18.
OP 0010122,
Rev 60, Instruction 8.5, step
2 required that
"An up-to-date
index (similar to Figure 6) shall
be
maintained
in the log".
This was
a recurring deficiency
which was initially brought to the licensee's
attention in
IR 95-10 and,
again,
indicated
a lack of strict attention
to detail in the area of procedural
compliance.
This item was discussed
with the Operations
Supervisor.
He intends to interview the operators
involved and review
past corrective actions to prevent recurrence.
B.
In the Unit 2 steam trestle area,
the inspector
observed
that'he~osition
of V09120
.
valve was Closed,
vice Locked Closed
as required
by the
attached
Danger
Tag ¹13 of Equipment
Clear ance Order 2-95-
09-062.
The inspector
reviewed the clearance
which showed
that tag ¹13 was
1 of 29 Danger Tags issued
on November
17
to inspect/repair
V09305, repack V09104.
All entries
on
the Equipment Clearance
Order were properly completed
including Tag ¹13.
The inspector
informed the
NPS who, in
turn, initiated
a root cause investigation.
The inspector
concluded that the operator failed to verify
that V09120 was in<he:correct position
as specified
on
the equipment clearance
order per
OP No. 0010122,
Rev 60,
step 8.6.2..
Further, the operator performing the
independent Verification per section 3.4.4 of the
same
procedure
also failed to identify this discrepancy.
This
failure to establish
and maintain
an adequate
equipment
clearance
is
a violation, VIO 389/95-21-01,
"Failure to
Follow Clearance
P} ocedures."
C.
Unit
1 Control
Room
(1)
The inspector
was present
when one of the .station's
Fire pumps
was started for testing
and observed
operators
responding to several
alarms
due to the
voltage 'transient.
Operators
stated that these
alarms
were predictable.
The inspector
questioned
the
ANPS as to whether these
alarms
were listed as
OWAs.
The ANPS stated that they were not.
This was
confirmed by a review of the posted
OWAs.
These particular alarms were previously identified by
operators
to the Event Response
Team during the root
cause investigation of the manual reactor trip that
occurred
on November
16 (see
paragraph
3.b.3)
as well
known and predictable
occurrences.
The inspector,
questioned
the
OWA coordinator responsible for
maintaining the
OWAs if any of the
PWOs issued
as
corrective actions to this event identified these
alarms
as
an
OWA.
He stated that he did not believe
so,
however,
he stated that
he would look into this
issue.
The Operations
Supervisor later said that
this item was identified on November
20 as
an
OWA and
was in the process of being issued.
The inspector
identified this as
a weakness
in identifying and
documenting
OWAs.
(2)
Prior to the start of the Fire pump,
a
CST N, alarm
was received.'he
inspector questioned
the
ANPS
concerning the cause of the alarm.
The
ANPS said the
alarm was spurious
and that the pressure
switch which
generated
the alarm was identified by a
PWO for
repair.
The desk
RCO showed the inspector
Equipment
Clearance
Order 1-95-11-043 which tagged
closed
V29202, the isolation valve from N, feed supply to
condensate
storage
CST/23/N-2/E-24.
This clearance
was issued
November
11.
The inspector questioned
the
ANPS why the subject Annunciator was not identified
with a blue or brown dot, indicating work was
pending.
The ANPS said that this was not required
since the pressure
switch itself (PS-29-4)
was
identified by a
PWO tag.
The inspector requested
a
copy of the
PWO for review.
The
ANPS discovered that
no
PWO had
been
issued
and,
consequently,
initiated
Work Request
No. 95019464 for repairs.
The
Operations
Supervisor said that it was his
expectation that identified deficiencies
receive
prompt corrective action.
Since the pressure
source
was isolated for 9 days
with no
PWO issued,
the inspector identified thi's as
a weakness. in not taking prompt corrective action for
a known deficiency.
The inspector
posed several. questions
to the
ANPS in
an effort to identify and evaluate
the process
used
to bring deficiencies to management's
attention.
The
ANPS response
was limited to verbal
communications
only with no,reference
to the
STAR program.
The Operations
Supervisor stated that he would
address this
as
a personnel
performance
issue.
D.
Unit 2 Control
Room
(1)
t
The inspector questioned
an operator
as to why the
"B'rain
CCW sample valve showed dual position
indication.
The operator explained that this was
a
solenoid operated
valve controlled by a pressure
switch and that, with the "8" CCW header
depressurized
for outage work, it should
have
indicated closed.
He also said that
a similar
condition had
been observed
on the "A" train
sample valve during that train's outage work.
The
ANPS explained that the system engineer believed the
dual indication was attributable to less
than normal
operating temperature
effects
on the magnetic valve
position limit switch and that normal position
indication should
be verified after the system is
returned to service.
The
NPS exercised this valve to
the
Open position
and released
the pushbutton,
at
Oi
E.
which time the dual position indication reappeared.
The
ANPS dete'rmined that
a Work Request
was;-speeded,to
identify the cause of the dual indication.
The inspector identified this as
a weakness
in not
documenting
a potential deficiency.
The
recommendation
from the system engineer to verify
proper system
response
after
a return to sei vice did
not appear appropriate.
A review of the control
room
deficiency log on November
28 showed that Work
Request
No. 95019684
was issued
on November
23 for
repairs.
The Operations
Supervisor
again stated that it was
his expectation that identified deficiencies
receive
prompt corrective action.
The inspector
noted that the. Instrument Setpoint List had
been
removed from both control
rooms
and that this
information was available in the TEDB;
In the Unit I
control
room, the
ANPS was unable to provide the inspector
with the pressure
switch PS-29-4 setpoint .after reviewing
the hardcopy printout.
In the Unit 2 control'oom,
the
ANPS required approximately
15 minutes
and detailed
instructions via telephone to access
information using the
computer
TEDB.
The inspector
found that incorporating this information
into the computer'EDB without, apparently,
providing
operators with adequate
instructions and/or training for
access
was
a potential
impediment to operator
effectiveness.
In a frank discussion
with the
NPS the
inspector learned that removing other sources of
information,
such
as tech manuals,
FSAR, etc.,
was being
considered
based
on housekeeping.
The inspector concluded
that licensee
should evaluate this consideration
carefully.
The Operations
Supervisor
on November
20 issued detailed
instructions
on accessing
instrument setpoints
in the
TEDB
to operations
personnel
via electronic mail.
4)
Control
Room Log Reviews
A.
While reviewing the Unit 2
OOS log on November 27, the
inspector noted
an entry for V3536, the
A SDC warmup
valve.
The valve had
been declared
OOS on October
24 for
repacking
and actuator repair.
In the portion of the log
entry which specified the
mode or condition requiring the
valve to be in service,
operators
had specified "Prior to
draining cavity below 59'."
The inspector
noted that the
unit was in Node
5 (reactor cavity empty) at the time with
0)
the reactor cavity having been drained
below 59'n
November 23.
The inspector questioned
control
room operators
about the
subject entry and was told that the valve had
been
declared
00S because
the scheduled
work on the valve would
result in breaching the
A SDC train's pressure
boundary.
As two SDC trains would be required
below 59', operators
sought to ensure that the integrity of V3536 was restored
prior to a level reduction
below that value.
While valve
work and stroke testing
was completed
by November
14, the
valve reoiainetl in an inoperable state
pending
VOTES
testing.
The inspector
discussed
the issue with control
room
operators
and the Operations
Supervisor.
Of particular
concern to the inspector
was the fact that the
mode or
condition requiring valve operability, specified
on the
OOS log appeared
to have
been
ignored in draining down the
reactor cavity.
The inspector
was told that the
OOS log
was not modified when valve integrity was restored
because
that level of updating
was not considered
practical
from. a
programmatic
sense.
It was explained that the
OOS log was
employed mainly to identify those
items which should
be
considered prior to maneuvering
the plant through
modes
and conditions.
The formal verification of the required
conditions
was said to be accomplished via the procedures
governing
any specific evolution.
The inspector
reviewed the governing procedure for the
log,
and found that the procedure
required that the log be
kept current.
The inspector considered
the explanation
offered by operators
to fit loosely within the
requirements
of the procedure,
as the subject entry was
left in the
OOS log until valve operability was
conclusively demonstrated.
While reviewing this issue,
the inspector
noted
discrepancies
between
AP 0010145,
Rev 7,
Controls,"
and
OP 2-1600023,
Rev 37, "Refueling Sequencing
Guidelines."
The discrepancies
involved the specification
of the TS-mandated
minimum reactor cavity level for the
movement of irradiated fuel
and above which only one train
of SDC was required.
Unit 2 TS required this level to be
23'bove the vessel
When this requirement
was
translated
into an overall elevation requirement, it was
alternately listed
as 58'nd 59's follows:
AP 0010145,
step 8.5, stated
the elevation to be
58'P
2-1600023 stated
the elevation
as:
~
58'n step 8.5
~
59'n Appendix A, Checksheet
1, step
2.C.,1
~
59'n Appendix A, Checksheet
3, step 1.A-
D
59'n Appendix
D
The inspector relayed the issue to the licensee,
who
stated that TCs would be generated
to establish
the
59'levation
as the consistent
standard.
The inspector
found
that the licensee's
procedures
were weak in their lack of
consistency
in TS-required values.
An additiona'I
weakness
appeared
to be involved in the recent review and approval
of OP 2-1600023
(October 26,
1995) in that the procedure
was released for use while internal inconsistencies
existed.
B.
The inspector reviewed
STAR 951930,
generated
by'gA as
a
result of an audit of Unit 2 control
room logs.
The gA
inspector
found that the penetration
log, required
by OP
2-1600023,
Rev 37, "Refueling Sequencing
Guidelines,"
was
not being maintained
as required
by step 8.4.8 of the
procedure.
The
gA inspector
found that three
28A, the equipment hatch,
and the personnel.
hatch,
were open,
were logged in the
OOS log, but were not=
'ogged
in the penetration
log.
Control
room staff updated
the logs when the condition was identified.
The failure of operators to maintain the penetration
log
constituted
a 'violation of plant procedures
and
NRC
. regulations.
This constitutes
a violation of minor
significance
and is being treated
as
a Non-Cited
Violation, consistent with Section
IV of the
NRC
.This item will be identified as,NCV
389/95-21-04,
"Failure to Maintain Penetration
Logs."
b.
Plant Operations
Review (71707)
The inspectors periodically reviewed shift logs
and operations
records,
including data sheets,
instrument traces,
and records of
equipment malfunctions.
This review included control
room logs and
auxiliary logs, operating orders,
standing orders,
jumper logs; .and
equipment tagout records.
The inspectors routinely observed
operator alertness
and demeanor during plant tours;
They observed
and evaluated
control
room staffing, control
room access',
and
operator
performance
during routine operations.
The inspectors
conducted
random off-hours inspections to ensure that operations
and
security performance
remained at acceptable
levels.
Shift turnover s
were observed
to verify that they were conducted
in accordance
with
approved licensee
procedures.
Control
room annunciator status
was
verified.
Except
as noted below,
no deficiencies
were observed.
1)
Cross
Connection of Electrical Trains during Unit 2
The inspector during routine plant tours
and inspections
found
that the licensee
had cross-connected
480V ESF Safety Related
10
Load Centers
2A2 to 2B2 through the
2AB swing load center.
Since this lineup is not discussed
in TS, the inspector
questioned
operators
as to whether electrical
separation
between electrical trains
A and
B was required in Modes
5 arid
6.
The operators
stated that they routinely use this lineup to
permit maintenance
and retain essential
equipment during
refueling outages.
STAR 2-951391
was written asking
engineerin'g to evaluate
the adequacy of this electrical
alignment.
Engineering
performed safety evaluation
JPN-PSL-SENS-95-037,
Rev.
0 "Safety Evaluation for Cross-Connecting
480V Load Center
during Modes
5 and 6" on this it'em.
This assessment
determined
that this alignment
was acceptable
and that no equipment
was
overloaded -or -exposed to additional failure as
a result of this
alignme'nt.
The inspector
reviewed this evaluation,
discussed it with an
NRR specialist
and found it to be acceptable
during refueling
outages.
However, .it appeared
that the licensee's
only
justification for this lineup
on Unit 2 was that it had
been
an
acceptable
practice
on Unit 1.
The inspector
noted that Unit
1
had
been licensed prior to any strict criteria for electrical
separation,
i.e.
2)
On November
8 the inspector reviewed the Unit 2 Appendix
C
Valve Switch,Deviation Log and identified two deficiencies:
A.
There
was
a log entry to unlock the'.normally locked closed
V-15538 Primary Water to SFP valve for
EM to washdown
equipment.
The entry was dated
and initialed on November.
7, however,.no
IV was documented.
The inspector brought
this to the attention of the
ANPS who confirmed that the
work had been
completed
and directed that the valve be
restored to the locked position, verified and the log
entry cleared.
Previous difficulties in maintaining this control
room log
were identified in IR 95-15
as violation 95-15-03,
"Failure to Follow Procedure
and Document
abnormal
valve
position in the Valve Switch Deviation Log", and in IR 95-
18.
The inspector
discussed
with the Operations
Supervisor the efficacy of the corrective actions
referenced
in IR 95-18, i.e., periodic
STA review.
The
Operations
Supervisor
noted that
a TC was in process
to
clarify the scope of the
ANPS/NWE daily log review and
that
a Night Order to all operations
personnel
had
been
issued
on November 10.
The Night Order stated:
"We are still having problems with the valve switch
deviation log.
Until further notice the valve switch
deviation log shall
be reviewed
each shift by the
ANPS.
During this review the
ANPS shall
ensure
the need for the
deviation to exist, the reason for the deviation,
and what
it will require to return the plant to
a normal
configuration.
A change to 0010125 will follow to
formalize this review.
This log should not have
many
items in it at any given time. If we are placing
a lot of .
items in this log we should question
and change
our
process."
The inspector
noted that the requirement for ANPS review
referenced
in the night order already existed in the
procedure.
The inspector
had
a followup discussion -with
=
the Operations
Supervisor
regarding the use
and
interpretation of AP 2-0010123 Administrative Control of
'alves,
Locks and Switches.
This AP, which contained
the
Appendix
C Valve, Switch Deviation
Log stated its purpose
as follows:
"This procedure
provides instructions for placing valves,
locks
and switches
under administrative control
when the
position of such valve, lock or switch is critical to the
safety of personnel
or equipment.
It also provides
instructions for periodic verification of the status of
'hese
valves,
locks
and switches
and verification of the
effectiveness
of these administrative controls."
Under Precautions
and Limits:
"The valves listed in this procedure
are the only ones
considered
to be under Administrative Control.
Other
valves found to be locked should
be referred to the
Operations
Supervisor for resolution."
Further, this
AP enumerated
the "criteria...considered
to
determine if a valve or switch should
be
added to or
deleted
from the list of Administratively Controlled
'alves
or switches".
And finally, this
AP stated that "Independent
Verifications, when required,
shall
be conducted
in
accordance with..."
The inspector questioned
the Operations
Supervisor
regarding the overall
usage of the Appendix
C Valve
Deviation Log and, specifically,
why V-15538 was
documented
in Appendix C.
This valve did not meet the
criteria specified
above requiring Administrative Control,
nor was it listed in any of the
AP Appendices.
The
Operations
Supervisor explained there were currently only
three methods of maintaining plant configuration control;
Equipment Clearance
Order, positioning
and restoring
valves
and switches within an approved
procedure or
12
documenting
by the Appendix
C Valve, Switch Deviation Log.
This applied to all valves
and switches including V-15538
Hose Station
15-55 Drain Valve which was not identified as
a valve requiring Administrative Control.
The presence
of a valve locking device
on V-15538 may have
added
some confusion for the operators.
The licensee
recently completed
a plant review of'll locked 'valves to
determine which ones
should
be under Administrative
Control.
Those valves
and switches which did not meet the
criteria had their locking devices
removed
and the
respective
PE IDs updated.
Under the Precautions
and
Limits quoted
above,
one might infer that the presence
of
a locking device
was only associated
with valves'under
Administrative Control.
The inspector
reviewed the
applicable
PAID as well as OP'-1560020
Primary Water
System
and verified that V-15538's
normal position was
closed vice locked closed.
The Operations
Supervisor
stated that it was his expectation that operations
personnel
minimize use of Appendix C.
On the question of when
an Independent Verification per
Appendix
C is required,
the Operations
Supervisor stated
this applied to all valves
and switches
under
Administrative Control
and those others which affected
safety related
components
or
systems similar to the
guidance
provided in OP-0010122
Equipment Clearance
Orders; paragraph
3.d.2.
The inspector
pointed out that
in the
9 months of reviewing Appendix
C log entries
he had
never
seen
an Independent .Verification waived.
The inspector concluded that while there
was
no violation
of any
NRC requirements,
AP 2-0010123
should
be clarified.
This AP did not currently address
maintaining
configuration control for valves
and switches which are
not under Administrative Control nor did it allow for
-waiving the'ndependent
Verification if the valve or
switch does not affect
a safety related
component or
.
system.
There were
2 log entries to close the normally open
V-
18150
and V-18710 Unit
1 to Unit 2 Instrument Air
X-tie'alves
for Safeguards
testing performed
on October
12.
Both valves were closed
by OP No. 2-0400050,
Rev
16
Periodic Test of the Engineered
Safety Features.
OP 2-0010123,
Rev 68, "Administrative Control of Valves,
Locks and Switches,"
Appendix N, "Hiscellaneous
Systems
Valve List," Part B.l, "Instrument/Station Air,"
identified the following valves for Administrative Control
by Unit 2:
(1)
V18717
(2),
V18150
(3)
V18149
13
Station Air X-tie from Unit
1
(G)
Instrument Air X-tie to Unit
1
(G)
Instrument Air from Station Air X-tie to
Unit (G)
V-18710 is not administratively controlled by Unit 2 since
it is
a Unit
1 valve physically located in the Unit
1
Turbine Building.
This valve was repositioned
by a Unit 2
test procedure
and improperly logged in the Unit 2
Appendix
C Valve Switch Deviation Log.
When this log
entry was questioned
by the inspector,
the Unit 2 ANPS
contacted
the Unit
1 ANPS, transferr ed the log entry and
filled out
a Data Sheet
No.
7 to document the discrepancy.
On November 9, the inspectoi". discussed this deficiency
with the Operations Supervisor.'he'Operations
Supervisor
stated that
a log entry was not required for
administratively controlled valves that were repositioned
and restored
by procedure.
The inspector
had reviewed the
procedure
and found no step which restored this valve.
Further, the inspector expressed
a concern that even with
all areas of each turbine building posted
"ensure you are
working on the right unit", operators
and test personnel
did not recognize
and inform the Unit
1 control
room of
this valve being repositioned.
The Operations
Supervisor
stated that
he had correcti.ve actions
under review which
may include initiating.a
STAR on the test procedure.
3)
Unit 1.Manual Reactor Trip following Feedwater Transient
On November
16,
1995, at approximately 5:35 pm, Operations
was
performing
a periodic surveillance
on the station's fire pumps.
This surveillance
involved .isolating the low fire main pressure
detector
and bleeding off pressure.to
ensure that both fire
pumps started.
At 5:40
pm the fire pumps started
and
a voltage
caused
several
control
room annunciators
to alarm.
While the operators
were responding to these
alarms,
a
1B steam
generator
Low Level alarm
(51 percent
Narrow Range)
occurred.
Attempts
by operators to take manual control of the
1B MFRV and
increase
feedwater flow were. unsuccessful
and steam generator
water level continued to decrease.
At 5:41
pm, with
approximately
41 percent level in the
1B steam generator,
a
manual reactor trip was initiated to avoid the automatic
low
water level,trip at 40 percent
level.
All rods fully inserted
and all plant equipment,
with the
exception of the lB MFRV, responded
as expected.
The
1B MFRV
was locked in the
50 percent
open position'normally, following
a turbine trip, the
MFRVs receive
a zero
demand
and close).
Secondary safeties
momentarily lifted and reseated.
Following
the trip, operators
observed level in the
increasing
abnormally.
The
15 percent
Feed
Bypass valves were
reset
and closed
and
a close signal
was sent to the
HFRV block
valves.
Since these
block valves require approximately
90
seconds
to close,
operators
manually tripped both
HFW pumps to
'revent
overfilling the
1B Steam Generator.
Following the trip
of the
HFW pumps,
the lA AFW pump autostarted
as designed
and
the
1B AFW pump was manually started
when level in the
1B Steam
.Generator 'decreased
to the normal
band.
After steam generator
levels stabilized,
operators
placed the
1A HFW pump back in
service to restore
normal feedflow.
A post trip review
verified that the
RCS cooldown limits were not exceeded.
The inspector attended
the operator debriefing conducted
by the
Operations
Hanager.
Operators
described
in detail their
recollection .of.-,the sequence
of events
and responses
to alarms
received.
Their actions in manually tripping both the unit and
HFPs were consistent
with current operating instructions
and
demonstrated
excellent operator
response.
Subsequent
to the trip, an Event Response
Team was formed to
determine
the root cause.
The
PGH reviewed the objectives of
the root cause evaluation with the team
and encouraged'them
to
remain focused.
The inspector
observed
team members
methodically review plant drawings,
vendor
documentation,
operator logs
and interviews
and control
room recorder traces
to eval'uate
system response
as part of their investigation.
The team was effective in developing
a plan of action which
identified the root cause
as
a degraded
24,VDC power supply
with input to'he
1B HFRV controller.
During post trip
testing,
the licensee
discovered that the this power supply was
degraded
to as low as 20.6 volts, which was';below the allowable
input of 21.6
VDC specified
by the controller manufacturer
(Fisher stated that the input voltage should
be 24
VDC + 10
percent).
The voltage
was further degraded
when the fire pumps
autostarted
causing the
1B HFRV Controll.er to malfunction.
- The degraded
power supply was replaced
and
a reactor startup
commenced
at 4: 12
pm on November
17. Unit
1 returned to full
power operation at 2:10
pm on November
18 without incident.
Prior to unit restart,
the inspector
reviewed the post trip
package.
No deficiencies
or conclusions
other than those
noted
by the licensee
were identified.
4)
Downpower Due to Loss of Cooling on
1A Hain Transformer.
On November -21; the-Unit- 1- ANPO'found-a burned out indicator
lamp for the
DC power available annunciator light in the lA
main transformer cabinet.
The change
out of this lamp by the
operator created
a hard short to ground
and resulted in a loss
of all cooling fans
and
pumps
on the main transformer.
0
0
15
The control
room received annunciators,
"Hain XFHR 1A Alarm
Panel"
and "Hain XFHR 1A Alarm Panel
Emergency. Condition" at
4:30
pm.
ONOP 1-0910031
"Hain Transformer Off-Normal" was
immediately entered;
The
RCO shifted from the auxiliary to
startup transformers
and began
as required
by the
procedure.
The
NWE and
a system protection engineer
were
dispatched
to the main transformer control panel
where they
.verified that all fans
and
pumps were off and that the
control wiring was
damaged
due to overload.
The system
protection engineer
was able to mechanically actuate
several
control relays using handheld
jumpers
and restore three sets of
cooling fans
and pumps.
After some manipulation
and
use of
additional
jumpers the system protection engineer
was able to
start the three remaining sets of fans
and pumps.
At 4:45
pm,
the unit downpower was leveled off at 60 percent.
'I
At 5: 17 pm, transmission
and distribution personnel
arrived at
the scene
and
commenced
repairs to the damaged control wiring.
At about 7:00
pm, these repairs
were completed
and after
testing the transformers
were realigned
and the unit was
returned to full power.
The response
by operators
and the system protection engineer
was found to be very timely and effective.
The knowledge
and
restoration
action taken
by the system protection engineer
prevented
the potential
loss of the unit.
5)
Water Treatment
Plant Carbon Filter Changeout
During a plant tour on October 20, the inspector
noted
a number
of operators
in the area of the Water Treatment
Plant preparing
to replace
media in 4,carbon filters.
In discussing'the
~
upcoming evolution, operators
stated that they did not believe
that...they could perform the evolution with the governing
operations
department
p'rocedure
due to a lack of specificity in
the guidance.
The inspector reviewed the subject procedure
and found that it
was very vague in its requirements
and included
a requirement
for those performing the evolution to take notes to be used in
developing
a new,
more detailed revision of the procedure.
Operators
stated that this requirement
was included
when plant
management
directed that
a procedure
be effectively as-built
while experienced
operators
and maintenance
personnel
performed
the media changeout.
Operators
stated that they felt that this
method of procedure
development
was not in keeping with the
plant's
new verbatim compliance policy.
The inspector
discussed
the issue with the Operations
Supervisor,
who stated that the Water Treatment Plant was
operated
using operations
departmental
procedures
which, due to
the lack of safety significance of that area of the plant, only
16
required his signature to approve.
The direction given to
develop
a more refined procedure
by recording the steps
required to perform the changeout
was considered
appropriate
to the circumstances.
The inspector stated that he considered
the operator's
attitudes to be correct,
as the conduct of
operations
procedure
required detailed
procedures
for
evolutions conducted
in all but
a small, procedurally-defined,
,series of 'exceptions.
The Water Treatment Plant
was not among
, the current list of exceptions.
1
During the current inspection period, the inspector
revisited
the issue with the operators originally involved in the issue,
who stated that
a detailed
procedure
was developed prior to the
commencement of work on media changeout
and that the plant's
verbatim compliance policy was applied to the evolution.
The
inspector
concluded that the operators
had raised
a valid
concern regarding the appropriateness
of procedural
guidance
and that the issue
had
been satisfactorily resolved.
C.
Plant Housekeeping
(71707)
Storage of material
and components,
and cleanliness
conditions of
various
areas
throughout the facility were observed to 'determine
whether safety and/or fire hazards
existed.
Plant appearance
declined
as expected
during the RFO.. However, the licensee
had
strengthened
their management
plant walkdown program
and
as
a result
are identifying and correcting
a lot of long term minor
deficiencies.
'o
violations or deviations
were identified.
d.
Clearances
(71707)
1)
Clearance
2-95-11-018
-
125VDC to 2A
EDG control panel.
Clearance
tags
on'-'2 breakers
in
DC panel
2A.
Both tags
were in
place
and the breakers
were in the correct position.
2)
The inspector
reviewed the following effective clearances
on
the Unit- 2 Atmospheric
Dumps
and their associated
block valves:
~Primar
Clearance
~Ei
t III
N
b
HV-08-14
HV-08-17
MV-08-18A
MV-08-18B
NV-08-19A
NV-08-19B
2-95-11-152
2-95-11-128
2-95-10-170
2-95-10-168
2-95-09-258
2-95-09-261
17
OP 0010122,
Rev 59, "In-Plant Equipment Clearance
Orders,"
Step
8.3.7,
provided the detailed instructions for performing
a
SAFETY REVIEW in item 7 of the Equipment Clearance
Order.
Step
8.3.7 stated:
'The
NPS/ANPS/NWE shall circle yes or no signifying that the
following items were reviewed with respect to the clearance
requested
when item P6
(AUTHORIZED BY) is signed.
A.
B.
C.
IV Required:
A Tech.
Spec./FUSAR/Safety
related
component
or system is affected.
Containment Penetration:
Associated
clearance
involves
a
Containment Isolation Boundary.
Scope of work required
by
the
NPWO shall
be reviewed against the clearance
to verify
Containment
Boundary is maintained.
Refer to the
Open
Log in Operating
Procedure
1 (2) - 1600023,
"Refueling Sequencing
Guidelines."
Redundancy:
Verify that the redundant
equipment/component/system
is OPERABLE.
The Equipment
Out-of-Service log and Jumper/Lifted
Lead log shall
be
utilized to verify redundancy.
D.
Mode Related:
Will a change
in MODE, up or down, require
additional surveillances
or requirements
to maintain
adherence
to Tech.
Specs.
"r
E.
Sensitive
Systems:
Work practices of.Administrative
Procedure
0010142 "Unit Reliability - Manipulation of
System
Systems."'he
safety reviews for .the above
Equipment Clearance
Orders
showed (refer to the preceding
paragraph for identification of
which item was reviewed)
A.
B.
C.
D.
E.
2-95-11-152
2-95-11-128
2-95-10-170
2-95-10-168
2-95-09-258
2-95-09-261
Y
Y
Y
N
N
N
N
Y
N
N
Y
Y
Y
Y
Y.
Y
N
Y
Y
N
Y
N
Y
Y
N
Y
N
Y
Y
N
There were several
inconsistencies
in the above safety reviews:
A.
-MV-08-17 (2-95-11-128) is a=Tech.
Spec. identified
block valve which requires
an IV.
B.
MV-08-18A, MV-08-18B, MV-08-19A and MV-08-19B were all
ADVs.
However, unlike the other
3
PORVs MV-08-18A (2-95-
e.
18
10-170) is identified as
a containment
and
sensitive
system.
C.
NV-08-14 and NV-08-17 are
2 of 4
ADV block valves.
NV-
08-14 (2-95-11-152) is identified as
a containment
which is not mode related.
.It appeared
to the inspector the safety review criteria was
, being inconsistently applied to similar components
as
shown
above
(items
B and C).
The failure to require
an independent
verification of NV-08-17 per
OP 0010122,
as identified above,
is identified as
a violation; VIO 389/95-21.-02,
"Failure to
Follow the Equipment Clearance
Order Procedure
and Require
Independent Verification of a TS Related
Component.".
Technical Specification
Compliance
(71707J
'icensee
compliance with selected
TS
LCOs was verified. This
included the review of selected
surveillance test results.
These
verifications were accomplished
by direct. observation of monitoring
instrumentation,
valve positions,
and switch positions,
and by
review of completed
logs
and records.
Instrumentation
and recorder
traces
were observed"for abnormalities.
The licensee's
compliance
'ith
LCO action statements
was reviewed
on selected
occurrences
as
they happened.
The inspectors verified that related plant
procedures
in use were adequate,
complete,
and included the most
recent revisions.
No deficiencies
were noted.
f.
Reduced
Inventory Operations
(71707)
On November 28, Unit 2 entered
a reduced
RCS inventory condition to
support
2A2 and
2B2
RCP seal
work.
The following items were
verified prior to this evolution:
~
Containment
Closure Capability - Instructions
were issued to
accomplish this;
men and tools were
on station.
The inspector
verified that the penetration
1'og properly. indicated actions
necessary
to close the three,
logged,
open penetrations
which
were required to establish
containment integrity.
~
RCS Temperature
Indication - The inspector verified that two
normal
Node
1 CETs were available for indication.
~
RCS Level Indication - The inspector verified that independent
RCS wide and narrow range level instruments,
which indicate in
the control
room, were operable.
An additional
Tygon tube loop
level indicator in the containment
was to be manned during
level
changes
and was displayed via closed circuit television
in the control
room.
~
The inspector verified that the tygon tube was free of obvious
kinks and properly supported.
The inspector noted,
however,
19
that the tube was routed directly over the
8 hydrogen
-. recombiner.
At the time, the
A recombiner
was operating
under
a surveillance test.
Operation of the recombiners results in
high amount of heat rising from the units.
The inspector
notified the control
room, cautioning operators
not to operate
the
8 recombiner without rerouting the tygon level indicator.
~
RCS Level 'Perturbations
- When
RCS level
was altered,'
additional operational
controls were invoked.
Procedural
restrictions required, operators
to terminate
maintenance
activities that could affect
RCS level,
shutdown cooling, or
related instrumentation
and controls.
~
RCS Inventory Volume Addition Capability - The inspector
verified that one (of three)
charging
pumps
and
a HPSI
pump
were available for RCS addition.
~
RCS Nozzle
Dams - Nozzle
dams were not installed at the time.
~
Vital Electrical
Bus Availability - Operations
would not
release
busses
or alternate
power sources for work during
reduced
inventory conditions.
The lh
EDG was considered
and the
18
EDG was considered
available
and was, in
fact running loaded,
as the licensee
was performing the TS-
required
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> surveillance
run, performed
each refueling on
each
EDG.
Governing procedures
prohibited switchyard work
during reduced
inventory conditions
and signs
were posted to
that affect at the switchyard.
~
Pressurizer
Vent Path - The manway atop the pressurizer
was
removed to provide
a vent path, -and
a vented
'FME device
was
attached.
The inspector reviewed
AP 0010145,
Rev 7,
Controls,"
and
OP 2-160023,
Rev 38, "Refueling Sequencing
Guidelines"
and found that initial conditions either
were satisfied
at the time of the review or could be satisfied
by the time
inventory reduction
commenced.
The inspector
noted that Appendix 8,
Check Sheet I, "Surveillances
Performed During Reduced
Inventory,"
contained
a verificati'on, in step
1.E, to verify that I SG with a
level of at least
10 percent
narrow range
was available
when nozzle
dams were removed.
The step
was apparently
meant to ensure
the
possibility of natural circulation in the event of a loss of
shutdown cooling; however, it had
been established
previously that
RCS integrity and pressurization
was required to ensure
natural
circulation.
As one requirement for reducing inventory was to vent
the pressurizer,
this step
appeared
superfluous.
The inspector
questioned
operators
as to the applicability of the subject step
and
found operators
knowledgeable
on the issue,
stating that they
realized that the step
was meaningless
and stating that it was
a
holdover from previous revisions.
The
NPS stated that the procedure
would be revised to remove the subject surveillance.
Overall, the
20
inspector
found operator
knowledge of the. upcoming evolution to be
good.
A prejob briefing was held in the late afternoon of November 28.
The unit entered
reduced
inventory at 5:55
pm to perform
RCP seal
work.
The work was completed
and reduced
inventory conditions were
exited at 9:45 pm,
on November 29.
g.
Effectiveness of Licensee Controls in Identifying, Resolving,
and
Preventing
Problems
(40500)
I)
Licensee Self Assessment
-*
The inspector attended
the Management
Review Meeting held
on
November
17.
Senior
FPL Managers
including the President of
the Nuclear Division and his designated
successor
were present.
The topics covered included:
A.
Unit I manual reactor trip which occurred
on November
16
B.
Operating
Report
C.
Unit 2 Outage Status
D.
Vakious Department
Reports
~
Nuclear Materials
Management
e
Engineering,
,
~
Maintenance
~
Plant Indicators
The discussions
were lively with active participation
by senior
management.
The inspector noted that the agenda
and
present'ation
was effective in briefing senior management.
2)
gA Audit Review
The inspector reviewed
gA audit OSL-OPS-95-12 of operations
and
technical specification
compliance dated October 20,
1995.
This audit was detailed
and thorough
and identified one finding
involving inadequate
control of long term surveillance
and the
timeliness of some non-technical
specification surveillance.
Weaknesses
involving procedural
adequacy
and adherence
were
also identified.
Good performance
was noted for on-line
maintenance activity coordination,
communication, shift
turnover,
use of self verification techniques,
and supervisory
oversight of reactivity control
and risk management.
The
inspector
noted that these findings closely paralleled
those of
the
NRC.
21
h.
Outage Activities (71707,62703)
1)
Unit 2 Core Verification
Preoperational
Test Procedure
No. 32000090,
Rev 15, Step 12.9,
is
a
QA Holdpoint where
QA independently verifies the fuel
assembly,
CEA and insert configurations
per AP 0010439,
."Physical
Inventory of Nuclear Fuel Storage Areas."
On November
19, the inspector
observed
the first half of core
verification following completion of"core reload at 1:06
pm.
A
CCTV and light attached
to a pole was lowered from the
refueling bridge
and positioned initially ov'er the southwest
portion of the core.
The
CCTV signal
was received
on
2
monitors
and
a
VCR on the refueling bridge where
a
QA inspector
and Reactor Engineer independently verified the orientation of
the assembly
and recorded the serial
number.
The refueling
bridge was then moved to the next assembly,
usually in the
same
row,
and the process
repeated.
Occasionally,
the submerged
lighting intensity was adjusted to ensure
a good quality
videotape
was produced.
The overall" Cdr'e"'Verification took
approximately 4-1/2 hours with only
1 deviation noted, i.e.,
CEA 843 in assembly
L75 (core location J6)
was rotated
180
degrees.
The inspector discussed
this deviation with the
Reactor
Engineer the next day.
The Reactor Engineer pointed
out that since this was
a full length
CEA there would be no
change
in the. core physics.
This was allowed per the
instructions for Unit 2 on Figure
1 of AP 0010439,
Rev 16,
which stated
"Full length strength
CEA's 'are oriented
SW for
convenience
of verification only."
The deviation was reviewed
and accepted
by
FRG on November 20, 'at which time
a STAR. was
initiated for tracking purposes
to the next
RFO.
In the three hours that the inspector
observed
Core
Verification, communications
were good
and coordination
among
the operators
was excellent.
The
2 data recorders
agreed to a
routine whereby neither would verbalize the assembly serial
number until both said "got it" and
had entered
the data
on
2
separate
data sheets.
This ensured
independent verification of
assembly serial
numbers
and location.
2)
Reactor Vessel
Reassembly
Upon completion of core load and verification, reactor
reassembly
was started
November 20.
The head
was set
on
November
25 and tensioned
on November 27.
The inspector
observed
selected- portions- of- these- activities during routine
reactor building entries.
The inspector did not identify and
the licensee
did not encounter
any significant problems during
this evolution.
22
3)
Freeze
Seals
The inspector reviewed licensee's
procedures
and documentation
associated
with freeze
seal application,
and interviewed
licensee
personnel
concerning the freeze
seal
process.
The
inspector specifically reviewed the procedure to determine if
the licensee
had included technical
guidance
as specified in
.the
NRC inspection
manual
Part 9900, Technical
Guidan'ce-
Mechanical
Freeze
Plugs.
The inspector
concluded that the
licensee's
procedure,
GAP-10,
Rev 2, "Application Of Freeze
Seals,"
adequately
addressed
the requirement specified in part
9900 which pertain to mechanical
freeze
seal application.
The
inspector reviewed
NPWO-91-8417
and WO-95017759-01
-and
determined that many of the requirements
specified in both the
licensee's
procedure
and
NRC inspection
guidance
had
been
complied with or specified
as requirements.
Since the core
was
off-load, freeze seals
were not used to the extent originally .
anticipated
during the outage.
Followup on Previous
Operations
Inspection
Findings
(92901)
1)
IR 95-09
and 95-10 identified, during ventilation systems
walkdowns,
several
instances
where operator
aides, i.e.,
and
CIAS donuts,
on both Unit 2 and Unit
1 control boards
were
missing.
At the time these
IRs were issued
the licensee
committed to correcting these deficiencies during
a complete
review of plant procedures
estimated to be completed within
approximately
90 days.
As followup to these
IRs the inspector confirmed that the two
missing operator aides
on Unit
1 were installed,
but that the
seven identified on Unit 2 were util'1 missing.
This was
brought to the attention of the Operations
Manager
who stated
that corrective action would be*taken.
The inspector verified
that all identified missing operator aides previously
identified in the above
IRs were inst'alled within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
2)
IR 95-14 identified deficiencies
associated
with a walkdown of
the Unit 2
CCW System in the control
room,
CCW Surge
Tank area
and the Upper and
Lower Platform levels of the
CCW structure.
The following deficiencies
have not been corrected
as of
November 30,
1995:
A.
V14101
5 V15536 were initially aligned to the
CLOSED
position;
however,
both had
a handwheel
locking device
installed with no associated
tag indicating
LOCKED CLOSED.
B.
V14438
(2A CCW HX outlet piping high point vent) omitted
from initial lineup.
C.
V14187 (Chemical
Feed Tank outlet) tag not attached.
0
3)
23
D, V14188 Aid not have
a
LOCKED CLOSED tag
as
shown in the
initial alignment.
The inspector brought this item to the attention of both the
Unit 2 ANPS and the Operations
Manager.
The
ANPS directed that
a
TC to Operating
Procedure
No. 2-0310020,
Rev. 34,
"Component
Cooling Water - Normal Operation"
be prepared to add V14438
(2A
.CCW HX outlet piping high point vent) to the initial 'lineup.
F
The inspector found that the licensee's
failure to address
minor deficiencies identified in previous
IRs
a weakness.
4.
'aintenance
and'urveillance
a.
Maintenance
Observations
(62703)
Station maintenance activities involving selected. safety-related
systems
and components
were observed/reviewed
to ascertain that they
were conducted
in accordance
with requirements.
The following items
were considered
during this review:
LCOs were met; activities were
'ccomplished
using approved
procedures;
functional tests
and/or
calibrations
were performed prior to returning components
or systems
to service; quality control records
were maintained; activities were
accomplished
by qualified personnel;
parts
and materials
used were
properly certified;
and radiological controls were implemented
as
required.
Work requests'ere
reviewed to determine the status of
outstanding jobs
and to ensure that priority was assigned
to safety-
related
equipment;
Portions of the following maintenance activities
were observed:
1)
. Inconel Alloy 600 Nozzle
and
RTD Replacement
) j
~ 'I/
In 1986,
San Onofre reported the failure of an inconel alloy
600 pressurizer
steam
space
nozzle, ht No. 54318.
determined that St. Lucie Unit 2 had four pressurizer
steam
space
nozzles,
one liquid space
nozzle
and five RCS hot leg
RTDs,
and four RCS cold leg
RTDs of the
same heat of inconel
alloy 600.
As a precaution,
St Lucie replaced
the four steam
space pressurizer
nozzles in 1987, the liquid space
nozzle,
and
the five RCS hot leg
RTDs in 1989, with inconel alloy 600 ht
No. 41501.
In 1993, the four alloy'600 steam
space pressurizer
nozzles
replaced
as
a precaution
in 1987, failed and were
replaced with inconel alloy 690 nozzles
welded with alloy 600
welding filler material
(I182).
In 1994, the steam
space
nozzles
replaced
in 1993, failed in the weld area.
These
nozzles
were removed
and reinstalled with alloy 690 welding
filler material
(I52).
FPL planned to replace the three liquid
space alloy 600 pressurizer
nozzles
in 1995,
as
a result of
previous failures of ht Nos.
NX 7630,
7387-2
and 41501.
planned to replace the five RCS hot leg
RTDs (ht No. 41501)
.
after 2003
and monitor the four RCS cold leg
RTDs (ht No.
54318).
A discussion of the
1993
and
1994 replacement activities is
contained
in
NRC Inspection
Report Nos. 50-335,389/93-08
and
50-335,389/94-10.
As
a result of both pressurizer
and hot leg penetration
failures of inconel alloy 600 ht Nos.
NX 7630
and 7387-2
reported
by San Onofre
and Palo Verde
and evidence of a St
Lucie Unit 2
RCS hot leg leak,
FPL decided to replace three
, Unit 2 pressurizer liquid space alloy 600, nozzles
and nine
instrument penetrations
with alloy 690.
As
a result of the above replacements,
all of the alloy 600 ht
Nos.
NX 7630
and 7387-2 have
been
removed from Unit 2,
and the
five hot
I'eg
RTDs of ht No.
41501 will be monitored until their
replacement.at..~
2003..
Four alloy 600 ht No. 54318
RCS cold
leg
RTDs remain in Unit 2.
Because of the lower cold leg
temperatures,
the alloy 600 ht No. 54318
RCS cold leg
RTDs are
expected to last until the
end of plant life.
None of the
alloy 600 heats
discussed
above are found in Unit l.
FPL contracted with B&W Nuclear Technologies
(B&W) to replace
the nozzles
and
RTDs under the
B&W gA program..
The applicable
Code for the nozzle
and
RTD replacement
is
B&PV Code:
Section
V - 1989 Edition with no Addenda
(89NA);
Section
IX - Edition in effect at the time of the activity; and
Section
XI -.89NA.
During the Unit 2 RFO, the licensee
implemented
PCM No. 152-295
RCS Hot Leg Instrument Nozzle Replacement for 8 flow
measurement
nozzle
J and
1 sampling nozzle
K.
These.'instrument
and
sample
nozzles
were part of the
RCS pressure
boundary
and
were
made of a specific heat treat of material
known to be
'usceptible
to
Flow measurement
nozzle
J for PDT-1121B
was found to be leaking
on October
10.
The J nozzles
attached
sensing lines to the
RCS hot legs for
pressure differential transmitters
PDT-llllA, B,
C,
and
D,
PDT-
1112A,
B,
C,
and D,'nd
PDT-1124W,
X, Y, and Z.
The PDT-lllA,
B,
C and
D, and
PDT-1121A,
B,
C and
D were part of the
and
measured
the reactor coolant flow.
The
K nozzle provided
a
sampling port off the
A hot leg.
This sample port was used
by
the Primary Sampling
System
and the
PASS to check reactor
coolant chemistry
and radioactivity.
This work was being performed
by
B&W using
a
FRG reviewed
and
approved
process traveler.
This process traveler
was
a
compendium of detailed work procedures,
operating instructions,
inservice
and
NDE inspection
procedures
including
contractor/FPL
gC signoffs.
25
On November 2, the inspectors
observed
the inprocess
work for
the
-'A hot leg nozzle replacements.
This included
a visual
examination of the work site
and
a discussion
with the onsite
contractor lead engineer.
At the time, the A hot leg nozzles
had
been cut and removed
and workers were aligning the two
drill jigs prior to machining.
The inspector
was impressed
with the contractor lead engineer's
knowledge of and
familiarity with the work.
The work was controlled by the lead
.
. engineer
inside containment with closed circuit TV and radio
communications to
a trailer parked
on the west. side of the
RAB.
As steps
were completed,
the lead engineer initialed a work
copy of the procedure
and informed the contractor staff in the
trailer via radio.
After completion of work and
upon exiting
containment,
the original procedure
was signed
by those
contractor workers performing the work.
On November 3, the inspectors
reviewed the process travelers
with the contractor
gC inspector
and noted only one minor
discrepancy.
The contractor
gC inspector working the night
shift on November
2 had mistakenly dated
4 signoffs as
"10/2/95" vice "11/2/95" for the
B hot leg work.
This
.
discrepancy
was considered
minor and editorial in nature.
The
dayshift contractor
gC inspector identified the four signoffs
for'correction.
All hotleg nozzle work was completed
by November'
and the
final contractor'ecords
verification performed
on November
11.
S
On November
1'4 and
15 the inspector
reviewed the completed work
package
in gC and noted the following discrepancies:
4
A.
RC-126 location
~
Sequence
120-00:
date of gC signoff was incorrectly
identified as "10-2-95".
~
Sequence
310:
verification
BY and
DATE signoffs were
lined through
and initialed, however,
completion of
this sequence
was IV'd..
B.
RC-127 location
~
Sequence
120-00:
.date of gC signoff was incorrectly
identified as "10-2-95".
C.
RC-128 location
~
Sequence
120-00:
date of gC signoff was incorrectly
identified as "10-2-95".
~
Sequence
130:
date of worker signoff was incorrectly
identified as "10-3-95".
26
During this
same period of time,. the contractor
a]so replaced
3
pressurizer
nozzles;
I temperature
nozzle located
on the lower
pressurizer
shell
(102E),
and
2 instrument nozzles
both located
on the lower pressurizer
head
(109A and
109B) per
PCH 027-295.
All pressurizer
nozzle work was completed
by November
10 and
the final contractor records verification performed
on November
12.
A review of this 'completed
work package
performed
by the
inspector identified the following discrepancies:
A.
102E location
~
Sequence
870:
"ASD" initials of welder performing
work were not included'n Attachment
3 - Authorized
Signature Identification List.
B.
109A location
Sequences
610-00 through 630,
655-00,
and 730-00
through 750-00 were annotated
"superse'ded
by NCR 95-
00099".
Attachment
2 -
NCR Log showed
NCR 95-00099
affecting only Sequence
740.
~
Sequence
655-00
was annotated
"See
NCR0 95-00098".
Attachment
2 -
NCR Log showed
NCR 95-00098 affecting
Sequences
600 and 655.
The inspectors
discussed
with the contractor difficulties
.encountered
during the wor k, specifically, the
4 failures of
the
UT examination of the. repaired =Inconel pad.'he
contractor
noted that this was the first time they had encountered
this
problem and believe that it was related to the difficulty in
performing weld repairs
due to the pad orientation
on the lower
pressurizer shell.
The inspectors
also reviewed
PCN 027-295,
Pressurizer
Nozzle
~R1
lihi 1dd:
P
T
1
- NOEp
d
and,reports;
STAR reports;
drawings;
Weld Control Records;
equality Control inspection reports; 'Authorized Signature
Identification Lists; heat treatment reports
and charts;
Foreign Material
and Personnel
Control Logs; nonconformance
reports;
welding material certified material test reports;
welder Performance qualification Records;
and Welding Procedure
Specifications
and their supporting. Procedure qualification
Records.
Observations
were compared with the
Code
and applicable
procedures.
27
Relative to the
PCH package
review, the inspectors
noted the
following:
Several
examples
where initials in the Authorized
Signature Identification Lists were
made in cursive
(hand
written) and the initials in the
PCM sign-off blocks were
block printed or vice versa.
The failure of sign-off
initials to match the Authorized Signature Identification
Lists initials, negates
value of the Authorized Signature
Identification Lists.
The inspectors
considered this
a
weakness.
Several
minor documentation
errors,
examples
were:
corrections
made without the
B&W gA program required
single line strike out, initial and'ate;
Weld Control
Record form was not amended to match current practice,
form required welder initials which are not
programmatically required;
missing required t'itles on
signature
blocks;
and lateral
expansion
dimensions
on
a
Welding Procedure gualification Record were reported in
mills as required,
but labeled in inches.
The licensee
made
on the spot corrections.
~
The nozzles
and
RTDs were replaced
by properly qualified
and certified welders,
gC inspectors,
and
NDE examiners
in
accordance
with properly qualified Welding Procedure
Specifications,
using properly certified welding filler
materials
and
NDE consumables.
No evidence of the non-
compliant activities of the type identified during the
1993
and
1994 nozzle replacement
outages,;were
identified
during this review.
4
The inspectors
determined that overall, this job wa's managed
very effectively and completed
on time without any significant
problems.
2)'ide
Range
SG Level Upgrade.
PCM 068-294
Wide Range
SG Level Upgrade for Reg Guide 1.97 was
also
implemented during this Unit 2 RFO.
This
Reg Guide
required that wide range
SG level instrumentation
be available
following an accident
("post accident qualified").
The
original Unit 2 design
included only I instrument per
SG whose
level transmitters
(LT-9012 .and 9022) were not qualified for a
post accident
environment.
The licensee
established
a two step
(phased
approach)
to
A.
Upgrade the environmental qualification of the existing
instrumentation,
via the previously implemented
PCN 138-
293,
and
28
B.
Add redundant
instrumentation,
with certain limitations
and exceptions
as noted in
PCH 068-294.
Work was performed
between
October
28 and November
6 by a
contractor,
under the supervision of Construction Services,
with plant testing identified as
an outstanding
item.
On
November 20, the newly installed instrumentation
was calibrated
.and placed in service.
On November
14 and
15 the inspector reviewed the completed
work
package
and did not identify any deficiencies.
This
modification also was well managed
and complete)'n
time -.,--
without any
significant;:pro5l,ems')
Emergency Diesel
Generators
The Unit 2
EDGs were taken out'of service
one at
a time to
perform routine
18 month refueling inspections
and planned
maintenance.
The following scheduled activities were
accomplished
on
EDG 2A.
~
18 month ele'ctrical
and mechanical
inspection.
'
Repair various leaks.
~ 'eplace
governor actuators.
~
Overhaul turbo lube oil motors.
~
PCH 019-295H replace water manifold. bolts.
'
PCH 156-295 delete
EDG start
on CIAS and
CSAS.
~
PCH 165-295 modify LO lube oil pressur e alarm.
~
PCH 160-295
change pre-lube check -valves to swing type
valve.
I
~
Install
new fuel oil piping from .the ..FOST to diesel oil
day
tank.'n
addition to the above planned repairs,
a problem involving
the failure of several
Curtis relay sockets
was identified.
The
18 month electrical surveillance
included removal
and bench
testing of approximately
54 relays
used in the diesel start
and
control circuitry.
After the above testing,
the, relays were
reinstalled.
During post maintenance
testing
on November 3,
EDG 2A failed to start.
Troubleshooting
found
a cracked solder
joint in the shutdown relay socket.
This socket
was replaced
and the
EDG was started.
During subsequent
testing,
the load
started
responding erratically and
was not controllable
so the
diesel
was unloaded
and shutdown.
Investigation found
a high
resistance
solder connection
on the 52Xl female relay socket.
Since this failure was similar to the above failures,
a
decision
was
made to perform resistance
testing of the
remaining
52 relay sockets.
This testing found that two
additional relay sockets,
air solenoids
(AVIA) and idle start
(R9) relays were defective.
Both of, these relay sockets
were
replaced.
k \\
29
In November 6, during the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> surveillance run, the
operator discovered that the
EDG did not respond to i%put
control signals.
The engine
was secured
and troubleshooting
efforts again found'
problem with a relay socket solder
connection
(SSIX).
The licensee
then assigned
a team consisting of system
.engineering,
corporate
engineering,
operations,
maint'enance,
. procurement,
and materials
management
to investigate this issue
and determine the root cause
and needed corrective action.
This team found that past
and future potential failures could
be attributed to flexing of the relay base
and socket that
occurred
when the relays were removed for testing during each
refueling outage.
On Unit 2, this testing
had
been
based
on
the
EDG installation vendor recommendations
and
had
been
accomplished
each refueling outage since initial unit, startup
in 1983.
On Unit I, this testing
had started,
on
9 of 30 KPD-13
relays
based
on
The remainder of the
relays
were
added to surveillance
program in 1994.
The team's
investigation concluded that the flexing of the bases
during
relay removal
had resulted
in flexing and deforming the
receptor contacts
and cracking the solder connections of the
receptor pins to 'base or base to terminal
board connections.
The licensee
obtained
replacement
relay bases
and found that
the replacement
relays
had increased
solder buildup which led
to improved
and more rigid connections
that were less
susceptible
to the failure.
Based
on this evaluation,
the licensee
replaced all 54 relays
.
bases
in
EDG 2A control panel.
A decision
was also
made to
inspect the relay and sockets
on
EDG lA/B as they became
available
and
on
EDG 2B when it was taken out of 'service for
the
18 month inspection during the current refueling outage.
)
The installed relays were square
D, 8501 series
KPD-13 relays
with an ll pin octal type connector
base.
.The socket
base is a
Curtis, RS-ll.
The socket
assembly is rated for 10 amperes
at
250 volts and consists of a socket
and two terminal strips
mounted
on
a circuit board.
The socket
assemblies
were replaced with identical
socket
assemblies
from stores.
As noted
above,
the manufacturer
appears
to have
had
some of the
same
problems identified with
these
components
in the past
because
the replacement
bases
have
much sturdier construction
and better solder buildup.
Based
on the above,
the licensee
determined that the removal
and insertion of the relays during
18 month surveillance
testing resulted in this failure.
In addition to replacing the
sockets
on
EDG 2A, the licensee
developed
and implemented
a
special test procedure to verify satisfactory operation of the
relay and bases after the repairs
were completed.
The
30
inspector followed the above work activities
and
PWO 66/1570
under which the relay replacement
was accomplished.
It was noted that the overall
RFO repair activities
on
EDG 2A
was performed
by a combination of plant, corporate,
and vendor
support representatives.
Good procedural
compliance
was noted
during the work observations.
It was also noted that it took
,several
relay failures before the licensee
was able to
determine the root cause.
The inspector also noted 'that -.during .the24 hour endurance
run
the
16 cylinder engine governor controls appeared
to create
a
high speed oscillations in the fuel rack-mechanism;
The .system
engineer stated that this had
been the normal historical
response
of this engine
and governor control
system.'=.-.The
inspector discussed
this issue with the maintenance
qanager
arid
plant general
manager
and questioned if this could i'.'reate
excessive
stress
and
abnormal
wear on the engine control
and
led to early failure.
The plant manager indicated that
he
would have maintenance
and engineering
look into this item
further after completing the outage
maintenance
on
EDG 2B.
Since the engine successfully
completed
a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. full load
surveillance
run and
no oscillations in
EDG frequency
was
noted,
the inspector reluctantly agreed to this approach.
On November 9,
EDG IB was taken .out of service
and
.-.
relays
were inspected.
Several
relay bases
were--found with
solder defects or loose receptor connectors.
No'.deficiencies
were identified that in the licensee's
opinion would have
resulted
in a failure that could have prevented
EDG IB from
performing its safety function.
Seventeen
rel'ay sockets
were
replaced
as
a precautionary
measure.
EDG IB was -returned to
service
on November
10,
1995.
Based
on this inspection
and the
fact that the relays in Unit I have only been
removed from
testing once,
the licensee
decided to schedule
the inspections
on
EDG 1A in early December after Unit 2 has completed the
current
RFO.
The licensee's
long. term plans call for replacing
all relay bases
on Unit I during the next refueling outage.
On November ll,
EDG 2B was taken out of service to perform the
18 month surveillance,
planned corrective maintenance,
selected
modifications,
and inspection of the relay problem identified
on
EDG 2A.
The following activities were planned:
18 month electrical
and mechanical
inspection.
Repair engine oil leak.
Replace
12 and
16 cylinder governor actuators.
Replace
16 cylinder fan shaft
and bearings.
Replace fuel oil priming pump due to excessive
packing
leakage.
Meld repair
on
16 cylinder fan drive idler adjuster.
Inspect
and repair abrasions
on actuator wiring.
31
Overhaul of turbo lube oil motors.
Installed
new fuel oil line from DFOST to
EDG 2B day tank.
Calibration of I&C equipment.
PCH 019-295H install
new water manifold bolts.
PCH 160-295
change
pre-lube
check valves to swing type.
PCH 156-295 delete
EDG 2B start
on CIAS and
CSAS.
PCH 165-295 eliminate spurious
alarm.
Inspect,
replace defective Curtis relay
sockets.'he
inspection of Curtis relay sockets
found them in
essentially
the
same condition
as
EDG 2A.
All 54 of the relay
sockets. were subsequently
replaced.
The inspector
observed
-selected
portions of these activities which were accomplished
under
PWOs 66/1678,
66/1612,
66/1443,
and maintenance
procedure
MP 2-2200063,
Rev 19, "Periodic Test of EDG 2B," and
HP 2-
0950187,
Rev 0, ."Operation of Emergency Diesel Generator for
Haintenance
and Governor Setup Following Governor Actuator
Replacement."
The relay replacement activity was originally planned
by the
licensee to repair all sockets
and build up the solder
connectors
under guidance
provided
by engineering.
The
inspector questioned this practice
and the means of determining
acceptable
repairs,
seismic qualifications of the repair,
and
what type of post maintenance
testing
was required.
Rather
than attempt to answer these
questions,
the licensee
elected to
replace all 54 relays with new ones they were able to obtain.
The inspector then reviewed the test of the relay and
new bases
and found it to be acceptable.
After completion of the relay work,
EDG 2B was restarted
to
perform gover'nor setup
and tuning.
Problems
were encountered
in achieving the proper
response
from the
16 cylinder governor
actuator during loaded conditions.
Afte'r extensive
troubleshooting
and attempts to adjust both engines,
a problem
was discovered
in the wiring harness
to the governor actuator.
It appeared
that vibrations
had resulted
in shorting two
control wires together near the connector plug.
This short
was
in the close proximity to
a chaffing problem previously
corrected
and discussed
in IR 95-18.
Repairs
were performed
on
this wiring.
The wiring harness for the
12 cylinder governor
was also
removed.
Even though
no defects
were identified, all
connections
were resoldered
and reinsulated.
The licensee
currently plan to perform these
same inspections
on
EDG 2A and
EDGs lA/B at the earliest opportunity.
The remaining work and
governor adjustments
were completed
and the unit successfully
completed
the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance
run and was returned to service
on November 29.
The inspector followed the above activities
as they occurred.
Specific observations
included, relay base
replacement
and
testing, wiring harness
repairs,
governor setup
and tuning,
32
various troubleshooting activities
and portions of the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
endurance
run.
Overall performance
and procedural
compliance
of the craft personnel
performing the work was considered
good.
System engineering
support
was considered
good until the
assigned
engineer
became unavailable.
The initial governor
setup
and tuning appeared
to be lacking in technical
expertise.
Additional vendor support services
and the return of the system
.engineer resulted in completing these activities after
a delay
, of several
days.
The licensee notified the
NRC of the relay problem
on November
20,
and plan to submit
a
LER on this item.
4)
PCN-008-295
RPS NI,Rpyl'acement/Upgrade
The licensee
implemented this
PCN duri,ng4he current Unit 2
refueling outage.
The modifications "removed'original
components
and installed replacements
developed
by
Gammametrics.
Replaced
components
included wide range
NI
detectors,
preamps
and drawers.
The .changes,
combined with a
similar
PCM to be applied to Unit I in 1996, allows
consolidation of parts,
standardization
of units,
and increased
gain sensitivities,
allowing for more accurate
indication of
flux in low leakage
cores.
The inspector reviewed the
PCH package
and'onducted
a walkdown .-
of installed,
accessible
components
with the
I&C System
Supervisor.
In viewing the Gammametrics
wide range
preamplifier boards in the Reactor Building keyway, the
inspector
noted that the cabling connecting to the -board-
included large
Ray-Chem splices
which appeared
to be securing
the cables'onnectors..to
the cables
themselves. 'he splices
were
so bulky as to prevent the cables
from being bent inside
the preamplifier cabinet to their mating connectors.
The
inspector questioned
th'e propriety of this application of the
splices.
The System Supervisor initiated STAR 951873 to
consider the question.
The STAR's resolution allowed the
cables to be used until the next refueling outage with the use
of 90'onnectors,
which precluded the need to bend the cables.
The acceptability of the splicing was based
upon .past history
of operability,
combined with satisfactory
and
continuity tests.
The inspector witnessed
portions of the post-installation
acceptance
testing performed
on the
B and
D wide range
NI
channels.
The inspector
found the procedure
and the
performance of testing to be satisfactory.
33
b.
. Surveillance
Observations
(61726)
Various plant operations
were verified to comply with selected
TS
requirements.
Typical of:these
were confirmation of TS compliance
for reactor coolant chemistry,
RWT conditions,
containment
pressure,
control
room ventilation,
and
AC and
DC electrical
sources.
The
inspectors verified that testing
was performed in accordance
with
adequate
procedures,
test instrumentation
was calibrated,
'LCOs were
met,, removal
and restoration of the affected
components
were
accomplished
properly, test results
met requirements
and were
reviewed
by personnel
other than the individual directing the test,
and that any deficiencies identified during the testing were
properly reviewed
and resolved
by appropriate
management
personnel;
"-='-"-
,
The following surveillance test(s)
were observed:
1)
OP 2-0400050,
Rev 16, "Periodic Test of the Engineered
Safety
Features."
On November
28 the licensee
continued the Integrated
Safeguards.
Test for EDG 2B Section 8.9 Diesel Generator Start
on
without
LOOP and 8. 10
EDG Loaded
24 Hour Run and Hot Restart.
This procedure
has several
TCs incorporated to allow for post
modification testing of
PCM 156-295
and interfacing to
OP 2-
2200050B
2B Emergency Diesel
Generator
Periodic Test
and
General
Operating Instructions.
PCM 156-295 modified the
logic to remove the
CIAS and
CSAS start signals which was.
described
in IR 95-18.
A thorough pretest briefing was conducted prior to stationing
test personnel.
The post modification testing confirmed that
the
2B
EDG did not start
on
a CIAS or
CSAS signal
and that when
paralleled to an offsite power source did not shift the
EDG to
the isochronous
Mode after receiving
a CIAS signal.
Following
completion of this portion of the test
a SIAS signal
was
inserted to verify the start of the
2B EDG. Voltage
and
frequency stabilized in the operating
range within the
10
seconds
allowed.
2B
EDG was then loaded to greater than 3800
MW for the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run.
The inspector
verified that the voltage
and frequency were in spec
and that
the
EDG had stabilized load.
The inspector noted that the test
was well controlled, test
steps
were signed off as completed
and that good communication
practices
were observed.
No deficiencies
were identified.
2)
on
Unit 2 Technical Specification 3. 1.2.9 required that boron
concentration
be verified consistent with shutdown margin in
Mode
5 by sampling the
RCS at
a frequency determined
by the
number of operable
charging
pumps;
The
AS requires that all
.
34
operations
involving core alterations
or positive reactivity..
changes
be suspended if the
TS requirement is not meet.
At approximately ll:45 pm on November
27 operations
discovered
.
that the required
8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
RCS chemistry surveillance with no
charging
pumps in operation
had not been
completed
since I:00
pm on November 27.
Operations
then
had Chemistry take
an
.sample.
At 12:00
pm Chemistry reported that the
'-
concentration
was within prescribed limited.
This time
exceeded
the allowable
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> +25 percent allowable extension
per
by I hour.
I
The apparent
cause of this violation appears
to be the failure
of operations
and chemistry to identify that sampling
requirement
time changed
from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in Mode 6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> in
Mode 5.
The unit had entered
Mode
5 at 3: 10
pm on November 27,
1995.
This surveillance=was
missed
on the day and peak shift
checks
and identified on the midshift.
This
same surveillance
was missed for 2 days in October
when Unit 2 entered
Mode 6 and
was identified as
NCV 389/95-18-06.
The licensee's
corrective
actions
on that item was to implement
a temporary
change to
Administrative Procedure
2-0010125
"Schedule of Periodic Tests,
Checks
and Calibrations" to require that
a Data sheet
30 of the
above procedure
be filled out to document this surveillance.
This item was also discussed
in the Operations
Department Night
Orders
on October 26.
A review of this check sheet for AP 2-
0010125 found that each shift had initialed off this step but
had not compl.eted the required data sheet.
This is
a
violation, VIO 389/95-21-03,
"Failure to Perform
Surveillance."
The licensee's
investigation
had not been
completed at-the
end
of the inspection period so all corrective actions
had not been
identified.
4
3)
Eddy Current Test of Steam Genera)or
Tubing
The licensee
ECT examined the'n'it"'2
SG tubes in accordance
with Procedure
NDE 1.3,
"Eddy Current Examination of
'onferromagnetic
Tubing Using Multifrequency Techniques
MIZ18/30," Rev 7, with Field Changes
A and.B.
The examinations
were conducted
by FPL personnel
augmented
by contract personnel
under the umbrella of the
FPL gA program.
The applicable
Code
for ET examination of Unit 2
SG tubes is The
Section XI 89NA.
To determine
whether the licensee
conducted
ECT examinations
in accordance
and
procedural
requirements,
the inspector
examined selected
gA
records
and 'supporting data
as desc} ibed below.
35
The
ECT examination of the Unit 2
SG tubes
included the
following:
~
Bobbin coil examination of all active tubes,
tube
end
to'ube
end.
~
Motorized Rotating
Pancake
(MRPC) examination of hot leg
transitions.
~
MRPC examination of 20 percent of cold leg tubes with
emphasis
on the stay rod and sludge pile areas.
~
MRPC examination of all dented
tube support intersections.
~
MRPC examination of selected
bobbin coil indications.
This outage,
the licensee
examined
a total of 16,355 tubes in
both
SG A and
B, identifying 383,recordable
indications
and
eight indications requiring plugging.
In addition the licensee
plugged eight tubes
as preventive maintenance.
Unit 2 Steam Generator
Tube Plug Status
SG 2A
SG-2B
Total
Tubes
Plugged Through
EOC-7
New tubes
Plugged
EOC-8
Total Tubes
Plugged through
EOC-8
269
274
198
209
467
16
483,
The inspectors
reviewed procedure
NDE 1.3, the data for the
~
plug indications,
the data for the five largest recordable
indications,
the qualification certification and visual acuity
certification documentation for ll selected
ECT examiners,
and
the calibration documentation for eight remote data acquisition
units.
Observations
were compared with the
Code
and
NDE 1.3.
The Unit 2
SG tube
ECT examinations
were conservatively
conducted
by properly qualified examiners
in accordance
with a
well written procedure.
4)
1B Emergency Diesel
Generator Periodic Test
The inspectors
observed
the performance of OP 1-2200050B,
Rev
24,
"1B Emergency Diesel
Generator
Periodic Test
and General
Operating Instructions."
OP 1-2200050B
was issued to satisfy
the 31 day surveillance
mandated
by Technical Specification
3/4.8.1.
This particular performance of Operating
Procedure
36
No.
1-2200050B,
was accomplished
to satisfy the requirements
of
AP 0010022,
Rev 0,
"Emergency Diesel
Generator Reliability
Program."
The inspectors
observed
the pre-job tail board
meeting
and the surveillance activities in the Emergency Diesel
Generator
(EDG) building.
The inspectors verified that the
latest version of the procedure
was used,
the personnel
were
properly qualified,
and tools were appropriately calibrated.
, During the performance of this surveillance the inspectors
noted the following:
~
A water valve adjacent to alarmed door 180,
and
a gage
labeled only "Water Temperature"
did not have plant
identification tags
and were not identified by a Plant
Labeling Deficiency Tag indicating that the deficiencies
were not 'formally identified by the licensee's
personnel.
Considering that the
EDG test is currently being performed
on
a
15 day periodicity, these labeling deficiencies
should
have
been identified by plant personnel.
'Replacement
bulbs were found in the log book rack on the
IB D-G.Idle Start Stop panel.
Other plants
have
experienced
plant trips as
a result of the inadvertent
installation of an incorrect panel
bulb.
Leaving
replacement
bulbs out and uncontrolled is and invitation
to trouble.
~
The water level site glass
on the
1B1 Radiator Expansion
Tank uses )-inch wide red tape to mark the high and low
water levels.
Operating
Procedure
No. I-2200050B step 8.1
4 does not specify where the water level is to be
evaluated
(above the tape,
below .the tape or behind the
tape).
l ~
~
The operators
conducting this surveillance
were
knowledgeable.
Procedure
adherence
was good.
The
coordination of this activity between the control
room. and
the
EDG building was good despite the remote location
a'nd
the high noise level.
5)
Vacuum Relief Test
The inspectors
observed
the performance of Data Sheet
24 of AP
1-0010125A,
Rev 41,
"Valve Testing Procedure."
This valve
exercise test, of the containment
vessel
to annulus
vacuum
relief valve Nos.
FCV-25-7 and
FCV 25-8, is conducted to
satisfy the requirements
of Technical Specification 3/4.6.5.
The inspectors
observed
the pre-job tail board meeting
and the
surveillance activities conducted
in the Unit I control
room.
The inspectors verified that the latest version of the
procedure
was used,
the personnel
were properly qualified,
and
tools were appropriately calibrated.
37
5.
Plant Support
(71750)
a.
Fire Protection
During the course of their normal tours, the inspectors
routinely
examined facets of the Fire Protection
Program.
The inspectors
reviewed transient fire loads,
flammable mater'ials storage,
housekeeping,
control hazardous
chemicals,
ignition source/fire risk
reduction efforts, fire protection training, fire protection
system
surveillance
program, fire barriers, fire brigade qualifications,
and
gA reviews of the program.
No deficiencies
were identified.
b.
Physic@'.-Protection
During this inspection,
the inspector toured the protected, area
and
noted that the perimeter
fence
was intact
and not compromised
by
erosion or disrepair.
The fence fabric was secured
and barbed wire
was angled
as required
by the licensee's
PSP.
Isolation zones
were
maintained
on both sides of the barrier and were free of objects
which could shield or conceal
an individual.
C.
The inspector
observed
personnel
and packages
entering the protected
area
were searched
either by special'purpose
detectors
or by a
physical
patdown for firearms, explosives
and'- contraband.
The
processing
and escorting of visitors was observed.
Vehicles were
.searched,
escorted,
and secured
as described
in the
PSP.
Lighting
of the perimeter 'and of the protected
area
met the 0.2 foot-candle
criteria.
In conclusion,
selected
functions
and equipment of the security
program were inspected
and found to comply with the
requirements.
Radiological Protection
Program
Radiation protection control activities were observed
to verify that
these activities were in conformance with the facility policies
and
procedures,
and in compliance with regulatory requirements.
These
observations
included:
Entry to and exit from 'contaminated
areas,
including step-off
pad conditions
and disposal of contaminated clothing;
Area postings
and controls;
Mork activity within radiation,
high radiation,
and
contaminated
areas;
Radiation Control Area
(RCA) exiting practices;
and;
Proper wearing of personnel
monitoring equipment,
protective
clothing,
and respiratory equipment.
V
38
1)
On November
2 the inspector
reviewed the nozzle replacement
worksite inside containment,
paragraph
4.a. l.
Prior to
entering containment,
the inspector contacted
HP in the Unit 2
RAB at approximately
10:00
am and requested
a current copy o'
both the
A and
B hot leg radiation survey maps.
HP provided
the A hot leg survey
performed at 1:00
am on November 2,
however,
was unable to locate
a current survey of the
B hot
,leg.
At the time, the inspector
understood that work'n the
A
hot leg was at the step where drilling and machining would
occur
and that scaffolding was still being erected
on the
B hot
'leg prior. to cutting and removal of the existing nozzles.
The
inspector requested
that
HP identify and provide the most
recent
B hot leg survey.
The HP'ech that the .inspector
spoke
with located
a general
area survey of the
B ho&-leg done
October
24 but believed that each shift performed this survey
and that
a more recent
one
was available.
Upon entering containment,
the inspector contacted
the
HP tech
covering the work on the A hot leg.
The
HP tech requested
the
specific
RMP used
by the inspector
and provided specific
and
detailed information on the radiation
and contamination levels
at the worksite.
.The inspector
was impressed
by the
HP techs
positive control of personnel
entering the work ar'ea
and
overall
knowledge of current radiological conditions.
On November
3 the inspector returned to the Unit 2
office to collect the
B hot leg survey requested
the previous
day.
The inspector
was given
a total of 4 surveys;
a general
area
survey done at 8:00
am on October 24,
a specific area
survey for removal of lead to install
a glove bag done at 2:00
am on October 31,
a general
area
survey done, at ll:00 am .on
November
2 and contamination
smears of scaffolding done at 9:30
pm on November 2.
The inspector questioned
the
HP supervisor
to determine
how often rad surveys
are required
and whether
workers entering containment
reviewed them.
The
HP supervisor
stated that radiological conditions were addressed
by HP techs
in the required prework briefings
and that only in isolated
instances
did workers request
and review rad surveys maintained
in the
HP office in the
RAB which is outside the
RCA.
The
supervisor referred the inspector to the applicable
procedures for how often rad surveys
are required.
The
inspector
reviewed
HPP-23 Health Physics Activities in the
Reactor
Containment Building During Shutdown
and noted three
cases
in which
a rad survey is required:
~
step 7.2.1 which was recently
changed
from
"Radiation
and
contamination surveys...should
be performed ...
once per
shift.." to "Radiation
and contamination
surveys
should
be
performed daily",
~
step 7.2.1
as directed
by the
HPSS
39
~
step 7.3.2 "All work areas
shall
be surveyed or verified
that
a curr@it survey has
been performed prior to start of
work in that area".
The fact that
a recent
documented
rad survey
on the
B hot leg
was not available for inspector review was brought to the
attention of the
HP Department
Head.
His followup indicated
-that the required surveys
were performed but not documented
and
.
that
he had instructed
HP personnel
that future surveys
were to.
be documented.
The inspector identified this as
a program
weakness.
The inspector
also reviewed HPP-I, "Radiation Work Permits,"
Rev 2, which refers to completing attachments,
e..g.,
Attachment
D prework briefing checklist.
These
attachments
were revised
and given
HPP Form Numbers only.
This editorial error was
brought to the attention of the
HP Department.
The inspector obtained
a copy of "A Layman's
Guide to Radiation
Safety" from the training department.
On page
54 in the Lesson
Titled:
Survey Naps,
appears
the statement
"Survey maps are
the best reference
to use to learn the dose rates
and
contamination levels in your work area".
The inspector could
find no requirement
or recommendation
in HPP procedures
for
radiation workers to refer to survey maps.
Radiation workers
are,
however, required to attend
prework briefin'g in which
radiological controls information is discussed
by HP.
The fact
that few, if any, workers actually, review completed
rad surveys
prior to performing work and that
HP apparently
assumes
complete responsibility in addressing
rad conditions during the
prework briefings did not reinforce the enabling objective of
RCAT training.'t
a very minimum, the licensee
may want to
consider
asking whether
any workers would like to review the
current survey.
This training and work practices
issue
was discussed
with the
HP Department
Head who said that
a STAR would be issued to
address
corrective actions.
6.
Exit Interview
The inspection
scope
and findings were summarized
on December I, 1995,
with those
persons
indicated in paragraph
I above.
The inspector
described
the areas
inspected
and discussed
in detail the inspection
results listed below.
Proprietary material is not contained
in this
repor't.
Dissenting
comments
were not received
from the licensee.
~Te
Item Number
40
Et
~0
VIO
50-389/95-21-01
50-389/95-21-02
50-389/95/21/03
Open
Open
Open
"Failure to Follow Clearance
Procedures,"
paragraph
3.a.3)B.
"Failure to Follow the
Equipment Clearance
Order
Procedure
and Require
Independent Verification of
a TS Related
Component,"
paragraph 3.d.2).
'Failure
to Perform
Boron Surveillance,'"
paragraph 4.b.2).
50=389/95-21-04
Closed
"Failure .to Haintain
Logs,'" paragraph
3.a.4)B.
7.
Abbreviations,
and Initialisms
ATTN
CFR
CIAS
DFOST
EH
FHE
Foreign Haterial Exclusion
Fuel Oil Storage
Tank
ADV
,
Atmospheric
Dump Valve
Analysis
and Evaluation of Operational
Data, Office for (NRC)
(system)
ANPO
Auxiliary Nuclear Plant [unlicensed]
Operator
ANPS
.
Assistant Nuclear Plant Sup'ervisor
Administrative Procedure
ASHE Code American Society of Hechani'cal
Engineers 'Boiler and Pressure
Vessel
Code
.Attention
Cubic Centimeter
Closed Circuit Television
Component
Cooling Water
Combustion
Engineering
(company)
Control
Element Assembly
Code of Federal
Regulations
Containment Isolation Actuation Signal
Containment
Spray Actuation System
Condensate
Storage
Tank
Deisel
Fuel Oil Storage
Tank
Demonstration
Power Reactor
(A type of operating license)
Emergency
Core Cooling System
Emergency Diesel
Generator
Electrical Haintenance
Engineered
Safety Feature
Engineered
Safety Feature Actuation System
Flow Control Valve
FR
FRG
GMP
HPP
HPSS
ICW
i.e.
IR
IV
JPN
LCO
LER
MRPC
MV
NI
No.
NPF
NPWO
NRC
NWE
ONOP
00S
OP
PGM
PAID
PSL
PWO
41
The Florida Power L Light Company
Federal
Regulation
Facility Review Group
Final Safety Analysis Report
General
Maintenance
Procedure
Health Physics
Health Physics
Procedure
High Pressure
Safety -Injection (system)
, Health Physics Shift Supervisor
Heat Exchanger
Instrumentation
and Control
Intake Cooling Water
that is
Institute for Nuclear
Power Operations
[NRC] Inspection
Report
Independent Verification
(Juno
Beach)
Nuclear Engineering
TS Limiting Condition for Operation
Licensee
Event Report
Main Feed
Pump
Main Feed Regulating Valve
Main Feed Water
Motor Operated
Valve
Motorized Rotating
Pancake
Motorized Valve
Megawatt(s)
Non Conformance
Report
NonCited Violation (of NRC requirements)
Non Destructive
Examination
Nuclear Instrument
Number
Nuclear Production Facility.(a type of operati
Nuclear Plant Supervisor
Nuclear Plant Work Order
Nuclear Regulatory
Commission
NRC Office of Nuclear Reactor Regulation
Nuclear Watch Engineer
Off Normal Operating
Procedure
Out Of Service
Operating
Procedure
Operator
Work Around
Post Accident Sampling
System
Plant Change/Modification
NRC Public Document
Room
Plant General
Manager
Piping
8 Instrumentation
Diagram
Power Operated Relief Valve
Plant St.
Lucie
Physical
Security Plan
Plant Work Order
Primary Water StressCracking
Corrosion
ng license)
I
QI
RCAT
RCO
Rev
RII
St.
. STAR
TEDB
TS
VCR
VDC
'I.O;-
XFHR
42
Quality Assurance
Quality Control
Quality Instruction
Reactor Auxiliary Building
Radiation Control Access Training
Reactor Control Operator
Pump
.Reactor
Coolant System
Revision
Refueling Outage
[NRC] Regulatory Guide
Region II - Atlanta, Georgia
(NRC),
Reactor Protection
System
Resistive
Temperature
Detector
Radiation
Work Permit
Refueling Water Tank
Shut
Down Cooling
Safety Evaluation Report
Spent
Fuel
Pool
Safety Injection Actuation System
Saint
St.'Lucie Action Request
Temporary
Change
Total Equipment Data
Base
Technical Specification(s)
Updated Final Safety Analysis Report
Video Cassette
Recorder
Volts Direct Current
Violation (of NRC requirements).
Work Order
Transformer