ML17349A723
| ML17349A723 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 02/17/1993 |
| From: | Butcher R, Landis K, Schenbli G, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17349A721 | List: |
| References | |
| 50-250-93-01, 50-250-93-1, 50-251-93-01, 50-251-93-1, NUDOCS 9303020265 | |
| Download: ML17349A723 (35) | |
See also: IR 05000250/1993001
Text
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UNITEDSTATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-250/93-01
and 50-251/93-01
Licensee:
Florida Power and Light Company
9250 West Flagler Street
Miami,
FL
33102
Docket Nos.:
50-250
and 50-251
License Nos.:
and
Facility Name:
Turkey Point Units 3 and
4
Inspection
Conducted:
January
-29,
1993
Inspectors:
.
C. Butche
, Senior Resident
Inspector
M (7
Da
Si
ned
(7
0
. A. Schnebl
, Resi
nt Inspector
Dat
Si
ned
C
~
~
. Trocine, Resident
Inspector
Date Si
ned
Accompanying Personnel:
R. Freudenberger,
Resident
Inspector,
Crystal River
J. J.
Lenahan,
Reactor Inspector,
Engineering
Branch,
Division of Reactor Safety
R.
P. Schin, Project Engineer,
Division of Reactor
Projects,
RII
Approved by:
K. D. Landis, Chief
Reactor ProjectsSection
2B
Division of Reactor Projects
/7 N
Date Signed
SUMMARY
Scope:
This routine resident
inspector inspection
involved direct inspection at the
site in the areas of monthly surveillance observations,
monthly maintenance
observations,
operational
safety,
and plant events.
Backshift inspections
were performed
on January
6, 7,
and
18,
1993.
Results:
In the operations
area,
several
major plant status
changes
were accomplished
in a professional
and controlled manner,
including two Unit 3 and
one Unit 4
shutdowns
and their subsequent
startups.
Two areas of concern
were identified
l
involving the inadvertent
opening of a power operated relief valve
(paragraph
'F303020265
9302f7
ADOCK 05000250
6
0
e
2
8.c)
and the iso1ation of the containment
spray
pumps in the wrong mode of
operation
(paragraph
S.d) which indicates
a lack of attention to detail.
In the maintenance
area,
several
equipment failures required plant shutdowns
for repairs,
inc1uding rep1acement
of 38 moisture separator
reheater
drain
line, repair of an unisolable leak on Unit 3 pressurizer
spray line,
and the
repacking of 4A steam generator
feed regulating valve.
Maintenance for the
three short notice outages
was conducted
in a safe, efficient manner,
and the
units were returned to service within the scheduled
time.
In the safety assessment/quality
verification area,
an issue
was identified
concerning
a failure to implement measures
to assure
vendor supplied materials
conform to procurement
documents
(paragraph 8.e).
In the engineering
and technical
support
area,
a weakness
was identified
concerning minor inaccuracies
on drawings which is
a repetitive problem
(paragraph 7.c).
Within the scope of this inspection,
the inspectors
determined that the
licensee
continued to demonstrate
satisfactory
performance to ensure
safe
plant operations.
One violation was identified.
In addition, the licensee,
through self assessment,
took prompt action to correct the two
non-cited violations:
Non-Cited Violation 50-250,251/93-01-01,
failure to maintain pressurizer
pressure
below 375 psig resulting in the inadvertent
opening of a power
operated relief valve (paragraph 8.c).
Violation 50-250,251/93-01-02,
failure to follow procedures
in the area of
conduct of operations resulting in the isolation of containment
spray prior to
system temperature
going below 200'
(paragraph 8.d).
Non-Cited Violation 50-250,251/93-01-03,
failure to implement measures
to
assure
that the wet annular burnable absorber
assemblies
conformed to
procurement
documents
(paragraph
S.e).
i
REPORT DETAILS
Persons
Contacted
Licensee
Employees
T. V.
H. J.
R. J.
R. J.
R.
D.
E.
F.
R.
G.
P.
C.
D.
E.
H. H.
V. A.
J.
E.
J.
E.
R. S.
J.
D.
L.
W.
H. 0.
T.
F.
D.
R.
R.
E.
R.
N.
F.
R.
R. J.
H.
B.
E. J.
Abbatiello, Site guality Hanager
Bowskill, Reactor
Engineering Supervisor
Earl, quality Assurance
Supervisor
Gianfrencesco,
Support Services
Supervisor
Gill, Chief Civil Engineer
Hayes,
Instrumentation
and Controls Haintenance
Heisterman,
Hechanical
Haintenance
Supervisor
Higgins,
Outage
Hanager
Jernigan,
Technical
Hanager
Johnson,
Operations
Supervisor
Kaminskas,
Operations
Hanager
Kirkpatrick, Fire Protection/Safety
Supervisor
Knorr, Regulatory
Compliance Analyst
Kundalkar,
Engineering
Hanager
Lindsay, Health Physics Supervisor
Pearce,
Plant General
Hanager
Pearce,
Electrical Haintenance
Supervisor
Plunkett, Site Vice President
Powell, Services
Hanager'ose,
Nuclear Haterials
Hanager
Steinke,
Chemistry Supervisor
Timmons, Security Supervisor
Tomonto,
Licensing Engineer
Wayland,
Haintenance
Hanager
Weinkam,
Licensing Hanager
Supervisor
Other licensee
employees
contacted
included construction
craftsman,
engineers,
technicians,
operators,
mechanics,
and electricians.
Bechtel
Employee
o G.
Thomas,
Senior Structural
Engineer
NRC Resident
Inspectors
- R.
C. Butcher,
Senior Resident
Inspector
- G. A. Schnebli,
Resident
Inspector
- L. Trocine,
Resident
Inspector
Other
NRC Personnel
S. A. Varga, Director, Division of Reactor Projects
- I/II, NRR
H.
N. Berkow, Director, Project Directorate II-2, NRR
o L. Raghavan,
Project Hanager,
Project Directorate II-2, NRR
o H. Ashar,
Senior Structural
Engineer, Civil Engineering
& Geoscience
Branch,
o G. Bagchi, Chief, Civil Engineering
& Geoscience
Branch,
l
]
2.
o Y. Kim, Senior Structural
Engineer, Civil Engineering
8 Geoscience
Branch,
o J.
Lenahan,
Reactor
Inspector,
Engineering
Branch,
Region II
R. Freudenberger,
Resident
Inspector,
Crystal River
R.. Schin,
Project Engineer,
Region II
Attended exit interview on January
29,
1993
o
Attended January ll, 1993, meeting at
NRC headquarters
regarding
containment
tendon surveillance
inspections.
(Refer to paragraph
9 for
additional information.)
Note:
An alphabetical
tabulation of acronyms
used in this report is
listed in the last paragraph
in this report.
Other
NRC Inspections
Performed During This Period
Re ort No.
Dates
Area Ins ected
3.
50-250,251/93-05
January
25-29,
1993
Emergency
Preparedness
Plant Status
Unit 3
At the beginning of this reporting period, Unit 3 was operating at
100%
power and
had
been
on line since
December
6,
1992.
The following
evolutions occurred
on this unit during this assessment
period:
On January
8,
1993, at ll:15 a.m.,
a load reduction to support
flux mapping
was
commenced.
At 12:20 p.m., the licensee
began
inducing Xenon oscillations with reactor
power at 85%,
and the
load reduction
was continued at 6:00 p.m., in order to facilitate
the repair of a steam leak on
a 3B HSR drain line.
The turbine
was taken off line,
and the unit entered
Mode
2 at 7:40 p.m.
The
turbine was placed
back on line,
and Unit 3 entered
Mode
1 again
at 2:30 a.m.
on January
10,
1993.
With reactor
power at
approximately
30%,
power ascension
was ceased
at 3:30 a.m.
due to
secondary
system high cation conductivity.
Power ascension
was
re-commenced
at 12:45 p.m.,
and
100% reactor
power was achieved at
8:20 p.m.
On January
15,
1993, at 2:32 p.m.,
an Unusual
Event was declared
because
of the identification of RCS pressure
boundary leakage.
(Refer to paragraph
8.b for additional information.)
A unit
shutdown
was
commenced
at 2:35 p.m., the turbine was manually
tripped at 5:49 p.m.,
and
Mode 3 was entered
at 5:55 p.m.
Unit 3
entered
Mode
4 at 4:40 a.m.
on January
16,
1993.
At 6: 15 p.m.,
Mode
5 was entered,
and the Unusual
Event was downgraded to a non-
emergency classification.
On January
18,
1993,
at 4:55 a.m., Unit 3 entered
Mode 4.
Hode
3
was entered
at 5:05 p.m.
on January
19,
1993.
Mode
2 was entered
at 2:02 p.m.
on January
20,
1993;
and criticality was achieved at
2:28 p.m.
Unit 3 was placed
on line and
Mode
1 was entered
at
7:25 p.m.
on January
20,
1993,
and reactor
power reached
100% at
4:25 a.m.
on January
21,
1993.
Unit 4
At the beginning of this reporting period, Unit 4 was operating at
100%
power
and
had
been
on line since October 27,
1992.
The following
evolutions occurred
on this unit during this assessment
period:
On January
6,
1993, at 7:20 p.m.,
a load reduction to approximate-
ly 15% reactor
power was
commenced
in order to facilitate the
repacking of the
feedwater regulation valve
(FCV-4-478).
The unit was stabilized at approximately
50
MWe at
9:45 p.m.
The turbine was tripped
and
Node
2 was entered
at 3:45
a.m.
on January
7,
1993.
Following the repair,
the turbine
was
placed
back
on line and
Mode
1 was re-entered
at 11:50 a.m.
At
12:40 p.m.,
power ascension
was ceased
and reactor
power
was
maintained at approximately
45% because
axial flux was outside of
the target
band for 73 minutes.
Power ascension
was
re-commenced
at 12:30 p.m.
on January
8,
1993,
and
100% reactor
power was
attained at 6:30 p.m.
On January
26,
1993, at 7:50 a.m.,
a power reduction
was
commenced
as
a precautionary
measure
due to a ground
on the
4A condensate
pump.
(Refer to paragraph 8.f for additional information.)
Reactor
power was stabilized at
70% at 9:40 a.m.,
power ascension
was
commenced
at 1200 p.m.,
and
100% reactor
power was attained at
5:30 p.m.
Onsite Followup and In-Office Review of Written Reports of Nonroutine
Events
and
10 CFR Part 21 Reviews
(90712/90713/92700)
The Licensee
Event Reports
and/or
10 CFR Part 21 Reports
discussed
below
were reviewed.
The inspectors verified that reporting requirements
had
been met, root cause
analysis
was performed, corrective actions
appeared
appropriate,
and generic applicability had
been considered.
Additional-
ly, the inspectors verified the licensee
had reviewed
each event,
corrective actions
were implemented,
responsibility for corrective
actions not fully completed
was clearly assigned,
safety questions
had
been evaluated
and resolved,
and violations of regulations
or TS
conditions
had
been identified.
When applicable,
the criteria of 10 CFR Part 2, Appendix C, were applied.
(Closed)
LER 50-250/92-12,
Containment
Personnel
Airlock Vent Inadver-
tently Open to Atmosphere
During Core Alterations.
This event
was previously discussed
in IR No. 50-250,251/92-28
and was
identified as
NCV 50-250,251/92-28-01.
This
LER is closed.
0,
Surveillance
Observations
(61726)
The inspectors
observed
TS required surveillance testing
and verified
that the test procedures
conformed to the requirements
of the TSs;
testing
was performed in accordance
with adequate
procedures;
test
instrumentation
was calibrated; limiting conditions for operation
were
met; test results
met acceptance
criteria requirements
and were reviewed
by personnel
other than the individual directing the test; deficiencies
were identified,
as appropriate,
and were properly reviewed
and resolved
by management
personnel;
and system restoration
was adequate.
For
completed tests,
the inspectors verified testing frequencies
were met
and tests
were performed
by qualified individuals.
The inspectors
witnessed/reviewed
portions of the following test
activities:
3-OSP-049. 1, Reactor Protection
System Logic Test, for both trains
A and
B,
and
0-OSP-025.
1 Control
Room Emergency Ventilation System Operability
Test.
The inspectors
determined that the above testing activities were
performed in a satisfactory
manner
and met the requirements
of the TSs.
Violations or deviations
were not identified.
Maintenance
Observations
(62703)
Station maintenance activities of safety-related
systems
and components
were observed
and reviewed to ascertain
they were conducted
in
accordance
with approved
procedures,
regulatory guides,
industry codes
and standards,
and in conformance with the TSs.
The following items were considered
during this review,
as appropriate:
LCOs were met while components
or
systems
were removed from service;
approvals
were obtained prior to initiating work; activities were
accomplished
using approved
procedures
and were inspected
as applicable;
procedures
used
were adequate
to control the activity; troubleshooting
activities were controlled
and repair records accurately reflected the
maintenance
performed; functional testing and/or calibrations
were
performed prior to returning components
or systems to service;
gC
records
were maintained; activities were accomplished
by qualified
personnel;
parts
and materials
used were properly certified;
radiological controls were properly implemented;
gC hold points were
established
and observed
where required; fire prevention controls were
implemented;
outside contractor force activities were controlled in
accordance
with the approved
gA program;
and housekeeping
was actively
pursued.
The inspectors
witnessed/reviewed
portions of the following maintenance
activities in progress:
replacement
of reactor trip breakers
3A and
3B,
repacking of the
4A main feedwater regulating valve (FCV-4-478),
troubleshooting of water intrusion in thermo-lagged
terminal
box
TB-3029,
replacement
of 3B MSR drain line due to steam leak caused
by
erosion,
and
repair of pressure
boundary leakage
from a cracked weld on
a
capped fitting off the pressurizer
spray line.
(Refer to
paragraph
8.b for additional information).
At 5:20 a.m.
on January
25,
1993, the diesel
driven fire pump
and raw
water tank II were taken out of service for repair
and recoating,
respectively.
TS 3.7.8. 1 requires
the fire water supply
and
distribution system to be operable with at least
two fire suppression
pumps
(one electric driven
and
one diesel
driven) with their discharges
aligned to the fire suppression
with two separate
water supplies
each with a minimum contained
volume of 300,000 gallons,
and with an
operable flow path taking suction from raw water tanks
I and II.
With
one
pump and/or
one water supply inoperable,
action statement
a. of TS 3.7.8. 1 requires
the restoration of the inoperable
equipment to operable
status within 7 days or the provision of an alternate
backup
pump or
water supply.
Alternate
pumps
and
an alternate
water supply were
provided prior to the removal of the diesel
driven fire pump
and raw
water tank II from service via the installation of a spool
piece
between
fire hydrant
13 and the screen wash/fire system crosstie line in
accordance
with O-ONOP-016.7,
Screen
Wash
Emergency
Makeup to the Fire
Protection
System at 1: 15 a.m.
on January
25,
1993.
For those maintenance
activities observed,
the inspectors
determined
that the activities were conducted
in a satisfactory
manner
and that the
work was properly performed in accordance
with approved
maintenance
work
orders.
Violations or deviations
were not identified.
7.
Operational
Safety Verification (71707)
The inspectors
observed
control
room operations,
reviewed applicable
logs,
conducted
discussions
with control
room operators,
observed shift
turnovers,
and monitored instrumentation.
The inspectors verified
proper valve/switch alignment of selected
emergency
systems,
verified
maintenance
work orders
had
been submitted
as required,
and verified
followup and prioritization of work was accomplished.
The inspectors
reviewed tagout records, verified compliance with TS LCOs,
and verified
the return to service of affected
components.
By observation
and direct interviews, verification was
made that the
physical security plan was being implemented.
The implementation of
6
radiological controls
and plant housekeeping/cleanliness
conditions were
also observed.
Tours of the intake structure
and diesel, auxiliary, control,
and
turbine buildings were conducted to observe plant equipment conditions
including potential fire hazards,
fluid leaks,
and excessive
vibrations.
The inspectors
walked down accessible
portions of the following
safety-related
systems/structures
to verify proper valve/switch
alignment:
4
A and
B emergency diesel
generators,
control
room vertical panels
and safeguards
racks,
intake cooling water structure,
4160-volt buses
and 480-volt load
and motor control centers,
Unit 3 and
4 feedwater platforms,
Unit 3 and
4 condensate
storage
tank area,
area,
Unit 3 and
4 main steam platforms,
and
auxiliary building.
a ~
The inspectors
reviewed the
FSAR and TSs in regard to the
requirements
for the
IAS,
and the nitrogen backup
system
for the
PORVs in conjunction with a postulated fire per
The
PORVs were not originally designed
as
safety-related
components
(other than for RCS pressure
boundary
isolation)
as they do not perform any active safety function and
credit for their operation to mitigate design
basis
events
was not
considered
in the plant accident
analyses.
Overpressure
protection for the
RCS is provided
by the pressurizer
safety
valves.
Since the
PORVs, which are air operated
valves,
were not
originally classified
as safety-related
components,
other than fo}
RCS pressure
boundary isolation, their motive power source
was
instrument air which is
a non-safety
system.
A review of Plant
TSs supports this position
as there are
no
LCOs specified for the
PORVs during Nodes
1, 2,
or 3.
TS 3/4.4.4, Relief Valves, applies
to each remotely operated
PORV block valve which is required to be
operable to isolate
an inadvertently stuck open or leaking
PORV in
Nodes
1, 2,
and
3.
The basis for TS 3/4.4.4 states that the
opening of the
PORVs fulfills no safety-related
function and
no
credit is taken for their operation in the safety analysis for
Nodes
1, 2, or 3.
Each
PORV has
a remotely operated
block valve
to provide
a positive shutoff capability should
a relief valve
become inoperable.
I
Subsequently,
increased
emphasis
was placed
on the
PORVs to
provide overpressure
protection for the
RCS during periods of low
RCS temperature/pressure
operation.
This functional requirement
for the
PORVs is referred to as
OHS.
The operational
requirement
for the
PORVs is reflected in Technical Specification Limiting
Condition for Operation 3.4.9.3,
Overpressure
Mitigation System
(OHS), which is required to be operable
in Hodes 4, 5,
and
6 when
RCS average
temperatures
are below 275'F.
This requirement
assures
that the
RCS will be protected
from pressure
which could exceed
the limits of Appendix
G to
10 CFR Part 50. If
the
PORVs are not available in this mode of operation,
the TSs
require that the
be depressurized
and
a vent path of at least
2.20 square
inches
be established.
As stated in the basis for TS 3.4.9.3,
in the
OHS mode of operation,
the PORVs'unction is to
provide relieving capability to protect the
RCS from the following
overpressurization
events:
The start of a HHSI pump and its injection into a water
solid
RCS; or
The start of an idle reactor coolant
pump with the secondary
water of the steam generators x 50'F above the
RCS leg
temperature.
In summary,
the Turkey Point TSs require that the
be
operational
only in Modes 4, 5,
and
6 with the reactor
head
on and
the
RCS not vented.
Operation of the
PORVs in this mode of plant
operation is dependent
on the availability of either the original
non-safety related
IAS or the dedicated
backup safety related
nitrogen bottle system.
To assure that the
PORVs are available in
this mode of operation,
TS 4.4.9.3. l.d. requires that the backup
air supply system
be verified as operable
at least
once every
24
hours.
Procedure
3/4-GOP-305,
Hot Standby to Cold Shutdown,
step
5. 13
requires that prior to
RCS cooldown to less
than 276'F
and when
pressurizer
pressure
is in the range of 325 to 375 psig,
then
perform the nitrogen
backup
system leak test
and loop operability
tests
using 3/4-0SP-041.4,
Overpressure
Mitigating System Nitrogen
Backup
Leak and Function Test,
and establish
and verify OMS
operation in accordance
with 3/4-0P-041.4,
Overpressure
Mitigating
System.
Operating
Procedure
0204.2,
Periodic Tests,
Checks,
and
Operating Evolutions,
step 8.2.3.4(l)
has the
RCO check the
status
on peak
and mid shifts when the
RCS temperature
is less
than 275'F.
With respect to
10 CFR Part 50, Appendix
R requirements,
the
are identified on the essential
equipment l~ist as defined in the
Drawing 5610-H-723,
Appendix
R Essential
Equipment List, lists the
(PCV-*-455C and PCV-*-456).
The
purpose for identifying the
PORVs on the essential
equipment list
is two-fold.
First, the
PORVs are protected to ensure that
an
Appendix
R fire does not cause their spurious
opening which could
cause
primary system depressurization.
Secondly,
the
PORVs are
identified to reflect their requirement for providing
protection.
In accordance
with 10 CFR Part 50, Appendix R,
Section III.L.6, the shutdown
systems installed to meet these
postfire shutdown requirements
need not be designed
to meet
seismic Category
I criteria, single failure criteria or other
design basis
accident criteria.
This requirement is reflected in
the
FSAR.
The
FSAR, Appendix 9.6A presents
the fire
protection
program
as required
by 10 CFR Part 50, Appendix R.
Some of the listed assumptions
and design basis
presented
in the
fire protection
program are
as follows:
During hot standby conditions
and initial cooldown
conditions,
decay heat
removal is accomplished
by
atmospheric
dump valve operations
and
AFW turbine exhaust.
During subsequent
cooldown
and cold shutdown conditions,
decay heat
removal is accomplished
by the
RHR system,
the
CCW system,
and the
ICW system.
No design basis
accident or natural
phenomenon
shall
be
postulated
concurrently.
The single failure criterion shall not apply to the design
of the alternate
shutdown
systems
and components,
except to
account for adverse
equipment actions
caused
by the
postulated fire.
The
IAS provides filtered compressed
air to pneumatic
instruments,
controls,
and air operated
valves.
Based
on the data noted
above,
the
IAS is assumed
to be available
during the Appendix
R postulated fire and the nitrogen
backup
system is not required.
The IAS,
and the nitrogen backup
system
meet present
TS and
10 CFR Part 50, Appendix
R design
requirements.
By GL 90-06 dated
June
25,
1990, the
NRC advised all
PWR owners of
the staff positions relating to
PORV and
PORV block valve
reliability and additional
low-temperature
overpressure
protection
for light water reactors.
The
GL represented
the technical
resolution of two generic
issues
and included plant backfits which
were cost-justified safety
enhancements.
FPL submitted
a response
to
GL 90-06 dated
November 25,
1992,
proposing license
amendments
to resolve the generic
issues
involved.
The
NRC has not completed
review of FPL's submittal at this time.
Based
on the resolution
of the generic
issues of GL 90-06, the existing
TS and/or
requirements
are subject to change.
The licensee routinely performs
gA/gC audits/surveillances
of
activities required
under its gA program
and
as requested
by
management.
To assess
the effectiveness
of these
licensee
audits,
the inspectors
examined the status,
scope,
and findings of the
following audit reports:
Number of
Audit Number
~Findin
s
T
e of Audit
QAO-PTN-93-038
Design Control
QAO-PTN-93-045
QA Records
QAO-PTN-93-046
Procedure
Control
No additional
NRC followup action is required.
During inspection of the fire water supply system
on January
11,
1993, the inspector
noted that valve 10-1188,
raw water booster
pump
B recirculation line isolation valve,
had about
a one-foot
length of open threaded five-inch diameter pipe extending
from it.
The inspector could look into the open pipe
and
see the disc of
the manual
gate valve.
A similar valve about two feet
above
(10-1187,
raw water booster
pump
C recirculation line isolation
valve)
had about
a one-foot length of five-inch diameter pipe
extending
from it with a bolted blank flange
on the end.
Both
valves
connected
to raw water storage
tank II through locked open
valve 10-762.
Valve 10-1188
was located
about six feet above the
base of the raw water tank,
such that if it were opened it would
drain most of the TS-required fire supply water from the tank.
The pipes connecting
each of these
valves to the raw water booster
pumps
had recently
been
removed
a part of a modification to the
fire water
and service water systems.
Valves 10-1188
and 10-1187
had clearance
tags attached,
indicating that they were to remain
in the closed position per clearance
No. 0-92-11-019-R.
Subsequent
review found that the clearance,
located in the control
room, referenced
PC/H 92-108
and stated that these
two valves were
tagged
closed for administrative control.
The inspector
asked
a licensee
engineer
who was in the area
inspecting the fire water supply system if there should
be
a blank
flange or lock on valve 10-1188.
Review of the current drawing,
which the engineer
had with him (Drawing No. 5610-T-E-4072,
Operating
Diagram, Fire Protection
System Tanks
L Pumps,
Rev.
24,
dated
November 23,
1992),
showed that valves
10-1187
and 10-1188
had
been
removed
and replaced with blank flanges.
The inspector
and engineer
noted that the drawing was in error.
Additional
review found that the drawing error had
been
made in rev.
23,
dated
November
13,
1992,
and that error had
been carried over into
rev.
24.
Rev.
22 of the drawing, which included valves
10-1187
and 10-1188,
indicated that the sections of piping including those
two valves were inside the
"Q" boundary, i.e. they were quality
related
and important to safety.
The engineer,
working with
licensee fire protection,
operations,
and engineering
personnel,
responded
with prompt interim action.
A lock was placed
on valve
10-1188 that day and
a corrected
drawing, rev. 25,
was issued that
10
same
day, January
11,
1993.
Also, licensee
engineers
conducted
a
walkdown of the piping system
shown in the drawing
and found that
there were
no other errors
on the drawing.
Later, it was
determined that
a lock was not required
on valve 10-1188
and the
lock was removed.
Although it was determined that the noted drawing error had little
safety significance, it is another
example of minor inaccuracies
on drawings.
The licensee
does
have
a program in place to replace
the existing T-E drawings with P&IDs by mid 1993.
As a result of routine plant tours
and various operational
observations,
the inspectors
determined that the general
plant
and system material
conditions were satisfactorily maintained,
the plant security program
was effective,
and the overall performance of plant operations
was good.
Violations or deviations
were not identified.
Plant Events
(93702)
The following plant events
were reviewed to determine facility status
and the need for further followup action.
Plant parameters
were
. evaluated
during transient
response.
The significance of the event
was
evaluated
along with the performance of the appropriate
safety
systems
and the actions
taken
by the licensee.
The inspectors verified that
required notifications were
made to the
NRC.
Evaluations
were performed
relative to the need for additional
NRC response
to the event.
Additionally, the following issues
were examined,
as appropriate:
details regarding the cause of the event;
event chronology; safety
system performance;
licensee
compliance with approved
procedures;
radiological
consequences, if any;
and proposed corrective actions.
a ~
Step 7. 1. 18 of procedure
4-0SP-051.6,
Containment Air Lock Doors
Operability Test, requires
the outside air lock door latch of the
containment
personnel
air lock to be slowly turned toward the
unlatched position in order to verify that the door will not
unlatch.
During performance of this step at 2:30 a.m.
on
January
14,
1993, the outside air lock door latch partially moved
in the unlatched position,
and air flow was detected.
Both doors
were immediately closed,
the containment
personnel
air lock was
declared
out of service,
and action statement
b of TS 3.6.1.3
was
entered.
This action statement
required at least
one air lock
door to be maintained
closed
and required the inoperable air lock
to be restored to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or bring the
unit to at least
Hot Standby within the next
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
and in Cold
Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The interlock linkages
were adjusted,
and Section 7. 1, Containment
Personnel
Air Lock
Test, of 'procedure
4-0SP-051.6
was re-commenced
at 6:15 a.m.
This
test
was completed at 6:45 a.m.,
and the containment
personnel air
lock was returned to service at 7: 10 a.m.
b.
At 2:32 p.m.
on January
15,
1993, the licensee
declared
an Unusual
Event due to the identification of RCS pressure
boundary
leakage
11
on Unit 3.
The leak was from a cracked
weld on
a pipe cap
on the
abandoned
spray valve bypass
pipe between
the previous
A spray
valve body and the pressurizer
spray nozzle.
The licensee
commenced
a unit shutdown at 2:35 p.m.
on January
15,
1993,
and
the unit reached
Hode
5 at 6: 15 p.m.
on the following day.
NCR N-93-005 was issued to document the condition
and
PC/H 933-012
was issued to repair the leak.
After cooldown,
a more detailed
visual inspection identified the leak location
on the pipe cap to
nipple socket weld.
After the piping assembly
was removed,
microscopic examination of the failed weld revealed
ID initiated
branch cracking,
which is indicative of SCC.
Additionally,
examination
showed
inadequate
pullback between the pipe
and cap
(the cap appeared
to have
been
bottomed out on the pipe).
The
lack of pullback can cause
high localized stresses
which increases
the chances
of SCC.
Repair of the failed weld was accomplished
per
PC/H 93-012
on January
17,
1993,
and preparations
were
made to
return the unit to service
(Refer to paragraph
2 for further
information on the plant startup).
At 4:32 p.m.
on January 16,'993,
PORV PCV-3-456 momentarily
lifted once
and immediately reseated
while the licensee
was in the
process
of collapsing the pressurizer
bubble for the establishment
of a solid water condition during
a Unit 3 shutdown.
Prior to
this event,
the 3A RCP had
been secured,
and the
3B and
3C
pumps were running.
OHS was in service,
and the
3B and
3C
charging
pumps were running with a 45 gpm orifice in service.
temperature
was approximately 260'F
and stable,
and
RCS average
pressure
was approximately
315 psig.
The
NPS had cautioned
the
RCO performing the evolution to monitor
RCS pressure
and to be
prepared for solid conditions at any time because
the wide range
level could be incorrect.
This was due to the actual
temperature
being greater
than the wide range pressurizer
level
calibration temperature
of 68'F.
In order to reduce the
charging/letdown
mismatch to allow greater control while
approaching
solid conditions,
the
RCO secured
one of the two
running charging
pumps.
This action reduced
the mismatch to
approximately
20 gpm.
At this point, wide range pressurizer
level
was approximately
87%.
It increased
to approximately
88.5% and
leveled off.
With the
NPS,
ANPS,
and
STA present,
the
RCO
performing the evolution explained that
as the water level rose
and covered the vapor temperature
tap, the vapor temperature
which
read approximately 430'F would begin to decrease
rapidly and
approach
the water temperature.
The
RCO explained that
he had
recently performed this evolution and
had noticed this occurrence
well before going solid.
No change in vapor temperature
was
noted.
At approximately 4:29 p.m., pressurizer
pressure
began to
increase rapidly with wide range pressurizer
level indicating
steady at approximately
88.5%.
When this pressure
increase
was
noted
by the
RCO in charge of the unit, the
RCO performing the
evolution reached for the charging
pump speed controller and
letdown flow control valve.
Although actions
were taken to slow
the pressure
increase
by increasing
letdown flow and decreasing
12
charging flow, pressure
increased
to the point {approximately 415
psig) where
PORV PCV-3-456 momentarily cycled open
once
as
designed
and immediately reseated.
The alert annunciator
and the
PORV lift occurred simultaneously
as the
RCO was securing
the
charging
pump.
The charging
pump was subsequently
restarted,
and
RCS pressure
was stabilized at approximately
310 psig.
This event
was attributed to the wide range pressurizer
level
indicating steady at 88.5% when the solid water condition was
achieved
and to the
RCO's failure to slow the
RCS pressure
increase
in time to prevent the
OHS actuation.
As a result of
this event,
the
RCO was counselled
by Operation's
Hanagement,
and
procedure
changes
were initiated,
The licensee
plans to
incorporate
a pressurizer
level correction curve into procedures
'by February
5,
1993.
1n addition,
by February
22,
1993,
the
licensee
plans to incorporate
procedure
changes
including the
addition of requirements
to maintain
RCS pressure
between
325 and
350 psig using the highest indicated pressure,
the
recommended
method of RCS pressure
control during solid water operations,
a
caution to stop the charging
pumps if a pressure
increase
cannot
be controlled by charging
and letdown,
a caution to stop the
if the
RCS pressure
decreases
to the
RCP No.
1 seal differential
pressure
low limit, and the requirement that
an operator
who has
been briefed by the unit ANPS to ensure
understanding will be
dedicated
to the tasks of drawing
a pressurizer
bubble or going
solid.
Operators
have also
been
scheduled
to receive
classroom
{procedure)
and simulator training on solid water operations
by
April 15,
1993,
and
an
REA has
been
submitted requesting
a
setpoint
change for the
OHS alert annunciator.
This change
would
allow the setpoint to be varied with a maximum limit dependent
on
the desired
RCS pressure.
TS 6.8. l.a requires that written procedures
and administrative
policies
be established,
implemented,
and maintained in accordance
with the requirements
and recommendations
of Appendix
A of
Regulatory
Guide 1.33,
Revision 2, dated
February
1978.
Section
1.b of this Appendix recommends that written procedures
be
established
for administrative
procedures
which include
authorities
and responsibilities for safe operation
and shutdown,
and Section 2.j of this Appendix recommends
general
plant
operating
procedures
for plant operation
from Hot Standby to Cold
Shutdown.
Paragraph
5. 1.6 of procedure
O-ADH-200, Conduct of
Operations,
requires all on-shift Operations
personnel
to be aware
of and responsible for the plant status
at all times.
Paragraph
5.14.2.2 of procedure
3-GOP-305,
Hot Standby to Cold Shutdown,
requires that pressurizer
pressure
be maintained within the range
of 325 to 375 psig for the collapsing of the pressurizer
bubble
and establishment
of a solid water condition.
Contrary to these
requirements,
on January
16,
1993, while collapsing the
pressurizer
bubble for the establishment
of a solid water
condition on Unit 3, pressurizer
pressure
was not maintained
below
375 psig.
This resulted in the inadvertent
momentary opening of
/
13
PORV PCV-3-456.
This failure to follow a procedure constitutes
a
violation; however, this violation is not being cited because
the
criteria specified in Section VII.B of the
were satisfied.
This item will be tracked
as
NCV 50-250,251/93-01-01,
failure to maintain pressurizer
pressure
below 375 psig resulting in the inadvertent
opening of a
PORV.
This item is closed.
Although the root causes
of previous inadvertent
PORV opening
events
and the more recent January
16,
1993,
event discussed
above
were unrelated;
the increased
frequency of these
types of events
has
caused
a concern regarding the lack of attention to detail.
On January
16,
1993, at approximately
11:00 p.m., the licensee
notified the
NRC of a reportable
event per
The event involved the inadvertent closing of the
CSP discharge
valves
3-891A and
B prior to
RCS temperature
going less
than
200'F.
On January
16,
1993, at 9:45 p.m., during the review of
SNPO log readings,
the Unit 3 ANPS recognized that containment
spray valves 3-891A and
B were logged
as locked closed at 8:00
a.m. that
same day.
Investigation
showed that valves
3-891A and
B
were closed at 5:00 a.m.,
at the
same time the operators
isolated
the
HHSI valves,
the accumulator discharge
isolation valves,
and
other required actions
when
T average
became
less
than 380'F.
Procedure
3-GOP-305,
Hot Standby to Cold Shutdown,
paragraph
5.8.3, states
that when T average is less than 380'F,
then
among
other actions,
align the
HHSI valves,
the accumulator
discharge
isolation valves,
and other alignments in accordance
with
attachment
1, Cold Shutdown Alignment Requirements.
Reference
Step 5.8.3 of Attachment
1 requires certain valve and breaker
alignments that do not include the
CSP isolation valves.
Paragraph
5. 15.3. requires that when the
RCS temperature
is less
than 200'F,
then isolate containment
spray in accordance
with
Attachment I.
Reference
Step 5. 15.3 of Attachment
1 requires
valves 3-891A and 3-891B to be closed.
Investigation of this event
shows there
was poor communications
between the control
room
RCO and the
SNPO in the auxiliary
building.
The
SNPO possessed
Attachment
1 to 3-GOP-305;
however,
the method of communication
was inadequate
to correctly perform
the task.
The
RCO copied Attachment
1 to 3-GOP-305
and
highlighted certain
items to be accomplished
including portions of
reference
steps
5.8.3
and 5.15.3.
The
SNPO, while accomplishing
the highlighted steps of Attachment
1 to 3-GOP-305,
asked
the
RCO
if he should accomplish the remaining highlighted steps.
The
RCO
replied to the affirmative without discussing
which specific
valves were to be operated.
A second
SNPO independently verified
the highlighted valves
and breakers
on the field copy of
Attachment
1 to 3-GOP-305.
The poor communications
between the
RCO and the
SNPO led the
RCO to believe
he was accomplishing the
required
steps in proper
sequence
and the
RCO was not aware the
14
CSP discharge
valves
had
been closed.
The Unit 3 ANPS directed
the
RCO to accomplish
the steps
in 3-GOP-305 in specific order
as
plant conditions dictated
and
was not aware that the
CSP discharge
valves
had
been closed.
The
RCO on peak shift that
had Unit 3 responsibility
when Unit 3
entered
Hode
5 (<200'F) at 6:15 p.m.
on January
16,
1993, put the
CSP controls in pull-to-lock, however,
the
RCO did not direct the
isolation of containment
spray in accordance
with 3-GOP-305 at
that time.
At 9:00 p.m. the
RCO,
when ready to accomplish
step
5. 15.3 of 3-GOP-305
(which isolates
the
CSP discharge
valves)
noted that Attachment
1 was signed off and independently verified.
The
RCO in charge of Unit 3 assumed
that
a second
RCO that was
assisting
in the control
room had ordered the
CSP discharge
valves
be closed
per attachment
1
and
he therefore initialled step
5. 15.3
of 3-GOP-305
as accomplished.
At 9:45 p.m.
on January
16,
1993, the
ANPS, while reviewing the
SNPO log readings,
noted that containment
spray valves 3-891A and
3-891B were logged
as closed at 8:00 a.m.
The
ANPS recognized
that valves 3-891A and 3-891B should not have
been closed until
Hode
5 (which occurred at 6:15 p.m.)
and initiated
an
investigation which revealed
the sequence
of events previously
noted.
TS 3.6.2. 1, Containment
Spray System,
requires
in Hodes
1, 2, 3,
and
4 that two CSSs
be operable.
Action statement
b states
that
with two CSSs inoperable,
restore
at least
one
status within one hour or be in at least
Hot Standby
(T average>
350'F) within the next
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
and in Cold Shutdown
(T average<
200'F) within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The
CSSs were inoperable
with the
RCS temperature
greater
than 200'F from approximately
5:00 a.m. until 6: 15 p.m. or approximately thirteen
hour s,
therefore
LCO was not exceeded.
The licensee
performed
an engineering
evaluation to assess
the
impact of isolating containment
spray
on the plant's
response
to
an accident with an average
RCS temperature
of approximately 350'F
or less.
At the time the
were isolated,
Unit 3 had
been shut
down for approximately
10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with an average
RCS temperature
of
350'F or less.
The engineering
evaluation
noted that the analysis of the plant
response
to a
LOCA with the plant in other than
Hode
1 is not
explicitly analyzed
in the
FSAR.
Per Turkey Point's original
licensing basis, it was
assumed
that
an accident in a Hode other
than
power operation
would be bounded
by the full power event.
has studied
shutdown accidents
(Hodes
3 and below)
and
has
shown that the largest credible break would be
a 6-inch
pipe break attached to the
RCS cold leg.
15
The
LOCA containment integrity FSAR analysis is performed at
100%
hot full power operation
assuming
a double
ended pipe break.
The
analysis
is performed specifically for Hode
1 operation,
because
it bounds the other
modes
and it represents
the limiting scenario
for containment integrity, in part,
because
the stored
energy in
the systems
are at their highest.
For this event,
the containment
peak pressure
and temperature
peak is turned
by the action of the
containment
heat sinks prior to the
CSS starting
and loading.
Therefore,
the
CSS function is to reduce
containment
pressure
and
temperature
and to remove decay heat.
Both the primary and
secondary
sides of the
RCS were at lower pressures
and
temperatures
than the
100% hot full power analyzed
values
when the
was isolated,
while the system stored energies
were
significantly reduced.
The effect of having the
CSSs unavailable
with the primary system at or about 350'F would be bounded
by the
assumptions
and conditions of the accident analysis,
and would not
represent
a challenge to the integrity of containment,
or
equipment qualification.
The
CSS is part of the plant's
system described
in Section 6.4 of the Final Safety Analysis
Report.
The primary purpose of the Containment
Spray
system is to
spray cool water into the containment
atmosphere
when appropriate
in the event of a
LOCA and therefore
assure that containment
pressure
and temperature limits are not exceeded.
For purposes
of
maintaining containment integrity, the three
ECCs are considered
fully redundant to the
CSS.
For purposes
of environmental
qualification, at least
one
CS pump
and two ECCs are
assumed
available to reduce the containment
temperature within the time
limits of the
Eg curve following a design basis
LOCA.
The
CSS also functions to reduce temperature
and pressure
following a Hain Steam Line Break accident.
However, for purposes
of containment design,
a
LOCA is considered limiting.
Considering
a single failure, two
by themselves
would be sufficient to
remove decay heat at the reduced levels that correspond
to
a plant
shutdown for ten hours.
Therefore,
the
ECCs would be capable of
reducing containment
temperature
and pressure
following the
initial blowdown.
TS 6.8. 1 requires that written procedures
be established,
implemented,
and maintained covering the activities referenced
in
Appendix A of Regulatory
Guide 1.33, revision 2, February
1978.
Regulatory
Guide 1.33,
Appendix A, Section
1,
recommends
administrative
procedures
for authorities
and responsibilities for
safe operation
and shutdown.
Section 2.j also
recommends
operating
procedures
for going from hot shutdown to cold shutdown.
Administrative procedure
O-ADH-200, Conduct of Operations,
paragraph
5.6.20,
states
that communications to operating
personnel
must
be clear
and concise.
These directions shall
be
given in such
a manner that they are explicit and understandable.
This should
be verified for complex orders
and those orders that
include numbers
by having the operator
repeat
them back or by
providing written direction
so that the director is satisfied that
16
the orders
are understood.
Upon completion of the directed
evolution, the operator shall report back to the controlling
station the exact action that he/she
has taken.
General
Operating
Procedure
3-GOP-305,
Hot Standby to Cold Shutdown,
provides the
prerequisites,
precautions/limitations,
and instructional
guidance
for changing plant conditions from hot standby to cold shutdown.
Step 5. 15 states
that when the reactor coolant temperature
is less
than 200'F,
then perform the following steps.
Step
5. 15.3 then
states
to isolate containment
spray in accordance
with Attachment
1, Cold Shutdown Alignment Requirements.
However, at
approximately
5:00 a.m.
on January
16,
1993, with the reactor
coolant temperature
at approximately 350'F,
the reactor control
operator directed the senior nuclear plant operator to accomplish
the highlighted portions of Attachment
1 to 3-GOP-305.
No
explicit directions
were provided
and
no report back of the exact
action taken
was accomplished resulting in the inadvertent
isolation of the containment
spray
system prior to reactor coolant
temperature
being less
than 200'F.
This failure to follow
procedures
is
a violation and will be tracked
as
VIO 50-250,
251/93-01-02,
Failure to follow procedures
in the area of conduct
of operation resulting in the isolation of containment
spray prior
to
RCS temperature
going below 200'F.
Also, there were several
missed opportunities to have identified this discrepancy earlier.
As noted in paragraph
8.c above,
the increased
frequency of
operator errors
has
caused
a concern regarding the lack of
attention to detail.
On January
15,
1993, the licensee notified the resident
inspector
of the preliminary results of their investigation into the cause
for an unexpected
increase
in the local peaking factor and
a more
positive power distribution following the Unit 3 startup
on
December
3,
1992.
A flux map performed
on December
29,
1992, at
100% power, equilibrium xenon,
and steady state conditions
prompted reactor engineering to investigate
the cause of the
unexpected results.
reviewed their manufacturing
records
and
on January
14,
1993,
confirmed that the
WABA rods were
manufactured
incorrectly resulting in the absorber centerline
being positioned
1.368 inches lower than the fuel center line.
This condition existed for both Unit 4, cycle
13 and Unit 3, cycle
13.
Unit 3 cycle
13 started
on December
3,
1992,
and Unit 4 cycle
13 started
on October 29,
1991.
Unit 4 is scheduled for a
refueling outage
(cycle 14) in April, 1993.
The
FPL fuel design
specifications
were not properly implemented
by Westinghouse
for
manufacturing the
WABAs for the
new debris resistent
fuel
assemblies.
Engineering evaluation
JPN-PTN-SEFJ-93-002,
Assessment
of Operability and Past
Performance
With Offset Wet
Annular Burnable Absorbers at Turkey Point Unit 3, Cycle 13,
and
Unit 4, Cycle 13, concluded that both Units 3 and
4 had operated
within the design basis
and that continued operation within TS
parameters
would ensure
operation within the design basis.
No TSs
were violated.
FPL is reviewing contractor
oversight activities
to determine if the manufacturing error could or should
have
been
17
identified earlier.
It appears
that the
WABA configuration for
Unit 4, Cycle
13 was sufficiently different such that
any effects
on local peaking factors
and for axial
power distrjbution would
have
been less
obvious
and more difficult to recognize.
The
recognition of the unexpected
peaking
and
a more positive power
distribution anomalies
on Unit 3 and the pursuit of a root cause
is considered
a strength.
Starting with Turkey Point Unit 3, Cycle 12, the fuel assembly
design
was modified to reduce
the probability of fuel failures.
The
DRFA design contained
a longer solid bottom endcap to reduce
debris fretting and in turn raised the fuel stack
1.368 inches.
The
DRFA fuel design
has
been incorporated
in Turkey Point Unit 3
Cycles
12 and
13 and in Turkey Point Unit 4 Cycle 13.
The
WABA rods are
used in the core for reactivity control
and to
aid in reducing
power peaking.
The Turkey Point Unit 3 Cycle
13
core contains
512
WABA rods,
each
108 inches in length
and the
Turkey Point Unit 4 Cycle
13 core contains
a total of 368
WABA
rods,
most at
126 and
some at
108 inches in length.
These cycles
were designed with the
WABA rods centered
on the fuel mid-plane.
The
WABAs provide the highest
power shaping control early in the
cycle and their reactivity control capability is reduced with
increasing
cycle operation.
Contrary to the core design
requirement that the
WABA rods
be centered
on the fuel mid-plane,
the
WABAs were manufactured
such that the absorber
length
was not
centered
on the active fuel mid-plane.
In December
1992 while performing the first 100% power
steady
state flux map at Turkey Point Unit 3 Cycle 13,
a discrepancy
between the predicted
and measured total peaking factor (Fq)
was
observed.
Subsequent
investigation of the deviation led to the
conclusion that the
WABA rods were incorrectly positioned relative
to the active fuel stack
by 1.368 inches.
10 CFR Part 50, Appendix B, guality Assurance Criteria for Nuclear
Power Plants
and
Fuel
Reprocessing
Plants, Criterion VII, Control
of Purchased
Haterial,
Equipment,
and Services,
states that
measures
shall
be established
to assure
that purchased
material,
equipment,
and services,
whether purchased directly or through
contractors
and subcontractors,
conform to the procurement
documents.
The failure to implement measures
that assure
the
WABA
assemblies
conformed to the procurement
document is
a violation.
However, this violation will not be subject to enforcement
action
because
the licensee's
efforts in identifying and correcting the
violation meet the criteria specified in Section VII.B of the
NRC
This item will be tracked
as
NCV 50-250,251/93-01-03,
failure to implement measures
to assure
that the
WABA assemblies
conformed to procurement
documents.
This
item is considered
closed.
18
At 11:00 p.m.
on January
25,
1993, the control
room began to shift
loads
on the
4A 4KV bus
due to the identification of a ground
on
the bus.
The ground
was isolated to the
4A condensate
pump at
11: 11 p.m.,
and the
4A condensate
breaker
was racked out at 11:20
p.m.
due to the ground.
As
a precautionary
measure
due to
inclement weather
and the possibility of losing
a second
condensate
pump,
a power reduction
was
commenced
at 7:50 a.m.
on
January
26,
1993.
Unit 4 reactor
power was stabilized at
70% at
9:40 a.m.
Power ascension
was
commenced
at 12:00 p.m.,
and
100%
reactor
power was attained at 5:30 p.m.
on the
same day.
Meeting on Results of Twentieth Year Tendon Surveillance for Units
3 and
4.
(94702)
A regional
inspector attended
a meeting held
on January
11,
1993,
in the
NRC Headquarters
office at
One White Flint North, Rockville, Maryland.
Attendees
at the meeting
are listed in paragraph
1 above.
The purpose
of the meeting
was to discuss
the results of the twentieth year tendon
surveillance results, specifically, the low lift-offvalues
measured
in
four Unit 3 and seven Unit 4 tendons,
and the licensee's
long-term
corrective actions.
The tendons with the low lift-offforces were
. retensioned
in accordance
with TS requirements.
The licensee
also
submitted special
reports
summarizing the low lift-offvalues
and
short-term corrective actions (retensioning)
as required
by the TSs.
The licensee attributed the root cause of this problem to be
underestimation
of the time-dependent
steel
relaxation values during
original design.
The original design
was
based
on steel
relaxation
values obtained
from test data which used
an ambient value of 68'F,
which was the current practice at that time.
Review of plant specific
temperature
data
shows that the average
temperature
is 90'F at the
tendon location.
Testing performed
on tendon wires for other sites
experiencing similar problems
showed that this small temperature
difference
has significant effect
on steel
relaxation values.
The
licensee
stated that re-analyzing
the predicted lift-offvalues
using
the stress
relaxation data corresponding
to
a 90'F temperature
correlates
well with the measured lift-offvalues.
The licensee
planned
long-term corrective actions
include reanalyzing the containment
using
appropriate effective prestress
forces
based
on the licensing basic
internal containment
pressure
of 55 psig.
The 55 psig containment
pressure
has
a
10% margin over the calculated
accident pressure
of 49
psig.
The licensee will submit
a report to
NRC on January
29,
1993, to
document their proposed
long term corrective actions.
Additional
reports will be submitted
as required to documet that the re-analysis
is
in compliance with FSAR commitments.
The containment post-tensioning
system meets
TS requirements,
and will be maintained
beyond the next
scheduled
surveillance.
Exit Interview
The inspection
scope
and findings were summarized during management
interviews held throughout the reporting period with the Plant General
19
Hanager
and selected
members of his staff.
An exit meeting
was
conducted
on January
29,
1993.
The areas requiring management
attention
were reviewed.
The licensee
did not identify as proprietary
any of the
materials
provided to or reviewed
by the inspectors
during this
inspection.
Dissenting
comments
were not received
from the licensee.
The inspectors
had the following findings:
Item Number
Descri tion and Reference
50-250,251/93-01-01
NCV - Failure to maintain pressurizer
pressure
below 375 psig resulting in the inadvertent
opening of a
PORV (paragraph S.c).
50-250,251/93-01-02
VIO - Failure to follow procedures
in the area
of conduct of operations resulting in the
isolation of containment
spray prior to
temperature
going below 200'F
(paragraph
S.d).
50-250,251/93-01-03
NCV - Failure to implement measures
to assure
that the
WABA assemblies
conformed to
procurement
documents
(paragraph
S.e).
and Abbreviations
ADM
ANPS
CFR
DRFA
F
Fq
GL
gpm
-ICW
ID
IR
JPN
KV
LCO
Administrative
Assistant
Nuclear Plant Supervisor
Component Cooling Water
Code of Federal
Regulations
Containment
Spray
Containment
Spray
Pump
Containment
Spray System
Debris Resistent
Fuel Assembly
Emergency
Containment
Cooler
Engineered
Safety Feature
Environmental Qualification
Fahrenheit
Flow Control Valve
Florida Power
and Light
Peaking
Factor
Final Safety Analysis Report
Generic Letter
General
Operating
Procedure
Gallons
Per Ninute
High Head Safety Injection
Instrument Air System
Intake Cooling Water
Inside Diameter
Inspection
Report
Juno Project Nuclear
Kilovolt
Limiting Condition for Operation
20
LER
HSR
MWe
NRC
ONOP
OP
P &ID
PC/M
pslg
PTN
QAO
.QC
RCO
REA
SNPO
T
TS
WABA
Licensee
Event Report
Loss-of-Coolant Accident
Moisture Separator
Reheater
Megawatts Electric
Non-conformance
Report
. Non-Cited Violation
Nuclear Plant Supervisor
Nuclear Regulatory
Commission
Office of Nuclear Reactor Regulation
Overpressure
Mitigation System
Off Normal Operating
Procedure
Operating
Procedure
Operations
Surveillance
Procedure
Piping and Instrumentation
Drawing
Plant Change/Modification
Pressure
Control Valve
Power Operated Relief Valve
pounds
per square
inch gauge
Plant Turkey Nuclear
Quality Assurance
Quality Assurance
Organization
Quality Control
Reactor Control Operator
Pump
Request
For Engineering Assistance
Residual
Heat
Removal
Stress
Corrosion Cracking
Senior Nuclear Plant Operator
Temperature
Terminal
Box
Turkey Point
Technical Specification
Violation'et
Annular Burnable Absorber