ML17229A506
| ML17229A506 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/06/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17229A504 | List: |
| References | |
| 50-335-97-10, 50-389-97-10, NUDOCS 9710230026 | |
| Download: ML17229A506 (67) | |
See also: IR 05000335/1997010
Text
U.S.
NUCLEAR REGULATORY COHHISSION
REGION II
Docket Nos: 50-335,
50-389
License
Nos:
Report
Nos: 50-335/97-10,
50-389/97-10
Licensee:
Florida Power
Im Light Co.
Facility:
St. Lucie Nuclear Plant.
Units
1
& 2
Location:
6351 South
Ocean Drive
Jensen
Beach,
FL
34957
Dates:
July 27 - September
6
~
1997
Inspectors:
H. Hiller. Senior Resident
Inspector
J.
Munday, Resident
Inspector
D. Lanyi, Resident
Inspector
M. Thomas,
Regional
Inspector
(Sections
E7. 1.
E8. 1,
and E8.2)
.
S. Ninh, Project Engineer
(Sections
08. 1, 08.2. 08.3.
~
08.4,
and 08.5)
Approved by:
K. Landis. Chief. Reactor Projects
Branch
3
Division of Reactor Projects
97i0230026 97i006
ADQCK 05000335
8
PDH
EXECUTIVE SUMMARY
St. Lucie Nuclear Plant, Units
1 5 2
NRC Inspection Report 50-335/97-10,
50-389/97-10
This integrated
inspection included aspects
of licensee operations'ngineer-
ing, maintenance,
and plant support.
The report covers
a 6-week period of
resident inspection;
in addition, it includes the results of region based
inspections
in the areas of engineering
and operations.
~Ocr ati ons
Actions taken by operators to terminate
a reactor
power increase,
experienced
while placing
a Chemical
and Volume Control System ion
exchanger'in
service,
were swift and correct.
The proper level of
attention
was afforded this critical evolution.
(Section 01.2)
A leaking condenser
tube was identified quickly by Chemistry personnel.
Actions taken to minimize'the event were timely and in accordance
with
applicable plant procedures.
(Section 01.3)
System periodic surveillance
was performed
satisfactorily with no discrepancies
rioted.
(Section 01.4)
Operator
response
to a dropped Control
Element Assembly during testing
was professional.
The inspector
noted good communications
between
Operations
and Reactor Engineering.
The management
decision to de1ay
the test until Xenon conditions were stabilized
was both appropriate
and
conservative.
(Section 01.5)
A routine walkdown of the control
room ventilation system revealed only
minor deficiencies.
The inspector
found the response
and corrective
actions for a refrigerant leak adequate.
(Section 02. 1)
Although the procedure
upgrade
program was found to be on schedule.
the
volume of.procedures
remaining will present
a challenge to the licensee.
The prioritization of procedure
revisions
was appropriate.
(Section
03.1)
A non-cited violation was identified for failure to revise a.Quality
Instruction after the Nuclear Watch Engineer position was determined to
be optional.
(Section 03.1)
Overall. site procedures
were found to be adequate
to perform their
intended functions, availability of current revisions
was good,
and the
procedures
were usable, particularly the upgraded
versions.
As an
example,
although the licensee
had issued only a small percentage
of
upgraded
Annunciator Response
Procedures,
the inspector
noted that they
were
a significant improvement over the older versions.
(Section 03. 1)
The inspector
noted that an operator aligning the Gas
Decay Tank system
was careful
and methodical
in performing the evolution.
Although the
operator misread
one step,
overall procedural
adherence
was good.
(Section 04. 1)
Maintenance
The
1B ion exchanger
resin was discharged
according to procedure with no
major problems
noted by the inspector.
Good coordination
was noted
between the groups involved in the activity. (Section Ml. 1)
The experience
and knowledge of the technicians calibrating
2A High
Pressure
Safety Injection discharge
pressure
instrument resulted in
timely repair of a unique problem.
(Section M1.2)
The simultaneous
performance of maintenance
and surveillance
was
considered
a strength in reducing unnecessary
starts
and periods of
inoperability of the
2B diesel
generator.
(Section Hl.3)
The 2A charging
pump accumulators
were charged properly in accordance
with site procedures.
(Section H1.4)
The inspector
noted the technicians
were knowledgeable
about both the
equipment
and the procedures
being used during Reactor Protection
System
survei llances.
(Section Hl.6)
Although plant cleanliness
was generally acceptable,
more attention
was
warranted.
(Section
M2. 1)
~
A Quality Assurance audit on
Gai -tronics system problems
was well
performed.
The conclusions
were well founded
and the recommendations
were appropriate.
The inspector
concluded that the licensee's
response
to QA audit findings was proper,
and the programs in place should
maintain the Gai-tronic system acceptably.
(Section
M7. 1)
The inspector
concluded that the licensee
was actively and methodically
working to locate
and isolate
OC grounds
associated
with a nuisance
alarm.
(Section
H8. 1)
~E
Quality Assurance
audits
and assessments.
and the Site Engineering self
assessment
efforts were effective in providing oversight of Engineering
activities
and identifying areas for improvement
and increased
management
attention.
(Section
E7. 1)
The findings identified by the licensee during the UFSAR/Procedure
'onsistency
Review were documented.
processed,
and being tracked in
accordance
with the licensee's
corrective action program
and
NRC
regulations.
(Section
E8. 1)
The inspector
concluded that, for the condition reports
reviewed, Site
Engineering generally provided acceptable
responses
to address
the
concerns identified in the applicable condition reports.
(Section
E8.2)
3
~
A violation was identified for failure to update the
UFSAR with the
latest information developed to describe the design basis.
Enforcement
discretion
was granted for three
examples of UFSAR descrepancies
that
would more than likely have been identified by the license's
review program.
An NCV was identified for these
examples.
(Section
E8.3)
The inspector's
review of issues
surrounding the containment radiation
monitors identified potential deficiencies
associated
with the design
basis.
as defined by calculation, operability of the system,
inaccuracies.
and timeliness of completing design basis calculations.
An Unresolved
Item was opened
pending further review of these
issues.
(Section
E8.3)
1
Plant
Su
ort
Although several
DC emergency lights were noted to need replacement,
work had
been planned
and replacement
batteries
were on order.
The
Preventative
Maintenance
program for the
DC emergency lighting system
was found to be adequate
to detect
any problems with the lights within
approximately
one month of fai lure.
(Section
FZ. 1)
With two exceptions,
the inspector
found the fire suppression
system
properly aligned
and maintained.
A pump discharge
pipe support
was
found not supporting the pipe and
a recently repai red check valve was
left uncoated
and exposed to the environment.
Other minor deficiencies
were noted
and corrected or planned to be corrected.
(Section F2.2)
Summar
of Plant Status
Re ort Details
Unit
1 entered the period at approximately
90 percent
power following recovery
from a condenser
tube leak.
On July 27. the unit experienced
a reacti vity
transient during power ascension
due to inadequate
flushing of a Chemical
and
Volume Control System
Ion Exchanger.
The next day,
power was reduced to about
90 percent
due to
a dropped Control
Element Assembly
(CEA).
The unit was
returned to full power early on July 29.
The unit experienced
one other
dropped
CEA on August 21.
Power was reduced to 88 percent for a short time to
allow for recovery.
The unit remained at full power for the remainder of the
period.
Unit 2 remained essentially at full power for the entire period.
I. 0 erations
01
,
Conduct of Operations
01.1
General
Comments
71707
Using Inspection
Procedure
71707, the inspectors
conducted
frequent
reviews of ongoing plant operations.
In general: the conduct of opera-
tions was professional
and safety-conscious;
specific events
and
noteworthy observations
are detailed
in the sections
below.
01.2
Unit
1 Reactivit
Increase
When Placin
Ion Exchan er In Service
71707
a.
Ins ection Sco
e
C
On July 27, reactor
power increased
2 percent
and Reactor
Coolant System
(RCS) cold leg temperature
increased
2.5
F after the
1A Chemical
Volume
and Control System
(CVCS) Ion Exchanger (IX), was placed in service.
The inspectors
reviewed Condition Report
(CR) 97-1492 which documented
the event;
as well as the procedures
used during the evolution.
b.
Observations
and Findin s
On July 25, the resin in the
1A IN was replaced.
On July 25 and 26,
steps
were taken to equalize the boron concentration of the
IN with the
RCS,
a process
known as "rinsing in."
This was accomplished
by simply
routing
RCS fluid through the
IX allowing the boron to be deposited
in
the resin.
Because
the boron concentration of the
RCS fluid leaving the
IX was reduced,
the effluent was routed to a holding tank rather than
returned to the
RCS.
This cycle is repeated until the
IN effluent boron
concentration is within 25 parts per million (ppm) of RCS concentration.
On July 26, approximately
1700 gallons of RCS fluid was diverted through
the IX. and
a chemistry sample taken at 2:00 p.m. indicated
a final
boron concentration of 655 ppm.
At 3:32 a.m.
~ on July 27. the rinsing
in process
was again
begun.
The initial boron concentration
sample
indicated
233 ppm, which was thought to be in error,
based
on the
previous
sample results.
A second
sample
was drawn which indicated the
concentration
was
633 ppm.
At 5:02 a.m.,
another rinse of the
IX was
performed with the resulting boron concentration
indicating
721
ppm.
at that time was
717
ppm so the decision
was
made to place the
IX in service.
This was completed
by 5:45 a.m..
Because
small uncertainties
in the boron sample analysis
can result in
small reactivity changes'perators
anticipated
having to make
corrections
as necessary.
Additionally. the reactivity change, if one
occurred,
would not occur immediately because
the
IX effluent is
directed first to the Volume Control Tank
(VCT) prior to being
pumped to
the reactor.
At 6:ll a.m.,
the board operator
added
10 gallons of boric
acid and
20 gallons of water to the suction of the charging
pumps to
counteract
a slowly increasing
RCS temperature.
At 6:25 a.m., the
IX
was bypassed
when the
RCS temperature
continued to rise.
temperature
increased
2.5
F from 546 to 548.5
F.
Reactor
power
increased
2 percent
from 87 percent to 89 percent.
Operations
then
added additional boric acid to reduce
RCS temperature
to the pre-event
values.
The licensee
immediately initiated an Event Response
Team (ERT)'to
determine the root cause
and provide corrective actions.
The team
concluded the root cause
was that the samples
were actually taken
when
the
IX was bypassed.
This resulted in sampling reactor coolant rather
than
IX effluent.
-This occurred
because
the operating
procedure
controlling the evolution,
OP 1-0210020,
Revision 43,
"Charging and
Letdown
- Normal Operation," did not provide enough detail to adequately
coordinate the operation of the system
and the drawing of the sample.
As corrective action, the licensee
generated
temporary
changes
(TC) to
both units operating
procedures
to add additional
steps to better
coordinate the activity.
These
changes
were documented
in TC 1-97-071
for Procedure
OP 1-0210020
and 2-97-136 for 2-0210020.
The licensee
followed up the TCs with a permanent
change to the
same procedures.
The inspector
reviewed the event
and discussed
the details with the
involved personnel
and considered
the licensee's
root cause to be
accurate.
~ The procedure
revisions were reviewed
and were determined to
provide enough detai l to adequately
control this evolution.
Conclusions
The inspector
concluded that the actions taken
by the operators to
terminate this event were swift and correct.
The proper level of
attention
was being placed
on the evolution during this critical time.
The revision made to the appropriate operating
procedures
should prevent
this event from occurring again.
Unit
1
Down ower Oue to Condenser
Tube Leak
71707
Ins ection
Sco
e
On July 26, Unit 1 experienced
a condenser
tube leak which resulted in a
manual
power decrease
to approximately
75 percent.
The inspector
reviewed
CR 97-1490 which was written to document the event
and
determine corrective actions.
In additions
the inspector discussed
the
01.4
event with various Operations
and Chemistry personnel.
The inspector
also reviewed Off-Normal Operating
Procedure
ONOP-1-0610030.
Revision
13 'Secondary
Chemistry-Offnormal."
Observations
and Findin s
On July 26, at approximately 6:45 a.m.,
Chemistry personnel
notified the
Nuclear Plant Supervisor
(NPS) that Steam Generator
(SG) cation
conductivity was 0.4 umho/cm on both
and increasing.
Procedure
ONOP
1-0610030
was entered
and
SG blowdown was increased.
The
ONOP indicated
that the plant was initially in an Action Level
1 condition which
allowed one week to reach
normal chemistry values.
Shortly thereafter,
Chemistry reported that the analysis
indicated the conductivity increase
was due to sea water intrusion.
Operations
commenced
reducing reactor
power at 7:37 a.m. to remove the suspect
181 waterbox from service.
However, at 8:05 a.m., Action Level
2 was reached
when conductivity
exceeded
2 umhos/cm,
and
a power reduction to less than
30 percent
within four'ours
was
commenced
in accordance
with the
ONOP.
At 8:10
a.m., the
181 Circulating Water
pump was secured
which terminated the
sea water inleakage.
By 8:30 a.m.,
waterbox conductivities were
decreasing
and
SG conductivities
had stabilized.
By 9:00 a.m., the
conductivities
began to decrease.
A clearance
was
hung on the waterbox
for maintenance
to commence work.
The power decrease
was halted at 75
percent.
Maintenance
personnel
searched
for the tube leak using helium and
a
helium detector but were not successful.
However,
four plugs were noted
to be missing when comparisons
were made with the waterbox tube plugging
map.
The missing plugs were replaced
and the plant was brought back to
100 percent
power.
Secondary plant conductivities
remained within
normal
range.
Conclusions
The leaking condenser
tube was identified quickly by Chemistry
personnel.
Actions taken were timely and in accordance
with applicable
plant procedures.
Unit 2 Auxiliar
Periodic Test
61726
Ins ection
Sco
e
~ The inspector witnessed
the performance of Procedure
OP 2-0700050,
Revision
Periodic Test."
Observations
and Findin s
The inspector
attended
the pre-job brief and observed portions of the
surveillance
in both the main control
room and locally at the pump.
The
procedure
was verified to be of'he current revisions
the Measuring
and
Test Equipment
(%TE) was within its calibration due dates,
and the
operators
were qualified to perform the task.
No discrepancies
were
identified dur ing the performance of this activity.
Conclusi ons
The surveillance
was performed satisfactorily with no discrepancies
noted.
Dro
ed Control
Element
Assembl
93702
Ins ection
Sco
e
On August 21, the inspector
responded to the Unit
1 control
room in
response
to
a dropped
CEA during Full Length,CEA testing.
The inspector
observed
the rod recovery
and subsequent
power ascension.
Observations
and Findin s
At 8:45 a.m..
on August 21, Unit
1 experienced
a dropped
CEA (A-47)
during Full Length
CEA Testing per Procedure
OP 1-0110050,
Revision 35,
"Control Element Assembly Periodic Exercise."
The operators
responded
immediately in accordance
with Off-Normal Operating
Procedure
ONOP 1-
0110030,
Revision 38,
"CEA Off-Normal Operation
and Realignment."
The
operators
reduced
power to approximately
88 percent.
This dropped
rod
was different from most since it was
a dual
rod shutdown
CEA positioned
near the
"D" linear power range nuclear instrument (NI).
This caused
a
large rod shadow
on that NI, and
a large axial flux shape variation.
In
fact, the large
power shift caused
the operators
some minor problems
maintaining the opposite side T in the normal
band.
18C personnel
quickly determined that
a power switch had failed,
allowing the
CEA to drop.
By 9:05 a.m.,
18C had repaired the problem
and Operations
had verified CEA operability.
Operators
had fully
withdrawn .the rod by 9:25 a.m.
The Operations staff acted
professionally throughout the event.
The
NPS and Assistant
Nuclear
Plant Supervisor
(ANPS) minimized extraneous
control
room activity
during the recovery.
The inspector
noted
good communications
between
Operation
and Reactor
Engineering
(RE).
RE support
was appropriate
and
timely.
The inspector noted that the recovery to full power 'was
deliberate to al'low core power to equalize.
The conservative
management
decision to delay the Full Length
CEA test for twenty-four hours
was
appropriate.
Conclusions
Operator
response
to a dropped
CEA during testing
was professional.
The
inspector
noted
good communications
between
Operations
and
RE.
The
management
decision to delay the test
a day after
CEA recovery
was both
appropriate
and conservative.
V
02
02.1
Oper ational Status of Facilities
and Equipment
Walkdown of Control
Room Ventilation
71707
Ins ection
Sco
e
The inspector
performed
a routine walkdown of both units'ontrol
room
air conditioning systems.
In additions
the inspector followed up on
maintenance
associated
with a refrigerant leak that occurred
on the Unit
2 3A air conditioning unit.
Observations
and Findin s
The inspector
used
Drawings 2998-G-879
SH 2, Revision
16 and 8770-G-852,
Revision .22 to perform
a system walkdown of the air conditioning
systems.
Also, Procedures
1-1900020,
Revision 12,
"Reactor Auxiliary
and Control
Room Ventilation Operation,"
and 2-1900020, Revision'0.
"Reactor Auxiliary and Control
Room Ventilation Operation," were
reviewed by the inspector to verify system line up.
The inspector
found
only minor drawing discrepancies
that had already
been identified to the
system engineer.
In May, Maintenance
noticed that the Unit 2 air conditioning unit
2HVA/ACC-3A had
a pinhole leak at the shell side threaded inlet fitting
of the water cooled condenser.
A Condition Report
(CR 97-1044)
was
written identifying that
27 pounds of refrigerant
had been
added
and
identifying the apparent
location of the leak.
By the middle of June,
Engineering dispositioned the
CR by identifying the repai r.
At that
point. the work was placed
on the Plan of the
Day
(POD) to be worked in
July.
The licensee started
a surveillance
run of the Unit 2 3A air
conditioner
on the evening of July 4.
Within a few hours, the
ANPS
determined that the unit was not cooling properly, declared
the unit
and generated
a high priority work request to repai r the
unit.
The repai rs were completed July 5 with 60 pounds of refrigerant
added.
On July 22, Maintenance
evacuated
the Unit 2 3A air conditioner to
repair the leak.
They verified the system pressure
gages
and the
pumping unit pressure
gages
showed that no more refrigerant
was present.
They then unbolted
and refrigerant
gas
escaped
into the ventilation room.
All personnel
were evacuated
from the
ventilation room, located directly behind the control
room.
The doors
from the control
room were opened to vent the control
room and vent room
areas.
The causes
of the event were determined to be the following:
A lack of procedural
guidance.
The licensee
considered
evacuating
refrigerant within the skill of the craft and
no detailed
procedure existed.
Inadequate
Maintenance training.
The crew that performed this
work activity had been recently certified to service air
conditioning units.
The training was inadequate
as it did not
include site specific information about the air conditioning
units.
Inadequate
information in the work package.
The work package
did
not include the schematic
drawing of the equipment
layout that
would have
shown the craft that
a check valve between the
condenser
heat exchanger
and the closed solenoid valve was
installed which prevented
the reclamation 'of refrigerant in the
lines.
Short term corrective actions
included adding guidance to the generic
air conditioning work order to ensure
evacuation of all piping.
Long
term corrective actions
included development of a procedure to control
all air conditioning maintenance.
Maintenance
also completed
repai r of
the leak and restored
the unit to operation.
c.
Conclusions
The inspector
found only minor deficiencies
in the control
room
ventilation system.
The system engineer
was already
aware of these
problems.
The inspector
found the response
and corrective actions to
the refrigerant leak adequate.
03
Operations
Procedures
and Documentation
03. 1
Procedure
Review
42700
a.
Ins ection
Sco
e
The inspector
reviewed the licensee's
procedures
for developing,
implementing.
and revising plant procedures.
Also, the inspector
evaluated
the licensee's
procedure
upgrade
program,
procedure
change
backlog,
and library maintenance.
Finally, the inspector
surveyed
a
sample of.Administrative, Operations,
Maintenance,
Chemistry,
and Health
Physics
procedures
for usability, accuracy,
and conformance with the
site Writer's Guide.
b.
Observations
and Findin s
The inspector
reviewed the following:
Both units'echnical
Specification
(TS) Sections
6.5 and 6.8
The Topical Quality Assurance
Report
(TQAR) Section 5.0. Revision
12. "Instructions,
Procedures,
and Drawings"
Quality Instruction QI 5-PSL-1,
Revision 2, "Preparation,
Revision,
Review/Approval of Procedures"
Quality Instruction'I 5-PR/PSL-3,
Revision
14, "Verification
Guide for Emergency Operating
Procedures"
Quality Instruction QI 6-PR/PSL-1.
Revision 32,
"Document Control"
Procedure
ADM 11.02,
Revision 0, "St. Lucie Procedure Writer'
Guide"
Procedure
ADM 11.03,
Revision 1,
"Temporary Change to Procedures"
The inspector also conducted
interviews with several
procedure writers,
their management,
and procedure
users to determine the overall
effectiveness
of the St. Lucie procedure
program.
Several
years
ago the licensee identified that its procedures
being used
in the field were less than adequate.
Sufficient detail
was lacking to
ensure that minimally qualified personnel
could perform
a task in a
repeatable
and acceptable
way.
About two years
ago the licensee
began
a
procedure
upgrade
program designed to improve and standardize all plant
procedures
by the year 2000.
At the end of this report period, the
inspector estimated that approximately
15 percent of the upgraded
procedures
had been
issued with another five percent
nearing completion.
The licensee
had not yet identified what the final population of
procedures
would be.
One Procedure Writer noted that
some procedures
would be combined while others would be subdivided into separate
procedures. 'herefore.
a final count would be difficult to ascertain.
Based
upon the information provided by the Procedures
Group supervision,
the inspector estimated that about thi rty-six hundred procedures still
required
a significant amount of work prior to being issued.
This
number included
2350 Annunciator Response
Procedures
(ARPs).
The
licensee
acknowledged that their resources
were less than adequate.
The
large number of procedures
to upgrade
by the end of 1999 combined
with'he
"normal" duties of revising and reissuing
procedures,
posed
a large
challenge to the Procedures
Group with its limi.ted resources.
The St. Lucie site maintained
two main libraries,
one in the South
Service Building
(SSB)
and the other in the North Service Building.
The
Technical
Support Center
(TSC),
and both libraries all have
a complete
set of controlled procedures.
Several satellite areas
also have
controlled copies.
For example,
the diesel
generator
rooms
have
portions of controlled Off-Normal Operating
Procedures
(ONOPs). the hot
shutdown panel
rooms
have controlled copies of the
ONOPs
and Emergency
Operating
Procedures
(EOPs),
and the maintenance
area of the D-13
building had
some controlled procedures.
Each library location
contained
"For Information Only" procedure title lists.
However.
according to Quality Instruction QI 6-PR/PSL-1,
Revision 32,
"Document
Control," Section 4.5, the user
was to verify controlled copies
by using
the on-line Passport
D150 panel.
The inspector verified that the diesel
room procedures
and the hot shutdown
panel
room procedures
were the
current revision and ensured that
a sample of the D-13 procedures
was
current.
The inspector
noted
no discrepancies.
The inspector
randomly
verified twelve operations
and administrative procedures
in both control
rooms.
No deficiencies
were noted.
The inspector
randomly selected
52
procedures
from all disciplines
and verified that they were current in
the two main libraries.
The inspector
found one deficiency that the
licensee concurrently identified.
Maintenance
Procedure
MP-0940061,
Revision 22,
"Maintenance of Thermal Overload Devices," still existed in
the
SSB files although
EMP-100.01,
Revision 0,
"Maintenance of Thermal
Overload Devices."
had superseded it in March.
The licensee identified
the problem in Condition Report 97-1651.
The inspector
reviewed fifteen procedures
from various disciplines:
Operations,
Administrative, Maintenance.
Health Physics
(HP).
and
Chemistry.
These included both upgraded
and non-upgraded
procedures.
Overall, the inspector
noted that the upgraded
procedures
were more
uniform in appearance
than the non-upgraded
versions.
However the
and Chemistry upgraded
procedures
routinely departed
from the Writer'
Guide recommendations.
All non-upgraded
procedures
reviewed
had been
revised within the past year for either clarity, technical
content or
both.,
The inspector
compared the procedural
steps to the plant
configuration,
where applicable.
and determined that the procedures
would accomplish their intended function and were usable.
The inspector
concluded that the format of the upgraded
procedures
was improved but
technical
content
was comparable to the non-upgraded
procedures.
However, the consistent
use of nomenclature
and format did make the
procedures
more usable.
During the review, the inspectors
observed
one discrepancy.
On August
5
~ the inspector
found that procedure
QI 1-PR/PSL-2,
Revision 32,
"Operations Organization," still described
the Nuclear Watch Engineer
(NWE) as required for minimum crew manning.
Since mid-June,
the
licensee
had allowed the
NWE position to remain
unmanned
as
a temporary
response to Violation 50-335,389/97-04-02,
"Routine Use of Heavy
Operator Overtime."
The licensee identified the needed
revision on June
19 and started the procedure
change
process.
Because
Procedure
ADM
11.03 'evision
1
~
"Temporary Change to Procedures."
did not permit QI's
to be processed
as temporary changes,
the licensee
was forced to perform
a normal procedure revision.
The revised procedure
was approved
by the
Facility Review Group and signed
by the Plant General
Manager
on July
14.
On August 5,
Document Control issued the procedure.
putting it into
effect.
The Operations Assistant Supervisor stated that
he did not
place
a higher priority on the change
because
he did not believe that it
was warranted.
His primary focus
was to get the procedures
that were
used regularly changed.
He understood that the operations staff rarely
read
QI 1-PR/PSL-2
and did not affect the routine of the Operations
Department.
Section 4.2 of Procedure
QI 1-PR/PSL-2,
Revision 32, stated,
"The
Operations
group consists of five (5) or more shifts with a Nuclear
Plant Supervisor
in charge of each shift.
Each shift consists of the
required
operators
discussed
in Section 5.2 of this procedure."
Section
5.2.5 stated that
a Nuclear Watch Engineer
was
a requi red position to be
manned.
The licensee routinely left the
NWE position unmanned
since
June 9.
For both units, Technical Specification 6.8. l.a requi red that
procedures
recommended
in Appendix A of Regulatory Guide 1.33,
Revision
2, including minimum shift staffing,
be maintained
and followed.
This
failure constitutes
a failure of minor significance,
and is being
treated
as
a Non-Cited Violations consistent with Section
IV of the
NRC
Enforcement
Manual,
NCV 50-335,389/97-10-01 'Failure to Update
a
Procedure."
The inspector also noted that the licensee
issued the first set of ARPs
in the Unit 1 control
room.
Each annunciator
panel still had
a response
procedure
book associated
with it.
Each
book now contained
a specific,
one-page
response
procedure for each annunciator
window.
This was
a
significant improvement over the old ARPs.
Operators
stated that the
new procedures
were more useable
and accurate
than the old procedures.
They liked the ability to revise
a single annunciator
response
without
revising the entire book.
A brief audit of the Controlled Wiring
Diagram
(CWD) references
by the inspector
revealed
a significant
improvement in their accuracy.
Of the ten
ARPs reviewed,
the inspector
found no deficiencies
in the references.
The licensee
scheduled
the
upgrade for completion by December
1998.
The inspector
reviewed the procedure revision process.
The licensee
could change their procedures
in two ways.
The simplest
method
was
a
temporary change.
As described
in Procedure
ADH 11.03.
Revision
1,
"Temporary Changes to Procedures,"
personnel
should generate
a
TC when
they could not perform 'a procedure
as written and time constraints
would
not allow revision via the normal procedure
change
process.
The
procedure
change
could not change the intent of the original procedure.
requi re
a Facility Review Group
(FRG) review. or was not
a Quality
Instruction,
Emergency
Plan Implementing Procedure,
or an Emergency
Operating
Procedure.
Furthermore the procedure
required the following:
A qualified reviewer perform
a
10 CFR 50.59 screening
on the
A member of plant management staff review the procedure
change to
determine if a cross-disciplinary
review was required
A member of plant management staff verification that no change of
intent was involved
A member of plant management staff verification of technical
adequacy
Another member of plant management staff to review the forms and
determine the need for a
FRG
Technical Specification 6.8 also requi red the review by two members of
plant management
and by the
FRG within fourteen days.
The inspector
reviewed fifteen recent
TCs.
No discrepancies
were noted.
The licensee
performed
normal procedure
changes
according to procedure
QI-5-PSL-1, Revision 2, "Preparation.
Revision,
Review/Approval of
Procedures."
This procedure
requi red those appropriate
subcommittee
reviews,
10 CFR 50.59 screenings,
UFSAR reviews,
and
FRG reviews
be
performed.
The inspector
reviewed nineteen
recently approved
procedures
from Operations,
Haintenance,
Administrative,
Emergency Operating
Procedures,
and
Emergency
Plan Implementing Procedures.
The inspector
reviewed
them for agreement
with licensing documents
and for
administrative compliance.
The inspector
found no deviations.
The licensee actively tracked the procedure
backlogs,
the number of
procedure
changes
due to technical
inaccuracies,
and the number of
active
TCs as indicators of their performance.
The inspector noted
a
positive trend in all areas for the last few months.
At the beginning
of July. the procedure
backlog was approximately
76 items.
They were
equally distributed
among word processing,
proofreading,
and
~7
04
04.1
10
administrative holds such
as training.
At the beginning of August the
backlog was
down to 42 items.
This time, however,
about half the
backlog was for an administrative hold.
Technical
inaccuracies
were
down during 1997 over
a comparable
period last year.
Most notably, the
licensee
reduced the inaccuracy rate for the improved procedures
to
about
2 percent of the issued
improved procedures.
This was
down from
approximately
6 percent the year before.
The non-improved procedures
also had
an inaccuracy rate of about
2 percent for 1997.
Conclusions
The procedure
upgrade
program at St. Lucie was scheduled to continue
into December
1999.
The prioritization of upgrading
was generally
appropriate.
However. the licensee
may not have allocated sufficient
resources
to attain the completion date
as evidenced
by the large
percentage of'he project remaining combined with the burden of normal,
non-upgrade
revision of the remaining procedures.
Overalls the
inspector
determined that the procedures
were adequate
to perform their
intended function, availability of current revisions
was good,
and the
procedures
were usable, particularly the upgraded
versions.
Although
the licensee
had issued only a small percentage
of upgraded
ARPs, the
inspector
noted that they were
a significant improvement over the older
versions.
The inspector determined that control of procedure
changes
was adequate.
The inspector
found
a positive trend in procedure
backlog
reduction.
One
NCV was identified for failure to properly revise
a
procedure to update the Operations staffing requirements
following a
change to those requirements.
Operator
Knowledge and Performance
0 erations
Swa
in
Gas
Deca
Tanks
71707
Ins ection
Sco
e
The inspector witnessed
an operator
remove the
1B Gas
Decay tank
(GDT)
from service
and place the
1A GDT in service.
In addition, the waste
gas analyzer
was aligned for service.
Observations
and Findin s
On July 30, the inspector witnessed
an operator
remove the
1B GDT from
service
and place the
1A GDT in service.
The operator
had
and followed
the appropriate
procedure.
The inspector
noted that when the operator
had questions
about the evolution, control
room operators
were contacted
for resolution.
While performing the valve lineup for placing the waste
gas analyzer in service,
the inspector
noted that the operator verified
= a valve closed rather
than open
as required
by procedure.
When
questioned
by the inspector
the operator .reviewed the procedure,
noted
the error,
and opened the valve.
Additionally. the inspector
noted
several
tools inside the panel
housing the waste
gas analyzer.
It
appeared
as though they were left by maintenance
personnel.
The
.It
11
appropriate
licensee
representative
was notified and the tools were
removed.
Conclusions
The inspector
noted that the operator
was careful
and methodical
in
performing this evolution.
Although the operator misread
one step,
overall procedural
adherence
was good.
Full Len th Control
Element
Assembl
Test
61726 71707
On August 22, the licensee
performed
a Full Length Control Element
Assembly test
on Unit 1 per Procedure
OP 1-0110050,
Revision 35,
"Control Element Assembly Periodic Exercise."
This test
had been
originally started the previous
day but was delayed after dropping
a
CEA.
The inspector noted that the actual testing
was being performed
by
an operator -in-training and supervised
by a qualified operator.
An
extra operator
was assigned
to the shift to allow the operators
performing the test to concentrate
on the test.
The operators
performed
the test according to the procedure
and kept the
ANPS informed of the
status
at all times.
Operator attention to the test
was good.
The pre-
job briefing was adequate
for the task.
Miscellaneous
Operations
Issues
Closed
LER 50-389/96-001-00
"Manual Reactor Tri
Due to Hi
h Main
Generator
Cold Gas
Tem erature"
92901
On January
5,
1996, Unit 2 was manually tripped by utility licensed
operators
due to an increasing
main generator
cold gas temperature.
The
primary cause of this event
was the fai lure of Temperature
Control Valve
(TCV) TCV-13-15 to automatically regulate cooling water flow from the
main generator
hydrogen coolers following local closure of the
bypass
valve.
A subsequent
inspection
showed that the valve controller
derivative setting
was incorrectly adjusted.
Post maintenance testing
performed after recent controller maintenance
was insufficient to assure
proper
system operation.
A contributing factor was the failure of
Operations
personnel
to adequately
monitor the evolution and ensure that
system
response
was as expected
following the local actions.
Several
unexpected
SG low level indications were received following the trip and
were subsequently
found to be caused
by partial sensing line blockage
from accumulated
corrosion products.
Corrective actions for this event included 'the following:
2)
3)
The TCV controllers setting
was adjusted prior to returning Unit 2
to service.
Additional controllersin other plant systems
were inspected for
proper operation.
Post maintenance
testing of controllers
was reviewed for adequacy.
4)
5)
6)
7)
8)
12
Operations
evaluated
generic implications and required additional
oversight for this evolution in the future.
Controller setpoints
were reviewed f'r inclusion into a data
base.
Unit 2
SG level instrumentation
sensing line blockage
was cleared,
and instrument performance
was revi ewed for Unit 1.
SG level sensing lines
and others
deemed susceptible will be blown
down in the future as part of a preventative
program.
Plant procedures
were revised to facilitate early detection of
instrumentation
discrepancies.
The inspector
reviewed the licensee's
corrective actions
and determined
that they had been completed satisfactorily.
Therefore, this item is
closed.
Closed
LER 50-335/96-003-00
"Containment Particulate
and Gaseous
Monitor Out of Service Resultin
in a Condition Prohibited
b
Technical
S ecifications
Due to Personnel
Error"
9Z901
This subject
LER documented
a
HP technician failing to return
a throttle
valve to its open position after
a containment air sample
was obtained
on February
22,
1996.
The root cause of this event
was personnel
error
attributed to the
HP technician for not following procedure.
Subsequently,
VIO 50-335/96-04-01,
"Failure to Follow Procedures
Lead to
Unit 1 Containment
PIG Inoperability," was issued for this event.
The
details of this incident were previously discussed
in Inspection
Report
97-06,
Paragraph
08. 1.
The inspector
reviewed the licensee's
corrective
actions for this event
and found that they had been satisfactorily
implemented.
Therefore, this
LER is closed.
Closed
LER 50-335/96-004-00
"Inadvertent
Manual Start of the
1A
Emer enc
Diesel Generator
Due to Personnel
Error"
9Z901
Ins ection Sco
e
On February
27,
1996,
an inadvertent
manual start of the lA Emergency
Diesel Generator
(EDG) was initiated when an Instrumentation
& Control
(I&C) technician,
working inside the
1A EDG control cabinet.
accidentally
bumped the actuating
stem on
a relay mounted
on the inside
of the cabinet.
The inspector
reviewed the event
and the subject
LER.
Observations
and Findin s
The investigation determined that the root cause of this event
was
personnel
error.
The Nuclear Plant Work Order
(NPWO) recommended that
a
clearance
be used.
A sign was posted
on the front of the
EDG control
cabinet
door warning that there
was equipment inside the cabinet which
could cause
an
EDG start.
The
I&C Supervisor did not request
a
clearance
before scheduling
work to commence in the
EDG control cabinet.
The acting control
room supervisor authorized
work to commence in the
1A
EDB control cabinet without a clearance.
Corrective actions were
inclusion of the
EDG control cabinet
under requirements of Procedure
0010142,
"Unit Reliability-Manipulation of Sensitivity Systems,"
13
personal
discussion of the incident and its importance with the
responsible
parties
by the licensee
management.
and
a special training
bulletin to all maintenance
and operations
personnel
that reinforced the
~
importance of using clearances
to avoid inadvertent actuation of plant
equipment
The inspector
reviewed the licensee's
corrective actions for this event
and found that all corrective actions
had been satisfactorily
implemented.
However, the inspector
found that Procedure
AP 0010142
'Unit
Reliability-Hanipul.ation of Sensitivity Systems."
was later
deleted
and incorporated into Procedure
ADH 0010432,
"Nuclear Plant Work
Orders."
Subsequently,
the inspector
reviewed the following plant
procedures
and discovered that they still referenced
Procedure
0010142.
Operations
Policy OPS-502,
Revision 0, "Pre-Evolution Briefs"
AP 0010532,
Revision 6, "Relay Work Orders"
ADH 08.01,
Revision 6,
"On-Line Leak Sealant
Procedure"
AP 0010460,
Revision
10, "Critical Maintenance
Hanagement"
AP 0005758,
Revision 7, "Electrical Maintenance
New Employee
Indoctrination Guidelines"
ADH 17.07,
Revision 3,
"Flow Accelerated
Corrosion Inspection
Implementation
Program"
The discrepancies
were brought to the licensees'ttention
and
subsequently,
a Condition Report 97-1584 was initiated to perform root
cause evaluation
and to determine
any potential generic implications
and
corrective actions.
The fai lure by the licensee to remove
a reference
of Procedure
AP 0010142
from the affected plant procedures
was
identified as
a weakness
in the licensee's
procedure
upgrade
program.
Conclusion
The inspector determined that the licensees'orrective
actions
were
appropriate to avoid
a repeat
event.
However, the failure by the
licensee to remove
a reference of AP 0010142 from the affected. plant
procedures
was identified as
a weakness
in the licensee's
procedure
upgrade
program.
08.4
Closed
VIO 50-335 389/96-11-04
"Preconditionin
of Valves Prior to
Surveillance"
92901
This violation documented
the failure of the licensee to ensure that the
procedures
(AP 1-0010125A,
Revision
39 and
AP 2-001025A,
Revision 43)
were performed
under suitable environmental
conditions.
Specifically,
these
.two procedures
allowed four containment
spray valves to be
lubricated prior to being tested:
The details of this incident and the
08.5
M1
Ml. 1
licensee's
cor rective actions
were previously discussed
in Inspection
Report 96-11,
Paragraph
E2. 1.
The inspector
reviewed the licensee's
corrective actions
as specified in the Florida Power
& Light (FPL)
response to the subject Notice of Violation (NOV), dated
September
27,
1996.
The inspector verified that all corrective actions were properly
implemented.
Therefore, this item is closed.
Closed
VIO 50-335 389/96-16-02
"Failure to Control
0 eration
Ke s"
~92901
This violation addressed
the licensee's
failure to properly control the
keys used for the electrical isolation of the Power Operated Relief
Valves
(PORVs)
as required
by Procedure
AP 2-0010123,
"Administrative
Control of Valves,
Locks and Switches."
The inspector
reviewed the
licensee's
corrective actions
as specitied in the
FPL response
to the
subject
NOV, dated October
18 '996.
The inspector verified that
ail'orrective
actions
were properly implemented.
Therefore, this item is
closed.
II. Maintenance
Conduct of Maintenance
Chemical
and
Volume Control
S stem Ion Exchan er Resin Oischar
e
62707
Ins ection Sco
e
The inspector
observed portions of the Chemical
and Volume Control
System
Ion Exchanger
Resin Oischarge
on Unit 1.
The inspector
reviewed
the radiological controls in place
and operator
procedural
conformance
and knowledge of the evolution.
Observations
and Findin s
Resin discharge
was
done in accordance
with Procedure
OP 1-0520020.
Revision 36.
"Radioactive Resin Replacement"
in conjunction with Health
Physics
Procedure
HP-40, Revision 43,
"Shipment of Radioactive
Material."
The licensee
discharged
the resin to a shipping container
staged
outside the Reactor Auxiliary Building (RAB).
The container
was
then sealed
and shipped offsite for burial at an approved site.
On July 29. the inspector
observed
the discharge of the
1B CVCS
purification ion exchanger.
The inspector
noted
good coordination.
between Operations
and Health Physics.
All personnel
appeared
to be
fami liar with the procedures'nd
communications
were generally good.
The inspector
did notice
a short period when communications
between the
shipping container
and inside the
RAB were lost.
An extra person
was
dispatched
from the container into the
RAB to inform them that the radio
was not working at that location.
The resin discharge
and flush were
completed without further problems.
'
e
Conclusions
15
The
1B ion exchanger
resin was discharged
according to procedure with no
major problems
noted by the inspector.
Good coordination
was noted
between the groups involved in the activity.
Calibration of the
2A Hi
h Pressure
Safet
In ection Dischar
e Pressure
Indicator
62707
Ins ection
Sco
e
The inspector witnessed
I8C personnel
calibrate the
2A High Pressure
Safety Injection (HPSI) discharge
pressure
indicator in accordance
with
Work Order
(WO) 97010910
and
I8C Procedure
2-140064P,
Revision 36,
"Installed Plant Instrumentation Calibration (Pressure)."
Observations
and Findin s
On July 30, the inspector witnessed
I8C perform portions of a
transmitter calibration.
The inspector verified the proper procedure
was being used,
the
M&TE was calibrated
and control led,
and the
appropriate prerequisites
had been completed.
After the transmitter
was
isolated
and the test equipment attached.
the technicians
noted the
pressure
indication increasing
on the test meter.
With the transmitter
isolated.
the pressure
should not have increased.
The test equipment
was
removed,
a valve lineup of the transmitter
completed
and the
equipment
reattached.
The transmitter again indicated
an increasing
pressure.
The technicians
manually increased
the pressure with an
installed pressure
source
and noted
an erratic response
from the
transmitter.
The technicians initially thought the transmitter
had
failed but noted that neither of them had ever seen
one fail in that
manner.
After several
minutes of discussion
one of the technicians
recalled having seen
a similar problem when Neolube was accidently
dropped
on the circuit board located inside the transmitter.
The
transmitter
was opened
and Neolube was found on the board.
Neolube is
a
conductive lubricating material that is applied to the threads of the
end caps
on the transmitter.
Prior to starting the calibration, the
technicians
had opened the transmitter to perform another part of the
procedure.
While applying the Neolube,
the technician accidently
brushed
a small
amount onto the circuit board.
After cleaning the
neolube
from the board,
the transmitter
was successfully calibrated.
Conclusions
The experience
and knowledge of the technicians calibrating this
instrument resulted in timely repair of a unique problem.
16
Governor Maintenance
and Load Run on 28 Diesel Generator
61726
62707
Ins ection
Sco
e
On August 28, the licensee
scheduled
preventive maintenance
on the
28
Emergency Diesel Generator to occur just prior to the monthly load run.
The inspector
observed
the coordination
between
maintenance
and
operations
and portions of the subsequent
load run.
Observations
and Findin s
On July 10, the
2A EDG experienced erratic behavior
due to set screws
on
the mechanical
governor vibrating loose.
The licensees'epair
was to
install the set screws with lock-tite.
On August 28, the licensee
scheduled
the 28
EDG for its monthly load run and determined that this
would also be an ideal opportunity to perform the maintenance
on this
diesel's
governors.
Because
the diesel
is inoperable for a period when
the Senior Nuclear Plant Operator
(SNPO) jacked the machine.
the
licensee
planned to perform the maintenance
then.
Shortly after the start of peak shift on August 28, the
ANPS held
a
brief with the crew.
The briefing consisted of those individuals
involved in the evolution and covered the precautions of the operating
procedure
and contingency actions for possible failures.
The ANPS 'also
covered the maintenance activity allowing the System
Engineer
time to
discuss
the job and the reason
behind it.
Overall the inspector judged
the brief to be above average.
At 4:45 p.m., the
SNPO entered
the
EDG room to begin work, the
electrician
was already in the room near the 281
EDG governor.
They
performed the maintenance
in accordance
with Work Order 97017209
01.
The procedure
had the electrician
remove each of the three set screws
one at
a time and reinstall with lock-tite.
Any problems were to be
resolved with the System Engineer
who was
on station.
The work did not
begin until the
SNPO disabled the diesel for jacking purposes.
This was
essentially
a tagout without paper.
The inspector questioned
the
Quality Assurance
(QA) Manager,
who was present for the evolution.
about
the need for a clearance.
He brought in the System Engineer to explain
why no tags were needed.
He explained that this was just an extra
precaution,
no tags would be needed
at all for his safety since
he was
not near
any rotating equipment.
Although the Equipment Clearance
Procedure
is not clear for this case,
the inspector
was satisfied that
the worker's safety
was not in jeopardy.
The
QA Manager initiated
a
Condition Report
(CR 97-1668) to clarify the issue.
The maintenance
was
performed
per the work order and in a timely manner.
The inspector
judged this to be an effective use of the inoperable diesel time.
The licensee, started
and ran the 28
EDG according to Procedure
OP 2-
22000508,
Revision 30,
"28 Emergency Diesel Generator
Periodic Test and
General
Operating Instructions."
The inspector
noted that the
SNPO
appeared
very familiar with the machine,
and followed the procedure
as
written.
The inspector did not see
any anomalies with the load run.
Conclusions
17
The inspector
observed
maintenance activity on the 28
EDG followed by
the monthly load run.
The combination of the maintenance
and load run
was considered
a strength in reducing unnecessary
starts
and periods of
inoperability of the diesel.
Unit 2 Char in
Pum
Accumulator Pressure
Checks
62707
Ins ection Sco
e
The inspector witnessed
the licensee
charge the suction
and discharge
pressure
for the
2A charging
pump.
Observations
and Findin s
This maintenance
was performed in accordance
with WO 97015744
and
Procedure
HP-2-H-0018,
Revision 52,
"Charging
Pump Accumulators
2A,
2B,
and
2C Pressure
Check/Recharge."
The inspector verified the proper
revision of the procedure
was used,
the
H&TE calibration of the
instrumentation
was current,
and the prerequisites
had been completed
prior to starting work.
The nitrogen supply was from installed piping connected
to the plant
nitrogen system.
To charge the accumulators,
the licensee
simply
connected
high pressure
hoses
and
a small
pump between the installed
piping and the accumulators.
The maintenance
personnel
were very
familiar with performing this work and completed the task
satisfactorily.
The only discrepancy
noted by the inspector
was also identified by the
licensee
and promptly corrected.
One of the maintenance
workers
slightly stepped into the roped off contamination
zone.
The health
physics technician
assigned to monitor the work, saw this occur and
instructed the worker to step back.
A survey was conducted
and the area
was found to be clean.
Conclusions
The 2A charging
pump accumulators
were charged properly in accordance
with site procedures.
Oia nostic Testin
of 2-V2525
Boron Load Control Valve
62707
Ins ection Sco
e
The inspector witnessed
portions of the performance of Haintenance
Procedure
0940079,
Revision 6,
"VOTES 100 System Operating," which was
used to perform testing for the 2-V2525.
Observations
and Findin s
18
This valve was being tested
monthly because
Engineering
had previously
identified that the thrust at the torque switch trip was less than
requi red.
This information was documented
in CR 97-1190
and the testing
was being tracked
by PHAI 97-06-282.
The
CR concluded that the problem
was
a result of inadequate
lubrication at the stem/stem
nut interface.
This area
was cleaned
and relubricated.
The
CR required testing
was to
be performed monthly for six months to monitor the condition.
The inspector
reviewed the
WO that actually contained the work
instructions
and noted that all the prerequisites
had been completed.
The procedure
was reviewed
and noted to have several
missing signatures.
Discussion with the personnel
performing the activity, revealed that
-tables at the back of the procedure
contained the
same signoffs
as those
in the body of the procedure.
The signoffs in the table had been
completed.
Upon discovery,
the duplicate steps
in the body of the
procedure
were signed
as well.
The inspector witnessed
the valve being stroked
and data being taken.
After the data
was reviewed,
the analyst
concluded that the valve was
operating properly and
no additi'onal testing or maintenance
was
required.
Conclusions
The inspector
concluded that the personnel
observed
performing this task
were qualified and knowledgeable
about diagnostic testing.
No
discrepancies
were identified with this evolution.
Unit 2 Reactor
Protection
S stem Testing
61726
ti
S
The inspector witnessed
portions ot the performance of two Reactor
Protection
System
(RPS) survei llances,
I8C Procedure
2-1400160.
Revision
13.
"Channel Calibration delta
T power
- Quarterly,"
and 2-1400198,
Revision 4,
"RPS Channel Calibration Variable High Power Quarterly."
Observations
and Findin s
The inspector
observed
two technicians
perform the Channel
A portions of
each of these tests.
The procedures
were noted to have
been well
written and required little interpretation.
The technicians
were
observed to follow the procedure
verbatim.
In addition, the inspector
noted that the technicians
were extremely knowledgeable
about the
equipment
being tested
and the procedures
being used.
Conclusions
The inspector noted the technicians
were knowledgeable
about both the
equipment
and the procedures
being used during these survei llances.
In
addition, the procedures
were noted to have
been well written and easy
to follow.
C
M2
Maintenance
and Material Condition of Facilities and Equipment
M2. 1
Material Condition of Plant
62707
71707
a.
Ins ection Sco
e
During routine tours
and maintenance
inspections,
the inspectors
identified
a number of items impacting the overall material condition of
the plant.
b.
Observations
and Findings
During routine plant tours
and inspections,
the inspectors identified
the following items:
On July 7, tools were found inside of the Unit
1 waste
gas
analyzer
panel
On August 21,
on Unit 1,
an unsecured
ladder
was found wedged
between the
1B battery
room wall and the
125 volt DC load test
panel in the cable spreading
room.
On August
21 and September
5,
on Unit 1,
an unsecured
ladder
was
found leaning against the 480 volt load center
1A2.
On August 21,
on Unit 2,
Door
RA84, located
on the 19.5 ft
elevation of the
RAB was found blocked open.
A sign attached to
the door stated that people exiting were to ensure the door
was
closed.
On August 27; fire locker 4, located
on the 43 ft elevation of the
Unit
1 RAB, contained four flashlights
used
by the fire brigade.
One of the flashlights contained
a dead
battery
and the other three flashlights were extremely dim.
On August 27,
on Unit 2, fire door 43, located
on the 19.5 ft
elevation of the
RAB, was found blocked open.
On August 28,
on Unit 2,
an unsecured
ladder was
f'ound leaning
against the wall in the
CVCS hallway,
on the 19.5 ft el'evation of
the
RAB.
On September
3, the access
doors to the
1A and
1B LPSI
pump rooms
were found to have
been secured
by only one latch.
Each door has
eight latches.
On September
3,
an unsecured
ladder
was found erected
over -the
2B
containment
spray
pump instrumentation.
M7
M7.1
20
Each of these conditions were brought to the licensees'ttention
and
were promptly corrected.
In addition,
on August 29, scaffold located in the Unit I fuel transfer
canal
was found suspended
by carbon steel
cables.
Procedure
QI 13-
PR/PSL-2,
Revision 31,
"Housekeeping
and Cleanliness
Control Measures,"
Step 9.D.8, states
that materials fabricated
from carbon steel shall not
be stored in the pool.
However, the procedure
did not specifically
apply the
same restriction to the fuel transfer canal.
Reactor
Engineering
and Chemistry were contacted to determine if this was
a
concern.
The Chemistry supervisor stated that carbon steel
components
were not allowed in the spent fuel pool because
the boric acid solution
would cause
the component to deteriorate.
He stated that although.
on
occasions
the fuel transfer canal
and the spent fuel pool communicate
with one another.
the cable would not be
a problem as long as it did not
remain there underwater for an extended
period of time.
The inspector
verified that the maintenance activity was performed in a dry atmosphere
and therefore would not be
a concern with respect to boric acid induced
degradation.
Conclusions
While plant cleanliness
was generally acceptable,
more attention
was
warranted.
Quality Assurance in Maintenance Activities
Lon standin
Gai -troni cs Defici enci es
62707
Ins ection Sco
e
In July, Quality Assurance
issued
an audit report
(QSL-EP-97-05) that
documented
several
Emergency
Plan deficiencies.
QA's first finding
discussed-the
licensee's
ineffectiveness
in resolving longstanding
audibility problems of the Gai-tronics public address
system.
The
inspector
reviewed QA's finding and the licensee's
response
to correct
the problem.
Observations
and Findin s
The
Gai -tronics system
was the St. Lucie site's
primary means of
notification to personnel
in case of an emergency.
Section 4.6 of the
Emergency
Plan,
Revision 32, stated,
"The LPublic Address]
(PA) system,
with speakers
strategically located throughout the Protected
Area,
provides for the transmission of warning and instructions in the event
oi an emergency."
The licensee
concluded that, "... the Gai-tronics
system
has not received the necessary priority and attention to maintain
acceptable
system performance."
QA further concluded,
"Corrective
actions to address
Gai-tronics deficiencies
have not been successful
in
resolving long term problems."
'
21
In November
1994, the licensee initiated St. Lucie Action Report
(STAR)
0-94110315 to assess
the
PA coverage at the site and to make necessary
improvements to the system.
The licensee
issued
Plant Manager's Action
Item (PMAI) PM 96-02-423 to close out the
STAR and carry out corrective
actions.
Initially, a due date of April 1,
1996,
was assigned
but was
later changed to September
1,
1996.
In November
1996,
Inspection Report
50-335,389/96-18
documented
a licensee
weakness
in failing to ensure the
implementation of timely corrective actions, specifically fai ling to
correct Gai-tronic audibility deficiencies identified in STAR 0-
94110315.
In December
1996, the licensee
audited the site wide audibility of the
Gai-tronics system,
identifying several
deficiencies.
The licensee
issued
a Nuclear Plant Work Order,
WO 97001256 to address
these
deficiencies.
At the time of the
QA audit,
some items
had been repaired
but the work order remained
open.
QA identified that the system ground
readings
were low. troubleshooting
was difficult, and other maintenance
priorities were taking precedence.
The audit went on to discuss
several
other
documented
problems with the
Gai-tronics system identified by plant personnel.
Condition Report 97-
0296 identified the lack of speakers
in the Management
Information
System office area.
Condition Report 97-0589 discussed
a loud hum from
the system in the control
room.
In May,
CR 97-0787 identified that
announcements
were not heard in the Unit 2 containment.
Finally,
Condition Reports
97-0998
and
CR 97-1009 identified the lack of working
speakers
in the North Service Building.
QA concluded that this finding was another
example of a weakness
previously identified by the licensee with less than effective
corrective action implementation
and follow through.
QA recommended
three actions.
First, the licensee
should commit the necessary
time and
resources
to promptly address
the problems.
Seconds
the licensee
should
start
a preventative
maintenance
program to periodically test
and repai r
the plant page system.
Third, the licensee
should review the impact of
additional
page stations prior to installation.
The inspector
found the
audit finding thorough.
the conclusions
accurate,
and the
recommendations
appropriate.
In June
1997, the licensee
formed
a task team to address
the
PA system
concerns identified in CR 97-0998
and
CR 97-1009.
The team's
recommendations
were not issued until after the
QA audit and therefore
included input from the audit.
NPWO 5306/67 identified which stations
were broken.
PMAI 97-07-119
was issued to track paging station repairs.
All repairs
were completed
by August 15.
The licensee established
a
surveillance
program for the system
on August 29.
The first test
occurred
on September
4.
The area tested
was in the turbine buildings
and steam trestles.
Although overall the test
was satisfactory.
several
discrepancies
were noted.
The licensee
captured the information in a
NPWO and repair work began that afternoon.
Last, the licensee
issued
PMAI 97-07-122 to develop
a tracking mechanism for the paging system
performance.
This was completed
on September
5.
Senior licensee
M8
H8. 1
a.
22
management
was holding those responsible for the completion of the items
accountable.
No due dates
were allowed to be extended without the
Manager's
and Site Vice-President's
approval.
The inspector
concluded
.
that the licensee
had committed the resources
to properly resolve the
. problems with the
Gai -tronic system.
The inspector
randomly verified the operability of Gai -tronic stations
in the power block.
All units checked
were operable.
Also the
inspector
ensured that the plant telephones
were working.
No problems
were noted.
Conclusions
The
QA audit on the Gai-tronics
problems
was well performed.
The
inspector
found the conclusions to be well founded
and the
recommendations
to be appropriate.
The inspector concluded that the
licensee's
response
was proper,
and the programs in place should
maintain the
Gai -tronic system acceptably.
Miscellaneous
Haintenance
Issues
Licensee Control of Nuisance
or Fre uentl
Alarmin
62707
37551
Ins ection Sco
e
The inspector
reviewed the licensees list of annunciators
in alarm. the
controlling procedure,
AP 0010120
~ Revision 94, "Conduct of Operations,"
associated
work orders,
and condition reports, to determine if the
licensee
was adequately
addressing this issue.
Observations
and Findin s
The inspector
reviewed the activities associated
with three
CRs
concerning
nuisance
Procedure
AP 0010120 defined
a
frequently alarming annunciator
as
one which was unexpected
and alarmed
at least twice in a twenty-four hour period.
It stated that action
should be initiated to correct the cause of the alarm.
This procedure
defined
a nuisance
as
one which was unexpected
and alarmed
greater than or equal to eight times in any eight hour period.
The
procedure
stated that immediate corrective action was to be taken to
correct the cause of nuisance
up to the point of calling
out the necessary
personnel
to correct the cause.
CR 97-1178
was written to document that when the Unit 2 station air
compressor
was started,
F-14, "Station Air Compressor
Temp
Hi/Overld/Trip," would alarm.
was written to troubleshoot
and repair.
Maintenance
determined
the problem to be associated
with
the overload trip/alarm contacts
on the 480
V breaker.
A scope
change
was
made to the
WO which allowed the alarm setpoint to be increased.
However, the setpoint
was still within the acceptable
limits previously
established
in the procedure.
The, work was successfully
completed in
e
23
accordance
with Procedure
HP 0920070,
Revision
10, "Periodic Maintenance
of 480 Volt ITE- Circuit Breakers,"
Section 4.0.
CR 97-1417
was written to document that Unit
N-25 was
a
frequent alarm.
This alarm was caused
by the reactor
drain tank
(RDT)
pressure
transmitter intermittently failing low.
Maintenance
performed
initial troubleshooting
in accordance
with WO 97013779,
which determined
the problem to be
a fai ling transmitter.
Because
the transmitter is
located in a high radiation area it was scheduled for replacement
during
the upcoming refueling outage.
The third issue involved annunciator
A-10.
"125 Volt DC Bus
1B Ground,"
which was continuously alarming
and was identified as
a nuisance
alarm
on June 8,
1997.
CRs 97-1265
and 97-0496 were written to document this
recur ring problem.
Initially Haintenance
located
grounds in the fire detection
system heat
detectors for the turbine lube oil and hydrogen seal oil systems.
was written to locate the faulty detectors
and replace
as
necessary.
This activity was completed 'on the turbine lube oil system
and the hydrogen
seal oil system
has
been scheduled for repair.
In addition,
a ground was found on
a wire associated
with the start
circuit for the
1A2 reactor coolant
pump.
This ground was isolated
by
lifting the affected wire.
This activity was documented
in temporary
system alteration
(TSA) 1-97-012.
Additional grounds still existed
on the system that have not yet been
located.
Engineering
concluded that the grounds
being detected
were
small
and not of major concern.
As
a result,
TSA 1-97-017
was developed
which disabled the annunciator
and installed
a voltage meter in the main
control
room.
Operations
personnel
monitored the meter hourly and if a
ground of a predetermined
magnitude
was detected,
the annunciator
response
procedure
was
implemented.
In addition, the sensitivity for
the ground alarm relays associated
with the
1B and
1BB battery chargers
was reduced in accordance
with engineering
evaluation
JPN-PSL-SEEJ-90-
029 and plant specific guidance.
At the end of this report period,
Engineering
was reviewing the ground detection
system to determine if it
needed to be modified to make it more effective.
Because
grounds still existed
on the system,
various circuits supplied
by the
1B bus,
were routinely monitored in an attempt to isolate
and
locate the remaining grounds.
The inspector
reviewed the
WOs and
TSAs associated
with the
aforementioned
problems.
Discussions
were held with numerous operators,
engineers.
and maintenance
personnel
regarding this problem.
In
addition, the inspector
reviewed the applicable
procedures
concerning
TSAs and nuisance
No discrepancies
were identified.
In addition;
CR 97-1265 indicated that corrective action to
repair/disable
A-10 was not taken,. in that personnel
E7
E7.1
24
necessary
to correct the problem were not called to the plant because
.
the event occurred
on
a weekend.
The inspector discussed this
CR with
Operations,
Maintenance,
and Engineering
management
and concluded that
the actions
taken were prudent.
The licensee stated that the personnel
knowledgeable
on the system were unavailable to respond
and searching
for electrical
grounds
was too risky to be performed without adequate
planning
and the proper staff.
However, sufficient staff was available
to determine that the grounds
causing the alarm were not sufficiently
large to warrant immediate .attention.
The inspector questioned
the licensee
about
why the annunciator
was not
disabled to prevent the operators
from being unnecessarily
challenged
and burdened
by it being in a constant state of alarm.
The licensee
stated that
a process
did not exist which would allow annunciators
to be
disabled without first being subjected to
a lengthy review process.
At
that time, annunciators
were being disabled
by the use of Procedure
0010124,
Revision 43,
"Temporary System Alteration Control."
However,
this process
requi red
a large amount of review/work by the system
engineer.
Because this person
was unavailable
when the annunciator
was
in constant
alarm, disabling the annunciator
was not considered
an
immediate option.
At the end of the report period, the licensee
was in
the process of developing
a procedure
which would allow the on shift
operators to disable annunciators,
upon successful
completion of a
screening
process.
This would result in a more timely response to
nuisance
Conclusions
The inspector concluded that frequent
and nuisance
place
an
unnecessary
burden
on the board operators.
The ability to rapidly
resolve annunciator
problems is crucial to ensure that
a valid
annunciator is not masked
by one which is in a constant state of alarm.
In the examples
discussed
above,
the inspector concluded that the
licensee
was actively and methodically working to locate
and isolate
grounds 'associated
with this
DC bus.
The effectiveness
of rapidly
resolving nuisance
annunciators will be enhanced with the implementation
of the proposed
procedure for disabling nuisance
III. En ineerin
Quality Assurance in Engineering Activities
ualit
Assurance
Audits and Assessments
40500
Ins ection Sco
e
The inspector
reviewed selected daily quality reports,
audit reports,
and techni ca 1 revi ew acti vity reports.
These vari ous reports
documented
oversight activities of the Site Quality Assurance
Department.
The
inspector also reviewed selected self assessment
activities performed
by
Site Engineering.
The inspector
reviewed the audits
and assessments
to
I
25
determine if findings were documented
and processed
in accordance
with
the licensee's
corrective action program
and
NRC regulations.
Observations
and Findin s
The inspectors
noted that Site
QA had observed
various activities which
involved Site Engineering.
These observations
were documented
in QA
Quality Reports.
Site
QA had issued over 20 Quality Reports since
January
1997.
The inspector
noted that nearly 50 percent of the
Quality Reports
found unsatisfactory results for activities related to
Site Engineering.
Site
QA issued condition reports to document the
unsatisfactory results.
Site Engineering
had initiated actions to
address
the
QA observations.
The inspector
reviewed
QA Audit Report QSL-EFF-97-01.
During this
review, the inspector
noted that one of the audit findings identified
configuration control concerns
regarding quality related equipment (fire
prot'ection equipment
as
an example) that were not clearly identified as
quality related in the Total Equipment
Data
Base
(TEDB).
Condition
Report 97-0592 documented
other quality related
equipment that was not
properly identified in the
TEDB.
Site Engineering initiated corrections
to address this
QA finding.
The inspector also reviewed
QA Audit Report
08.03.MKFOHV.97. 1*.
This
audit was
a limited scope audit performed
on the Steam Generating
Team
Ltd.
(SGT) design control process.
SGT is
a Morrison Knudsen
Corporation
and
Duke Engineering
& Services,
Inc.,
company which the
licensee
had contracted with for the engineering
and replacement of the
Unit
This audit was performed
by the quality
assurance staff put in place
by the licensee to provide oversight of the
Replacement
Project
(SGRP) activities.
The inspector
noted that the audit team identified four findings.
The audit findings
were being addressed
by SGT management.
The inspector also reviewed selected
QA Technical
Review Activity
Reports.
These monthly reports provided
a summary of oversight
activities completed
by the Technical
Review and Assessments
(TRA) group
within Site
QA.
The inspector
noted that the
TRA group was responsible
for performing the independent
technical
review function that had been
performed previously by the Independent
Safety Engineering
Group (ISEG).
The
ISEG function was transferred to the
QA organization
as
a result of
a licensee
Technical Specification
amendment
request that was approved
by the
NRC on December
22,
1994.
The inspector
reviewed
TRA monthly
reports for the period January
1997, through July 1997,
and focused
on
the engineering activities reviewed by the
TRA group.
The inspector
noted that the
TRA group identified
a number of findings and initiated
'several
CRs
as
a result of the activities observed.
The inspector
noted
that Site Engineering
was taking actions to address
the findings
identified by the TRA group.
In addition to reviewing the
QA audit and assessment
efforts. the
inspector also reviewed the results. of the Site Engineering self
E8
26
assessment
for the second quarter of 1997.
This self assessment
covered
the performance of Site Engineering for the months of March, April. and
May.
and was centered
around the St.
Lucie Unit 2 Cycle
10 refueling
outage activities.
The inspector
noted that the self assessment
of Site
Engineering
found areas of strength,
areas that were acceptable.
and
areas for improvement.
Site Engineering
had initiated actions to
address
the areas for improvement.
Conclusion
The inspector
concluded that the
QA audits
and assessments,
and the Site
Engineering self assessment
efforts were effective in providing
oversight of Engineering activities
and identifying areas
for
improvement
and increased
management
attention.
The inspector verified
that findings identified by the licensee during the audits
and
assessments
were documented
and processed
in accordance
with the
licensee's
corrective action program requi rements
and
NRC regulations.
Miscellaneous
Engineering
Issues
U dated Final Safet
. Anal sis
Re ort Review Pro
ram
37550 40500
Ins ection Sco
e
The inspector
reviewed the results of the licensee's
Updated Final
Safety Analysis Report
(UFSAR)/Procedure
Consistency
Review effort to
determine if the findings identified by the licensee
were documented
and
processed
in accordance
with the licensee's
corrective action program
and
NRC regulations.
The inspector also reviewed the status of the
licensee's
efforts to conduct
a graded
review of the St. Lucie Unit
1
and Unit 2 UFSARs.
Observations
and Findin s
UFSAR/Procedure
Consistenc
Review
The licensee,
initiated this
UFSAR review as part of the corrective
actions for a violation issued
by the
NRC for the St.
Lucie Unit
1 Boron
Dilution Event of January
22,
1996.
In a letter dated April 23,
1996,
FPL committed to review the Unit 1 and Unit 2 UFSARs and plant
procedures
for mutual consistency.
This review was to be completed
by
December
31,
1996.
The Site Engineering
Department
was assigned
the lead to perform the
review of'he
UFSARs and procedures.
The licensee
formed
a
project team in August 1996 'hich consisted of personnel
from Site
Engineering,
Operations,
and
QA.
Quality Instruction
ENG-QI 6.7,
"FSAR
Reviews,"
was followed for the classification of the review findings.
All chapters of the
UFSAR for both units were reviewed by Engineering
and Operations
personnel.
Procedures
and procedural
processes
that were
mentioned in the
UFSAR were identified.
Mutual consistency
between the
procedures
and the
UFSAR was established
and the inconsistencies
were
27
identified and documented.
After the licensee
completed both
reviews. the inspector
noted that recommendations
for UFSAR corrections,
procedure
changes,
and plant modifications (if required)
were
prioritized and scheduled for disposition.
The inspector
noted that the results of the St. Lucie Unit
1
UFSAR/Procedure
Consistency
Review were documented
in FPL inter-office
correspondence
JPN-SPSL-96-0560 'ated
December
30,
1996.
This review
resulted in a total of 41 CRs,
129 PHAIs,
206 Procedure
Change
Requests
(PCR),
and
80
FSAR Change
Packages
(FCP) being issued to document
and
track the findings.
There were no Unit
1 modifications required
as
a
result of this review.
The inspector noted that the results of the St. Lucie Unit 2
UFSAR/Procedure
Consistency
review were documented
in FPL inter-office
correspondence
JPN-SPSL-96-0562,
dated
December
31,
1996.
This review
resulted
in
a total of 26 CRs,
181 PHAIs,
228
PCRs,
and approximately
65
FCPs being issued to document
and track the findings.
The inspector
noted that there
was one Unit 2 modification which resulted
from this
review.
A condition was identified by the licensee
where
an
commitment
had not been
met by the plant design in that the control
power for the primary and the back-up protection for the Reactor
Coolant
Pump
(RCP) feeders
was being provided from the same battery.
The
licensee initiated Plant Change/Hodification
(PC/H) 97015 'CP Relaying
Hodification
~ to address this finding.
This
PC/H was classified
by the
licensee
as being non-nuclear safety related.
The inspector further
noted during review of the licensee's
results that
completion of the corrective actions for the
UFSAR findings was not tied
to the December
31,
1996,
NRC commitment date.
The licensee
had
developed workoff curves
and schedules
to track completion of all the
findings.
The inspector
concluded that the findings identified by the licensee
during the UFSAR/Procedure
Consistency
Review were documented.
processed,
and being tracked in accordance
with the licensee's
corrective action program and
NRC regulations.
UFSAR Graded
Review
The inspector
reviewed the FPL's letter L-97-180, Voluntary Initiative
to Review Final Safety Analysis Reports,
dated July 11,
1997.
In this
letter,
FPL committed to conduct
a graded
review of the St. Lucie Unit
1
and Unit 2 UFSARs.
This review by the licensee
was being performed in
accordance
with the revisions that the
NRC published to its General
Statement of Policy
and Procedures
for Enforcement
Actions'Enforcement
Policy),
(NUREG 1600) to address
issues
associated
with
departures
from the
These revisions were published in the
Federal
Register
by the
NRC on
October
18,
1996.
28
In the July 11.
1997 letter,
FPL indicated that the reviews would be
prior itized according to risk significance
(based
on probabilistic
safety assessment
methods) of the systems
described
in the
sections.
The licensee
had established
four priority levels.
The
licensee
further indicated that the discovery phase of the Priority l.
2.
and
3 reviews
was expected to be completed
by October
18,
1998, but
some of the walkdowns that requi re access
to the containment buildings
may be completed during the Unit 2 refueling outage in 1998 and the Unit
1 refueling outage in 1999.
The licensee
indicated that the Priority 4
systems
may be reviewed,
pending the outcome of the Priority 1, 2,
and
3
reviews.
The inspector
noted that the project scope for performing the
reviews
was still being developed
by the licensee at the conclusion of
this inspection.
The inspector
noted that the scope
document, titled
"Review of Risk-Significant
UFSAR Systems."
dated July 16,
1997,
was
still in draft form.
The inspector discussed
the project scope with
Site Engineering
personnel
who indicated that the
UFSAR fire protection
systems
(which were described
as Priority 2 systems
in the July 11,
1997, letter) would be covered in a separate
scope
document.
The inspector
concluded that the specific details of the licensee's
plan
to perform
a graded
review of the
UFSAR systems
according to risk
significance
(as discussed
in the licensee's
letter to the
NRC dated
July ll, 1997) were being developed.
Conclusion
The inspector
concluded that the findings identified by the licensee
during the UFSAR/Procedure
Consistency
Review were documented.
processed,
and being tracked in accordance
with the licensee's
corrective action program and
NRC regulations.
The inspector also concluded that the details of the licensee's
plan to
perform
a graded
review. of the
UFSAR systems
according to risk
significance
(as discussed
in the licensee's
letter to the
NRC dated
July 11 '997) were being developed.
Condition
Re ort Review
40500
Ins ection
Sco
e
The inspector
reviewed selected
CRs assigned to Site Engineering to
assess
the adequacy
and timeliness of the corrective actions
proposed
by
Engineering.
Observations
and Findin s
The inspector
reviewed the
CRs listed below that were assigned
to Site
Engineering for resolution.
The inspector
noted that Engineering
had
not responded to some of these
CRs because
the 30 day response
due dates
had not been
reached at the time of this inspection.
CR 97-0494
CR 97-0592
CR 97-1399
CR 97-1422
CR 97-1429
CR 97-0524
CR 97-1211
CR 97-1414
CR 97-1428
CR 97-1460
29
During review of CR 97-1422.
the inspector
noted that this
CR was
written to document
a concern that plant drawings were not revised
when
the Unit 2 PC/M 008-295,
RPS NI Safety Channel
Replacement,
was revised
during implementation via Change
Request
Notice
(CRN) 008-295-5600.
Site Engineering
responded
to the
CR by issuing Drawing Change
Request
(OCR) 97-0127 to resolve the drawing configuration issue.
The
Engineering
response to this
CR also included corrective actions to
address
generic implications and actions to prevent recurrence.
These
actions
included
a
PMAI (PM97-08-053)
assigned
to Engineering to review
the
CRNs, drawings.
and manuals for both the Unit
1 and Unit 2 Nuclear
Instrumentation
(NI) modifications
(PC/M 009-195
and
PC/M 008-295,
respectively).
The inspector considered that the corrective actions for
this
CR were of sufficient depth
and scope to address
the issue
identified.
Howevers
during further review of this
CR. the inspector
noted that the due date for completion of the
PMAI was March 30,
1998.
The inspector discussed
this
CR with licensee
personnel
and questioned
the timeliness for completion of this PMAI, given the Unit 2 drawing
configuration issues identified with implementation of CRN 008-295-5600,
and the conf'iguration control issues identified during implementation of
the Unit
1
PC/M (discussed
in NRC Inspection
Report 50-335,389/96-22)
in
the Uni't
1 refueling outage in 1996.
Subsequent
to the discussions
with
the inspector,
the licensee
revised the completion due date for PMAI
PM97-08-053 from March 30,
1998 to November 30,
1997.
The inspector
informed the licensee that after the licensee
completes
the actions for
PMAI PM97-08-053.
the inspector will review the results during-a
subsequent'nspection.
Followup of this issue
was identified as
Inspector
Followup Item, IFI 50-335,389/97-10-02,
"Completion of
Corrective Actions for Condition Report 97-1422 Regarding Plant Drawing
Revisions."
During review of the other
CRs, the inspector
noted that Engineering
generally provided acceptable
responses
to address
the concerns
identified in the applicable
CR.
Conclusions
The inspector concluded that, for the condition reports
reviewed, Site
Engineering generally provided acceptable
responses
to address
the
concerns identified in the applicable condition reports.
However, the
initial due date for completing the corrective actions for
CR 97-1422
was not considered timely.
The completion date
was revised
by the
licensee
and
an IFI was identified to review the completed corrective
actions.
30
E8.3
Closed
URI 50-335 389/96-04-09
"Failure to
U date
Closed
URI 50-335 389/96-15-05
"Inade uate
Desi
n Basis
Documentation"
Closed
URI 50-335/96-16-04
"FSAR Descri tion of Installed
Instrumentation
on Unit
1
HSDP"
92903
The inspector
reviewed the NRC-identified
UFSAR inaccuracies
detailed in
Table
1 in accordance
with the Enforcement Policy as updated
by
Enforcement
Guidance
Hemorandum
"Enforcement
Issues
Associated with FSARs, Section
8. 1.3 Enforcement of FSAR Commitments."
With respect to the items in the table below, the inspector
reviewed the
licensee's
planned
UFSAR review effort to determine whether it was
reasonable
to conclude that the inaccuracies
would have
been identified
by the licensee's
review program.
The inspector
had the following
findings associated
with the items
on the table:
,With respect to item 1, the inspector
noted that,
although the
deficiency was identified to the licensee
in an inspection report
dated April 29,
1996, the inaccuracy
was not corrected
in a
amendment
submitted in January,
1997.
The licensee's
failure to
update the
UFSAR in this case
was found to be one example of a
violation of 10 CFR 50.71(e),
which requi red that the
UFSAR be
periodically updated to include, the latest material
developed
(VIO
50-335,389/97-10-03,
"NRC Identified UFSAR Inaccuracies" ).
With respect to items
2 through
16 the inspector concluded that
the inaccuracies
would not have
been identified by the licensee's
documented
UFSAR review effort and were, therefore,
subject to
enforcement action per the subject
EGN.
The inspector
found that
the subject
items represented
additional
examples of violations of
(VIO 50-335,389/97-10-03,
"NRC Identified UFSAR
Inaccuracies" ) .
With respect to item 17, the inspector
concluded that the item was
identified shortly after
a modification was affected that created
the subject inaccuracy.
The licensee
subsequently
incorporated
the change appropriately.
With respect to item 18, the inspector concluded that because
manual operation of these
components
was only allowed under test
conditions.
an inaccuracy in the
UFSAR did not exist.
With respect to item 19. the licensee
provided additional
information indicating the
UFSAR requirements
were met.
With respect to items 20,
21,
and 22, the inspector concluded that
the licensee's
program to review the
UFSAR was of sufficient scope
to identify these
examples.
In accordance
with the Enforcement
Policy, the fai lure to update the
UFSAR normally would be
categorized
as
a Severity Level
IV violation.
However, as-
'discussed
in Section VII.B.3 of the Enforcement Policy, the
NRC
may refrain from issuing
a Notice of Violation (Notice) for a
31
violation that involves
a past
problem,
such
as
an old
engineering,
design,
or installation deficiency,
provided that
certain criteria are met.
After review of this violation the
NRC
has concluded that while a violation did occur,
enforcement
discretion is warranted in this case.
Therefore,
to encourage
~licensee efforts to identify and correct
UFSAR discrepancies.
no
Notice is being issued in this case.
The specific bases for this
decision were (1) the licensee's
UFSAR review program,
as
described in paragraph
E8. l.b of'his report.
would likely have
identified the violation in light of the defined scope,
thoroughness
and schedule;
(2) there
had been
no prior notice
where the licensee
could have reasonably identified the violation
earlier;
(3) timely and appropriate corrective action was taken or
planned;
(4) timely and effective long-term corrective acti'ons
are
being implemented to review and identify any similar design
deficiencies:
(5) the design deficiency was considered
an old
design issue;
and,
(6) the yiolatIon was not willful. This issue
will be documented
as Non-Cited Violation (NCV)
50-335.389/97-10-06:
Failure to Update
With respect to item 23. the inspector
noted that the inaccuracy
appeared
to represent
an inaccuracy of material significance.
The
issue's
resolution
has
been tied to the resolution of a generic
concern for the operability of containment
leak detection
radiation monitors.
The issue will be tracked
as
a part of a
separate
URI, as discussed
below.
URI 50-335,389/96-04-09
is
closed.
URI 50-335/96-'6-04 is closed.
TABLE 1
Item
IR
96-004
96-006
96-006
96-006
96-006
96-006
96-006
96-006
Para
raph
X1
Xj.j
X1.1
Xj.j
X1.1
X1.1
X1.2
X1.2
Oiscrepanc
Unit 1 UFSAR Table 6.2-22
showed Unit 1
NaOH concentration
as 30-32 w/o.
TS 3.6.2.2.a correctl
specified the concentration
as 28.5-30.5 w/o.
Unit 1 UFSAR Table 7.3-2 incorrectly designated
NV-21-2 as relating to
the A ICW train rather than the 8
ICW train.
Unit 1
UFSAR Figure 9.2. la was not revised following modifications to
the intake coolin
water lube oil cooler
erformed under
PC/N 341-192.
Unit 1 UFSAR Table 7.4-1
~ Intake Cooling Water System.
was not revised
to delete lubricating water pressure
switches
FIS-21-3A,
3B,
3C. 30.
3E
and 3F (non-safet
) which had been
removed
b
modification.
Unit
1 UFSAR figures 7.4-9.
19'nd
11 were not revised to remove
E-15 lo ic. which was
s ared out.
Unit 2 UFSAR Table 7.3-2 incorrectly designated
NV-21-2 as relating to
the A ICW train rather than the 8
ICW train.
Unit
1 UFSAR Section 4.2.3.2.3(b)(1)
indicated
a minimum CEA drop time
of 2.5 seconds
plus 0.5 seconds totalling 3.0 seconds
which was
inconsistent with the 3. 1 seconds listed in TS 3. 1.3.4
and
UFSAR Table
4.2-1.
An audit of Unit 2 fire extinguishers identified three fire
extinguishers
~ at locations T-13. T-16.
and T-18 of the Turbine
Building.that were not the types of fire extinguishers
described in Unit
2 UFSAR Table 9.5A-BD.
32
Item
10
12
14
15
16
17
18
19
20
21
IR
96-008
96-008
96-015
96-015
96-015
96-015
97-006
97-006
96-004
96-006
96-006
96-022
96-16-04
IR 96-16
Para
ra h
Xj
X1
E3.1
E3.1
E3.1
E3.1
E8.8
E8.8
X1
X1.1
X1.1
X.1
02.3.6-
Discrepanc
Unit 2 UFSAR'able 7.5-3 for windows LA-9 and LB-9 incorrectly showed
actuation devices
as LS-17-552A/553A and LS-17-552B/553B.
The correct
actuation devices
were LS-59-009A/014A and LS-59-218/28B.
Unit 2 UFSAR Table 7.5-3 indicated that windows LA-4 and LB-4. "Lube
Water Supply Strainers'igh Differential Pressure,
were safety related.
The system
had been
downgraded
to non-safety related status
by PC/M 268-
292.
Unit 1
UFSAR Section 5.2.4.5.b,
1 incorrectly stated that the level
detector which measured
leakage
flow through the containment
sump weir
was non-seismic.
The detector
was in fact seismically qualified.
[This
section also stated that the recorder would have
a full scale
range of 0
to 11
.
The recorder.
FR-07-03.
in fact had
a ran
e of 0 to 12 gpm.7
Unit
1
UFSAR Section 5.2.4.5.b.2
stated that the Containment
Atmosphere
Radiation Monitoring System took isokinetic samples of air from the
containment cooling system ductwork.
Section
12.2..4. 1 stated that the
sample nozzles
were designed
such that the sampling velocity was the
same
as that in the ventilation system
so that preferential particulate
selection did not occur.
The licensee
indicated that the system flow
rate was greater
than the sample flow rate: therefore the system
was not
isokinetic.
Unit
1 UFSAR Table 5.2-11,
Reactor Coolant Leak Detection Sensitivity.
item (1). referenced
Figure 5.2-36 which did not exist.
[The Average
Rate of Change
and the Time for Scale to Move did not correspond for
entries
2 and 3 of Table 5.2-117.
[Human factors decrepancies
were
identified in that the instrument
ranges in Item (2) for the quench tank
water level.
Item (3) for Safety Injection Tank water level were
specified in units that did not correspond to units used in the plant
instrumentation.
Also, item (3) indicated that the Safety Injection
Tank pressure
instruments
ranged
from 0 to 250 psig when plant
instruments
indicated
from 0 to 300 psig.7
[The licensee identified
that the average
rate of change did not corres[pond to item 2 and 3 of
Table 5.2-jj.j
Unit
1
UFSAR Section 12.2.4. 1 stated that containment
atmosphere
sample
flow was regulated
and indicated by independent
mass flow meters.
While
the flow was indicated
by independent
mass flow meters. it was not
regulated.
The system flow was dependent
only on the capability of the.
Um
Unit 1 UFSAR Table 8.3-5 did not match the battery load profile shown in
calculation PSL-1-F-J-E-90-0015
and
UFSAR Fi ure 8.3-14.
UFSAR Table 9.2-5. Operating
Flow Rates
and Calculated
Heat Loads for
Auxiliary Equipment Cooled by Component Cooling Water.
was not changed
to reflect
a 1993 accident
reanal
sis of these
arameters.
Unit 2 UFSAR Table 7.3-4 listed
EDGs as starting
on a CSAS:
a feature
removed in the Unit 2 outa
e
revious to the findin ..
Unit 1 and
2 UFSAR descriptions of TCV 14-4A and
4B operation
assume
the
valves to be automatic.
et
rocedur es allow manual
o eration.
Unit 2 UFSAR Section 9.2. 1.2 stated that
an alarm would alert operators
if blowdown heat exchanger
ICW isolation valves were reopened
during
a
SIAS.
The desi
n of the alarm was unclear.
PC/M 009-195 deleted the rod drop turbine ru0back feature in Unit 1 NI
circuitry. but
UFSAR Section 7.7. 1.4 was not updated to reflect the
deletion
Unit 1 UFSAR Section 7.4. 1.8 listed one control switch for the
pressurizer auxiliary spray valve as installed
on the Hot Shutdown
Panel.
Two switches were actually installed.
33
Item
22
23
IR
96-16-04
IR 96-16
96-015
Para
raph
02.3.6
E3.1
Oiscre
anc
Unit
1
UFSAR Section 7.4. 1.8 Hot Shutdown Panel
contained
two source
range
and two wide range Nls.
The UFSAR failed to list the existence of
these in lists of installed indicators.
Unit 1
UFSAR Section 5.2.4.6 stated that the rate of chan'ge in
indication of the various leak detection
parameters
provides the
necessary
information to identify and estimate
leakage rates for a 1.0 gpm leak.
Table 5.2-11 lists the amount of time
for a
1 gpm leak to be detected
as evidenced
by a 10 percent deviation
in the normal readings.
The inspector
observed
the Containment
Radiation Particulate
and Gaseous
meters
channels
31 and 32.
respectively.
to deviate
by more than
10 percent normally. without a
1
gpm leak.
URI 50-335,389/96-15-05.
"Inadequate
Design Basis Documentation."
was opened
to track the resolution of questions
raised over both units'eak
detection
system containment radiation monitors
( Item 23 in Table, 1).
The issue
was
raised
when the inspectors
noted that no basis existed for containment
particulate
and gaseous air sampling high radiation alarm setpoints.
Since
the original inspection of this issue,
the inspectors
continued to review the.
subject systems'escriptions
in the
UFSAR and the licensee's
actions relative
to the systems.
In the course of the inspection,
the inspectors
noted that
the licensee
had no analytical
basis for the information in the
Consequently,
in October,
1996 'he licensee
began performing calculations to
demonstrate
the performance characteristics
of both units'etector s.
The
inspectors identified discrepancies
as described
in Table
2 below:
TABLE 2
Unit
Source
1
5.2.4.1
Discrepant
Information
"The leakage
detection
systems
are consistent
upwith
the recomnendations
in R.G. 1.45..."
Oiscussion
Referenced
Regulatory Guide stated that the sensitivity of each
leakage detection
system should be adequate
to detect
a leakage
rate of 1 gpm in
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
UFSAR information. described in items
below. indicated that the
UFSAR might be inaccurate
in this regard.
A Task Interface Agreement
(TIA) on the subject
was forwarded to
NRR for review.
The accuracy of the
UFSAR statement will be
judged,
in the context of the requirements of 10 CFR 50.9.
based
upon the response
to the TIA.
34
Unit
Source
1
5.2.4.5
2
5.2.5
5.2.5
Discrepant
Information
"The time that
a 1.0
gpm reactor
coolant
boundary leak takes
to cause
a
10
percent deviation in
the normal readings
of various
monitoring systems
is listed in Table
5.2-11."
The subject Table
indicated that:
The time for the
gaseous
monitor to
deviate
10 percent
was 15. 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The time for the
particulate monitors
to deviate
10
percent
was 18.1
hours
"The leakage
detectiqn
system is
capable of detecting
equivalent to 1.0
gpm or less within
one hour."
Table 5.2-14
indicated that
detection time for
both the particulate
and gaseous
monitors
to deviate
10
percent
from normal
readings
were
">62
minutes."
"The leakage
detection
system is
consistent with the
recommendations
of
Discussion
The inspectors
found that normal deviations experienced
in the unit
resulting from fluctuations in background level exceeded
10 percent
over several
minutes.
The accuracy of the
UFSAR in indicating that
a
10 percent deviation was both indicative of a
1 gpm leak and was.
in fact. identifiable given background variability. wi 11
be
evaluated in the context of 10 CFR 50.9.
Calculation PSL-1FSN-96-002.
Revision 0, which evaluated
gaseous
monitor sensitivity. indicated that
a
10 percent
increase
in.
detector output could. mathematically.
occur in 2. 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
assuming
a higher percentage
of failed fuel than currently existed in the
plant.
The calculation also stated that "It is unacceptable
to use
an alarm setpoint of two times background
as
an indication of a 1.0
gpm step increase
in RCS leakage since the time to an alarm would
be too long...[based
on realistic
RCS chemistry]."
Estimates of
times required to identify a
1 gpm leak based
on typical chemistry.
a 100 percent
increase
in indication.
and initial leak rate (prior
to a
1 gpm step increase)
varied from 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> to 1200 hours0.0139 days <br />0.333 hours <br />0.00198 weeks <br />4.566e-4 months <br />.
The
corresponding
times for a
10 percent
change
ranged
from 2. 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
to 19.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
The calculation results
(Section 6.2 of the
calculation) stated that. given current
RCS chemistry performance,
"...there would be insufficient activity available in the
containment
atmosphere for the containment
gaseous
monitor to
noticeably respond to a
1 gpm step increase
in RCS leakage."
Calculation PSL-1FSN-96-001.
Revision 0, which evaluated
particulate monitor sensitivity. indicated that
a 100 percent
increase in detector output could. mathematically.
occur in 70
minutes.
The calculation also stated that the use of the
10
percent deviation as indicative of 1 gpm
RCS leakage
was "difficult
given the current
o crating environment."
Calculation PSL-2FSN-96-003.
Revision 0. performed to evaluate
the
containment particulate monitor, concluded that. for typical
chemistry conditions.
105 minutes
were required for detector output
to double.
As in the case of Unit 1.
a
10 percent
increase
in
output was found. in the field. to be masked
by the natural
variability of background levels.
The accuracy of the subject
statement will be reviewed against
the requirements of 10 CFR 50.9.
The inspectors
noted that the referenced
Regulatory Guide stated
that the sensitivity of each
leakage detection
system should be
adequate
to detect
a leakage rate of
1 gpm in
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
information, described in items below. indicated that the
might be inaccurate
in this regard.
A TIA on the subject
was
forwarded to NRR for'eview.
The accuracy of the
UFSAR statement
will be judged, in the context of the requirements of 10 CFR 50.9.
based
upon the response
to the 'TIA.
35
In addition to the discrepancies
identified above,
the inspectors .identified
a
potential operability concern relating to the detectors.
The applicable
TS
stated:
3.4.6.1
The following RCS leakage detection
systems
shall
be
OPERABLE:
a.
The reactor cavity sump inlet flow monitoring system;
and
b.
One containment
atmosphere
radioactivity monitor
(gaseous
or
particulate).
APPLICABILITY:
HODES 1, 2, 3,
and 4.
The inspectors
noted that
an obvious operability issue would exist if the
licensee is found to be out of agreement
with the Regulatory Guide referred to
in the
However, the inspectors
also questioned
whether the monitors
could be cohsidered
operable if RCS activity levels were less than that
assumed
in the
UFSAR (.1 percent failed fuel).
Specifically:
~
Current chemistry results indicate that the units are performing
much better, relative to failed fuel, than
assumed
in the
Calculations referred to above indicate that the low level of RCS
activity presents
a challenge in the ability of the detectors
to
identify leakage.
~
Both units'articulate
monitor calculations credit Rubidium-88
(Rb-88) alone
as providing the activity detected.
Rb-88 has
a
half-life of approxiqately
18 minutes.
Given this short half-
life, the inspectors
questioned
the ability of the particulate
monitors to indicate leakage
when the unit is in Hodes
3 and 4.
For example,
a simple decay
law estimation indicated that Rb-88
activity levels
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after shutdown would reduced
by a factor
of approximately 8E-25.
When asked for a basis for Hode 3 and
4 operability, the licensee stated that
meeting the recommendations
of Regulatory Guide 1.45 as stated in the
and accepted
in two NRC Safety Evaluation Reports
was sufficient to establish
operability regardless
of plant mode.
Additionally. the licensee
stated that
surveillance
requirements
of the subject
TS were met (the monitors were
calibrated
and channel
checks
were performed
as required),
thus indicating
operability.
The inspectors
noted that the Bases for TS 4.03 stated,
in part,
"Under the provisions of this specification,
systems
and components
are
assumed to be
OPERABLE when Surveillance
Requirements
have
been satisfactorily
performed within the specified time interval.
However, nothin
in this
rovision is to be construed
as
im
1 in
that s stems
and
com onents
are
OPERABLE when the
are found or known to be ino erable althou
h still meetin
the Surveillance
Re ui rements
[emphasis
addedj."
The operability of the
subject monitors will be resolved
as
a part of the overall .issue.
'n
addition to the issues
above,
the inspectors
noted that, while the lack of
calculations
which supported
statements
made in the
UFSAR was identified to
the licensee in October of 1996 'he'icensee
had, at the close of the current
36
inspection period. failed to complete the calculations.
The calculations for
Unit
1 were completed
on October
24,
1996.
The calculation for the Unit 2
particulate monitor was completed
on February 4,
1997.
The licensee
stated
that the Unit 2 gaseous
monitor calculation
was not scheduled to be completed
unti l approximately January,
1998.
The inspectors
asked whether Safety
Evaluations
under
10 CFR 50.59 had been performed for the noted
discrepancies.
The licensee stated that none had been performed
and that they
would not be performed unti 1 the calculations
were complete.
The timeliness
of the licensee's
corrective actions
(completion of calculations
which support
UFSAR data
and operability and the performance of 10 CFR 50.59 Safety
Evaluations) will be reviewed for conformance to 10 CFR 50 Appendix B,
Criterion XVI, to determine whether the licensee's
actions
were of appropriate
promptness.
The issues
described
above will be tracked
as
one
04,
"RCS Leakage Detection Radiation Honitor Acceptability and Operability" ).
URI 50-335,389/96-15-05,
"Inadequate
Design Basis Documentation," will be
'losed, in deference to the new URI, which incorporates
design basis,
operability,
UFSAR accuracy,
and corrective action issues.
IV. Plant
Su
ort
F2
Status of Fire Protection Facilities
and Equipment
F2.1
Emer enc
DC Li ht
71750
a.
Ins ection Sco
e
The inspector
performed
a walkdown of the Emergency
DC lights within the
Radiological Controlled Area .(RCA) and observed portions of the monthly
emergency lighting preventive maintenance.
b.
Observations
and Findin s
e
On September
3. the inspector
performed
a partial walkdown of the
emergency lights, concentrating
mainly on both
RABs and the
EDG rooms.
The inspector
noted deficiency tags
on several
lights, however,
none of
the tags
noted were more than two months old.
The following day, the
inspector noticed
an electrician performing the August checks
per
Procedure
HP 0940066 'evision
20 'Portable
Haintenance
and Inspection,"
and Work Order 97017406.
The results
o'
the checks
observed
were satisf'actory.
The inspector
reviewed the last two months of inspections
performed
by
Electrical
Haintenance
(EH).
In July, four lighting units were found to
be inoperable in Unit 1 and replaced
(EL-1-36-001,
EL-1-36-004,
EL-1-47-
002,
and EL-1-7-006).
EH found nine emergency lights that needed
replacement
in Unit 2.
Planning
has
issued
a work order to replace
these l'ights when replacement
batteries
become available.
The inspector
noted that the generic work order to check the lights also allowed
replacing lights.
In fact
~ one step stated that ten spares
should
be on
hand.
When the inspector questioned
why there were no spares,
the
37
supervisor
and the planner stated that the had
an unusually high usage
recently
and all spares
had been
used.
Conclusions
The
PM program for the
DC emergency lighting system is adequate
to
detect
any problems with the lights within approximately
one month of
failure.
Several
lights were noted to need replacement,
work had been
planned
and replacement
batteries
were on order.
Fire
Pum
Halkdown
71750
Ins ection Sco
e
On August 26 'he inspector
performed
a detailed
walkdown of the fire
pump area.
The inspector
was looking for any detrimental conditions,
system lineups
and licensing document
conformance.
Observations
and Findin s
The inspector
had questions
about multiple items,
most of'hich the
licensee
proved acceptable
to the inspector.
However, the licensee
did
agree that several
items required
some type of corrective action.
The
inspector identified that all of the large Motor Operated
Valves
(MOV)
had equalizing valves installed around the
MOV.
Drawing 8770-G-084
SH.
1 did not show the equalizing lines
and valves.
Engineering verified
that the original design included one inch bypass
valve features,
and
therefore
no design
non-conformance
or operability concerns
existed.
CR
97-1670
documented
the drawing problem and requested
Engineering
and
Operations
Support to initiate a revision to the drawing.
The inspector also noticed that the large
MOVs were all locked open or
closed.
Drawing 8770-G-084
SH.
1 did not show any locking devices
present.
.Protection Services
recognized that this question
had been
asked in the past.
Inspection Report 95-21 noted t'hat V15500 was
shown
closed,
but the actual position was locked closed.
At that time, the
licensee initiated
STAR 960264 to investigate.
The response
indicated
that this was
an acceptable
practice.
Nuclear Engineering Standard.
STD-D-13.5.
Paragraph
6.12 stated that.
"Valves shall
be indicated
as
locked open or locked closed
when as
a Design Baseline,
locks are
necessary
for nuclear or personnel
safety.
Valves locked
administratively for equipment security and other similar purposes
are
not to be addressed
on Flow Diagrams."
The STAR further stated that the
licensee
locks the valves to meet Nuclear
Mutual Limited Insurance
Standards
and National Fire Protection Association Standards.
Since
no
design baseline exists to maintain these
valves in a locked position for
nuclear or personnel
safety,
the drawings .do not need to show the valves
as locked.
The inspector noted that both pumps
had discharge
pressure
switches
(PS-
15-20 for 1A and PS-15-21 for 1B) and pressure
gages
(PI-15-24A for 1A
and PI-15-24B for 1B) that had several
temporary valves associated
with
38
them.
The Protection Services
Supervisor
agreed that the valves were
necessary
to use the system
and that they would not remove them.
An
Engineering
review revealed that these
valves
met the definition of a
temporary valve per Operations
Ipstruction 0-0I-99-09, Revision 0.
"Labeling/Tagging of Plant Equipment,"
and they were properly labeled.
The inspector observed
what appeared
to be caulking around the base of
three
18 fire pump pipe supports.
Protection Services
stated that the
caulking was placed
around the edge to keep water from corroding the
support flange from underneath.
The inspector questioned if the
concrete
support
pad actually
made contact with the pipe support.
The
inspector
and the Protection Services
Manager probed behind the caulk
and found that the support flange on the discharge of the
18 pump was
not in contact with the concrete support.
The Protection Services
Supervisor wrote
a
CR (97-1695) to determine the operability of the
system.
Engineering
determined that the support
was not required
and
that the system
was operable.
The preliminary analysis
showed that all
pipe stresses
were within allowable limits and no operability concerns
existed.
Engineering
was planning to continue their investigation to
learn
how the piping was left in this condition.
The inspector
performed
an independent
investigation in an attempt to
determine the reason
for this nonconformance.
In October,
1996, the
licensee
replaced the
18 pump casing
due to excessive
corrosion
according to
PRO 69 5085.
Although the workers
remember
some
"difficulty"in pipe/pump flange alignment,
the Journeyman's
notes only
discussed
shimming the
pump to meet the discharge
The licensee
completed
a similar replacement
on the lA pump in February,
1997.
Again
the workers noted
some pipe fitup problems,
and again they documented
shimming the pump.
None of the maintenance
personnel
interviewed by the
inspector
remembered
noticing the gap between the support
and the
support
base.
The inspector
was unable to determine
when the support
was lifted, but it may have
been prior to the
pump casing
replacement.
The inspector
spoke with the painter who caulked
and painted the
supports.
He stated that his painting guidelines
di rected
him to caulk
any cracks prior to painting.
He further stated that he did not
consider that
a prob'lem might exist if the support did not rest
on the
base.
Once the painter painted the support,
the inspector concluded
that it was unlikely that
a casual
observer
would notice that the
supports
were caulked
and painted.
The inspector noticed that the pipe around the
18 recirculation check
valve V15121 was not painted
and was heavily corroded.
The licensee
confirmed that they had recently performed work on the check valve and
they never
repainted
the carbon steel
pipe.
The licensee corrected the
condition.
c.
Conclusions
The inspector
found the overall condition of the fire pumps to be
acceptable.
The system
was properly lined up for standby actuation.
39
One deficiency was identified due to a pipe support
found not supporting
the pipe.
Some other minor deficiencies
were noted
and corrected or
planned to be corrected.
With the exception of leaving
a repaired
check
valve exposed to the environment,
the inspector
found the material
condition generally good.
F5
Fire Protection Staff Training and Qualification
F5. 1
Closed
URI 50-335 389/97-06-13 "Failure to Man the Fire Bri ade
as
Re ui red
b
Procedure"
92904
This Unresolved
Item involved an Auxiliary Nuclear Plant Operator
(ANPO)
filling a position on the fire brigade
team which was specifically
designated
as requi ring a Senior Nuclear Plant Operator.
The procedure
was not changed prior to allowing the
ANPO to assume
the SNPO's fire
brigade duties.
Further investigation determined that the
ANPO did meet
the intent of the procedure;
he had been trained in Safe'Shutdown
System
fire fighting and was
a qualified brigade
member.
Operations
supervision did not question the one specific requirement
that the
~
position was to be filled by a
SNPO.
Procedure QI-5-PSL-l, Revision 2,
"Preparation,
Revision,
Review/Approval of Procedures."
Section 4.7. 1,
required verbatim compliance with procedures.
This fai lure to follow
the procedure constitutes
a violation of minor significance
and is being
treated
as
a Non-Cited Violation,
NCV 50-335.389/97-10-05.
"Failure to
Man the Fire Brigade as Required
by Procedure."
consistent with Section
IV of the
This item was inadvertently reported
in the items opened
and closed section of Inspection Report 97-06 as
a
NCV. It was unresolved at the end of that report period.
This
Unresolved
Item is now closed.
V. Mana ement Meetin s and Other
Areas
Xl
Exit Meeting Summary
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on September
12,
1997.
An interim exit meeting
was held on August 22,
1997, to discuss
the
findings of Region based
inspection.
The licensee
acknowledged
the
findings presented.
The inspectors
asked the licensee
whether any materials
examined during
the inspection
should
be considered proprietary.
No proprietary
information was identified.
PARTIAL LIST OF
PERSONS
CONTACTED
Licensee
H. Allen. Training Manager
C. Bible, Site Engineering
Manager
W. Bladow, Site Quality Manager
G. Boissy, Materials
Manager
H. Buchanan,. Health Physics Supervisor
D. Fadden,
Services
Manager
R. Heroux,
Business
Manager
H. Johnson,
Operations
Manager
J.
Marchese,
Maintenance
Manager
C. Marple. Operations
Supervisor
J. Scarola,
St. Lucie Plant General
Manager
A. Stall, St. Lucie Plant Vice President
E.
Weinkam, Licensing Manager
W. White, Security Supervisor
Other licensee
employees
contacted
included office. operations,
engineering,
maintenance.
chemistry/radiation,
and corporate
personnel.
4
INSPECTION
PROCEDURES
USED
IP 37550:
IP 37551:
IP 40500:
IP 42700:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92901:
IP 92903:
IP 92904:
IP 93702:
Engineering
Onsite Engineering
Effectiveness of Licensee Controls in Identifying, Resolving,
and
Preventing
Problems
Plant Procedures
Surveillance
Observations
Maintenance
Observations
Plant Operations
Plant Support Activities
Followup - Plant Operations
Followup - Engineering
Followup - Plant Support
Prompt Onsite Response
to Events at Operating
Power Reactors
ITEMS OPENED,
CLOSED.
AND DISCUSSED
~0ened
50-335,389/97-10-01
"Failure to Update
a Procedure"
(Section
03. 1)
50-335,389/97-10-02
50-335,389/97-10-03
50-335,389/97-10-04
50-335,389/97-10-05
50-335,389/97-10-06
IFI
"Completion of Corrective Actions for Condition
Report 97-1422" (Section E8.2)
"NRC Identified UFSAR Inaccuracies"
(Section
E8.3)
"RCS Leakage Detection Radiation Monitor
Acceptability and Operability" (Section 08.3)
"Failure to Man the Fire Brigade as Required
by
Procedure"
(Section
F5. 1)
"Failure to Update
UFSAR" (Section
E8.3)
Closed
50-389/96-001-00
50-335/96-003-00
50-335/96-004-00
50-335.389/96-11-04
50-335,389/96-16-02
50-335.389/96-04-09
50-335,389/96-15-05
50-335/96-16-04
50-335,389/97-06-13
Discussed
50-335/96-04-01.
41
LER
"Manual Reactor Trip Due to High Main Generator
Cold Gas Temperature"
(Section 08. 1)
LER
"Containment Particulate
and Gaseous
Monitor Out
of Service Resulting in a Condition Prohibited
by Technical Specifications
Due to Personnel
Error" (Section 08.2)
LER
"Inadvertent
Manual Start of the
1A Emergency
Diesel Generator
Due to Personnel
Error"
(Section 08.3)
"Preconditioning of Valves Prior to
Surveillance"
(Section 08.4)
"Failure to Control Operation
Keys" (Section
08.5)
"Failure to Update
UFSAR" (Section E8.3)
"Inadequate
Design Basis Documentation"
(Section
08.3)
"FSAR Description of Installed Instrumentation
on Unit 1 HSDP" (Section
E8.3)
"Failure to Man the Fire Brigade
as Required
by
Procedure"
(Section
F5. 1)
"Failure to Follow Procedures
Lead to Unit 1
Containment
PIG Inoperability" (Section 08.2)
50-335,389/96-15-05
"Inadequate
Design Basis Documentation"
(Section
08.2)
50-335,389/97-04-02
"Routine Use of Heavy Operator
Overtime"
(Section 03.1)
LIST OF ACRONYMS USED
ADM
ANPO
ANPS
ATM
Administrati ve Procedure
Auxil iary Feedwater
Auxi'liary Nuclear Plant [unlicensedj
Operator
Assistant
Nuclear Plant Supervisor
Administrati ve Procedure
Annunciator Response
Procedures
Attention
Control
Element Assembly
42
CFR
CR
CRN
CWD
DWG
EMP
ENG
ERT
FCP
FR
FRG
GDT
HSDP
IBC
ICW
IFI
I.P
IR
ISEG
IX
JPN
LER
M8TE
NaOH
NI
NPF
NPWO
NRC
NWE
Code of Federal
Regulations
Condition Report
Change
Request
Notice
Containment
Spray Actuation System
Chemical
8 Volume Control System
Control Wiring Diagram
Direct Current
Drawing Change
Request
Demonstration
Power Reactor
(A type of op
Drawing
Enforcement Action
Enforcement
Guidance
Memorandum
Electrical Maintenance
~ Electrical Maintenance
Procedure
Engineering
Emergency Operating
Procedure
Engineering
Package
Event Response
Team
UFSAR Change
Package
The Florida Power
8 Light Company
Federal
Regulation
Facility Review Group
Final Safety Analysis Report
Gas
Decay Tanks
Health Physics
High Pressure
Safety Injection (system)
Hot Shutdown
Panel
Instrumentation
and Control
Intake Cooling Water
[NRC] Inspector
Followup Item
Inspection
Procedure
[NRC] Inspection
Report
Independent
Safety Engineering
Group
Ion Exchanger
(Juno
Beach)
Nuclear Engineering
Licensee
Event Report
Low Pressure
Safety Injection (system)
Level Switch
Measuring
5 Test Equipment
Motor Operated
Valve
Sodium Hydroxide
Non Cited Violation (of NRC requirements)
Nuclear Instrument
Notice of Violation (of NRC requirements)
Nuclear Production Facility (a type of op
Nuclear Plant Operator
Nuclear Plant Supervisor
Nuclear Plant
Work Order
Nuclear Regulatory
Commission
Nuclear Regulatory
(NRC Headquarters
Publ
Nuclear Watch Engineer
crating license)
crating license)
ication)
ONOP
OP
PC/M
PIG
PMAI
ppm
Pslg
PSL
PWO
QI
Rb-88
RDT
RE
RII
SNPO
St.
TCW
TEDB
T
TQAR
TRA
TS
umho/cm
V
43
Off Normal Operating
Procedure
Operating
Procedure
Public Address
Plant Change/Modification
Procedure
Change
Request
NRC Public Document
Room
Particulate-Iodine-Noble
Gas Monitor
Preventive
Maintenance
Plant Management Action Item
Power Operated Relief Valve
Parts
per Million
Pounds
per square
inch (gage)
Plant St. Lucie
Plant Work Order
Quality Assurance
Quality Control
Quality Instruction
Quality Surveillance Letter
Reactor Auxiliary Building
Rubidium-88
Radiologically Controlled Area
Reactor
Coolant
Pump
Reactor
Coolant System
Reactor Drain Tank
Reactor
Engineering
Region II - Atlanta, Georgia
(NRC)
Reactor Protection
System
Steam Generator
Replacement
Project
Steam Generating
Team.
Ltd
Safety Injection Actuation System
Senior Nuclear Plant [unlicensed] Operator
Saint
South Service Building
St. Lucie Action Request
Temporary
Change
Temperature
Control Valve
Turbine Cooling Water
Total Equipment
Data
Base
RCS Hot Leg Temperature
Task Interface Agreement
Topical Quality Assurance
Report
Technical
Review and Assessment
Technical Specification(s)
Temporary System Alteration
Technical
Support Center
Updated Final Safety Analysis Report
Micromhos per centimeter
[NRC] Unresolved
Item
United States
Nuclear Regulatory
Commission
Volt(s)
Volume Control Tank
VOTES
Violation (of NRC requirements)
Valve Operation Test Evaluation System
Work Order
rg