ML17312B745
| ML17312B745 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 10/29/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17312B743 | List: |
| References | |
| 50-528-97-16, 50-529-97-16, NUDOCS 9711060133 | |
| Download: ML17312B745 (36) | |
See also: IR 05000528/1997016
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-528
50-529
50-530
NPF-51
50-528/97-1 6
50-529/97-1 6
50-530/97-1 6
Arizona Public Service Company
Palo Verde Nuclear Generating Station, Units 1, 2, and 3
5951 S. Wintersburg Road
Tonopah, Arizona
September
7 through October 18, 1997
Jim Moorman, Senior Resident Inspector
Resident Inspector
Dan Carter, Resident Inspector
John Kramer, Resi'dent Inspector, San Onofre Nuclear Generating
Station
Dennis F. Kirsch, Chief, Reactor Projects Branch F
Attachment:
Supplemental
Information
97ii060i33 97i029
ADQCK 05000528
6
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EXECUTIVE SUMMARY
Palo Verde Nuclear Generating Station, Units 1, 2, and 3
NRC Ihspection Report 50-528/97-16; 50-529/97-16; 50-530/97-16
~Oerations
On September 8, 1997, the Unit 2 reactor coolant system was drained to the hot
midloop condition by a dedicated midloop operating crew which augmented
the
normal operating crew during the evolution.
Operator oversight and direction of the
evolution and decisions to take conservative actions during the evolution were
excellent.
The use of a designated
midloop operating crew was seen as a strength
(Section 01.1) ..
On October 6, 1997, the Unit 2 reactor coolant system was drained to the cold
midloop condition.
A dedicated
midloop operating crew augmented
the normal
operating crew during the evolution.
During the draindown,
a discrepancy between
the "A" and "B" channels of reactor water level indication system was discovered,
which was caused by an open shutdown cooling bypass-valve.
This resulted in less
than 3780 gpm of flow through the core, a violation of TS 3/4.4.1.4.2.
Operator
oversight and direction of the evolution and decisions to take conservative actions
related to the discrepancy observed with reactor level measurement
were excellent.
Immediate corrective actions were timely (Section 01.4).
Observation of core offload and reload activities associated
with the Unit 2,
Cycle 7, refueling outage indicated that refueling personnel consistently used good
communications
and demonstrated
a safety-conscience
approach to performing
refueling operations.
Personnel
performance was excellent (Section 01.2).
In response
to the unexpected
loss of power to the PBB-SO4 4160V Class
1E Bus
on September
17, 1997, the control room operations staff responded
in an excellent
manner (Section 01.3).
Maintenance
Maintenance
and surveillance activities observed
by the inspectors were generally
conducted
in a'safety conscious
manner by knowledgeable
technicians using
current procedures
(Section M1.3).
The inspectors verified that the licensee conducted the Unit 2 containment close out
activities in a thorough manner (Section M2.1).
The licensee installed steam generator
(SG) nozzle dams in the Unit 2 SG during the
Cycle 7 refueling outage to support eddy current testing of the SG tubes.
The
licensee did not provide the foreign material exclusion (FME) responsible
person the
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viewing point and communication tools to properly monitor all items entering. and
exiting the SG Zone III area; a weakness that has since been corrected.
However,
the licensee's
SG nozzle dam installation procedure
and FME training provided to
the nozzle dam installers ensured that acceptable
FME practices were maintained
(Section M3.1).
\\
~
When calibrating the refueling water level indication system detectors to support the
Unit 2, Cycle 7, refueling outage, Instrumentation 5 Controls (l8cC) personnel failed
to adhere to procedural guidance.
This resulted in a non-conservative
eight inch
error in reactor water level indication.
The noncited violation of procedures
represents
poor work practices by the technicians.
The licensee's corrective
actions were sufficiently complete and thorough (Section M4.1).
~En ineerin
~
The engineering department performed an accurate calculation and generated
a
good temporary procedure to verify the adequacy of the shutdown cooling system
to cool the fuel in the reactor vessel and supplement the spent fuel pool cooling
system, as required in the Updated Final Safety Analysis Report (UFSAR). Although
calculations indicated performance of this test was unnecessary,
the licensee's
decision to verify the calculations through performance of the test was a good
example of conservative plant operations
(Section E1.1).
Plant Su
ort
~
.
The licensee removed the Unit 2 core barrel during the Cycle 7 refueling outage for
the 10 year inservice inspection.
The licensee's thorough planning, coordination of
activities, and training of personnel resulted in a'successful
removal of the core
support barrel from the reactor vessel with minimal radiation exposure to personnel.
The licensee's activities to ensure that radiation dose rates remained low were
, excellent (Section R4.1).
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Re ort Details
Summar
of Plant Status
Units
1 operated at essentially 100 percent power for the duration of the inspection period.
Unit 2 began this inspection period in Mode 6. The unit was in midloop operation on two
occasions,
once on Se'ptember 8-9, 1997, (Section 01.1) and the second time on
.
October 6, 1997 (Section 01.4).
On October 11, 1997, the unit commenced
a reactor
startup and power ascension.
The unit reached
100 percent power on October 17, 1997,
and remained there for the duration of the inspection period.
Units 3 operated at essentially 100 percent power until October 7, 1997, when the unit
was reduced to 87 percent power for approximately 7.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to replace
a failed pressure
switch in the steam plant.
The unit was returned to 100 percent power and remained at
that power level for the duration of the inspection period.
I. 0 erations
01
Conduct of Operations
01.1
Unit 2 Midloo
Reduced
Inventor
Activities
a.
Ins ection Sco
e 71707
On September
8, 1997, the inspectors observed control room operators draining the
(RCS) using Procedure 40OP-9ZZ16, "RCS Drain
Operations," Revision 8. The unit was being placed in midloop conditions to install
SG nozzle dams in preparations for eddy current testing.
The inspectors reviewed
the preoutage
midloop training video, RCS draining procedures,
and attended the
briefing before the draining operation.
b.
Observations
and Findin s
The inspectors attended the briefing for the midloop evolution.
The midloop control
room supervisor conducted the briefing professionally with the appropriate nuclear
safety focus.
The inspectors
also reviewed the licensee's
Procedure 400P-9ZZ16,
prior to the reduction of RCS inventory and verified that the prerequisites
were met.
The licensee augmented
the onshift operating crew with a dedicated
midloop team
to perform the midloop operation.
The midloop team was comprised of a control
room supervisor,
a reactor operator, and shift technical advisor who was acting as
midloop coordinator.
The inspectors observed that the midloop team
maintained
positive control of the evolution.
The licensee minimized unnecessary
work while the unit was in a reduced inventory
condition.
To prevent loss of shutdown cooling or RCS level perturbations,
the
licensee incorporated
a supplemental
senior reactor operator (SRO) who was
stationed at the entry of the auxiliary building to screen work activities going into
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the field.
In addition, the licensee maintained sources of offsite and onsite power
available, and limited access to critical equipment areas.
During the draindown, at approximately the 103 foot 8 inch level, the midloop crew
identified that refueling water level indication system (RWLIS) instrumentation was
remaining constant.
At this point, level should have been indicating a continued
reduction.
The operators stopped the draindown and determined that a calibration
problem existed with both channels of the RWLIS. The miscalibration of the RWLIS
is discussed
further in Section M4.1,
Unit 2 was in midloop operation for approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />.
During that time the
licensee implemented and maintained the requirements
specified by
Procedure
400P-9ZZ1 6.
C.
Conclusion
On September
8, 1997, Unit 2 was drained to the hot midloop condition by a
dedicated midloop operating crew which augmented
the normal operating crew
during the evolution.
Operator oversight and direction of the evolution and
decisions to take conservative
actions during the evolution were excellent.
The use
of a designated
midloop operating crew was seen as a strength.
01.2
Full Core Offload and Reload
Unit 2
aO
Ins ection Sco
e 60710)
The inspectors reviewed, in part, the licensee's performance of a full core offload
and reload as controlled by Procedure 72IC-9RX03, "Core Reloading," Revision 9.
b.
Observations
and Findin s
Unit 2 refueling operations were observed during the period.
The refueling SRO was
in charge of the overall fuel movement process,
and was stationed
in containment
to directly supervise
AIIfuel movement was coordinated with the
control room and logged in accordance with Procedure 72IC-9RX03.
Good
communications were observed between the refueling SRO, the fuel pool bridge
operator, and the control room.
The inspector independently verified that both
startup channels were operable during the fuel movement.
C.
Conclusions
Observation of core offload and reload activities associated
with the Unit 2,
Cycle 7, refueling outage indicated that refueling personnel consistently used good
communications
and demonstrated
a safety-conscience
approach to performing
refueling operations.
Personnel
performance was excellent.
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01.3
Unit 2 Loss Of Power
LOP on 4160 V Class
1E Bus 8
a.
Ins ection Sco
e 71707
On September
17, 1997, at 3:40 a.m., a LOP occurred on Unit 2 B 4160 V Class
1E bus (PBB-SO4).
The inspector was in the control room when the event occurred
and observed
operations
personnel
respond to the event.
Unit 2 was in the
Cycle 7 refueling outage with the full core offloaded to the spent fuel pool (SFP).
b.
Observations
and Findin s
At approximately 3;40 a.m. on September
17, 1997, an emergency safety features
actuation, specifically a LOP actuation, occurred on Bus PBB-S04.
The licensee's
preliminary investigations indicated that the apparent cause of the LOP was a failure
in Load Sequencer
B, which resulted in a load shed signal to Bus B. Prior to the
event, Bus PBB-SO4 had been declared inoperable for maintenance,
but was still
energized.
Diesel Generator
B had been properly removed from service under a
clearance for scheduled
maintenance
and did not start.
Once the event occurred, the operators entered Abnormal Procedure 40AO-9ZZ12,
'Degraded
Electrical Power," Revision 1. The operations staff exhibited good
oversight and direction of activities in the control room during the event.
During the event the inspectors verified that the SFP was being adequately. cooled
by Train A of the spent fuel pool cooling (SFPC) system, since the full core was
being stored in the SFP.
An auxiliary operator was tasked with monitoring the SFP
temperature.
During the preliminary investigation, the SFP temperature
increased
approximately 3.5 'F, but was well below the established
limit.
On September
17, at 10:35 a.m., the PBB-SO4 bus was reenergized.
At 11 a.m.
the licensee started SFPC Pump B in parallel with SFPC Pump A to reduce SPF
temperature.
The licensee initiated Condition Report/Disposition Request
(CRDR) 2-7-0320 to
address this issue.
The cause of the event was still under investigation by the
licensee at the close of this inspection period.
c.
Conclusions
In response
to the unexpected
LOP to the PBB-SO4 4160V Class
1E bus on
September
17, 1997,.the control room operations staff responded
in an excellent
manner.
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01 4
Unit 2 Midloo
0 eration
Inade
uate Shutdown Coolin
Flow
1
Ins ection Sco
e 71707
On October 6, 1997, while conducting
a draindown of the Unit 2 RCS to the
midloop condition, operators suspended
the draindown after noticing an
unacceptable
deviation between Channels A and B of the RWLIS. An NRC
inspector observed the evolution.
b.
Observations
and Findin s
Control room operators were conducting
a draindown to midloop condition to
support removal of the SG nozzle dams.
The actual draindown evolution was
controlled by an additional SRO assigned to control only the draindown.
While
conducting the draindown, operators noted
a discrepancy between Channels A and
B of the RWLIS. The discrepancy of approximately 8 inches was discovered while
the wide range level indication was still in use.
The SRO in charge of the draindown
stopped the procedure just prior to entering the midloop condition and requested
that the level discrepancy
be solved before resuming the draindown.
Unit 2 was in
shutdown cooling with Train B containment spray pump in service.
Troubleshooting
the problem determined that the shutdown cooling warmup bypass Valve SIBUV690
was cracked open.
This allowed approximately 400 gpm of shutdown cooling flow
to bypass the core and flow back to the suction of the inservice shutdown cooling
pump.
Since shutdown cooling flow is measured
upstream of the bypass line,
there was no indication to the operators that actual flow to the core was low.
Actual shutdown cooling flow has an effect on water level measurement.
Since
actual shutdown cooling flow was less than indicated flow, this caused the use of
an incorrect error correction factor in determining water level. The use of the
incorrect error correction factor accounted for the difference between
Levels A and
B. At 8 p.m. on October 5, shutdown cooling flow had been lowered to what was
indicated to be just above the Technical Specification (TS) limit. With about 400
gpm of flow bypassing the core, actual flow'to the core dropped to less than the
3,780 gpm required by TS 3/4.4.1.4.2.
This condition was corrected at
approximately noon on October 6, 1997, when the shutdown cooling bypass valve
was fully shut and an operator increased shutdown cooling flow to above the TS
limit. Since this evolution was being conducted
near the end of the outage with a
newly refueled core, the decay heat load was minimal and no adverse affects were
noted due to the lower flow. After resolution of the level indication problem, the
draindown and entry into midloop operation were completed without further
roblems
p
'I
Unit 2 TS 3/4.4.1.4.2 requires that shutdown cooling flow to the core be
maintain'ed greater than 3,780 gpm.
From approximately 8 p.m. on October 5 until
approximately noon on October 6, shutdown cooling flow to the Unit 2 reactor was
less than required.
The failure to maintain greater than 3,780 gpm shutdown
cooling flow to was a violation of TS 3/4.4.1.4.2 (Violation 50-529/9716-01).
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C.
Conclusions
On October-6, 1997, the Unit 2 reactor was drained to the cold midloop condition.
A dedicated
midloop operating crew augmented
the normal operating crew during
the evolution.
During the draindown,
a discrepancy between Channels A and B of
RWLIS was discovered, which was caused
by an open shutdown cooling bypass
valve.
This resulted in less than 3780 gpm of flow through the core, a violation of
TS 3/4.4.1.4.2.
Operator oversight and direction of, the evolution and decisions to
take conservative actions related to the discrepancy observed with reactor level
measurement
were excellent,
Immediate corrective actions were timely.
08
Miscellaneous Operations Issues (92901)
08.1
Closed
LER 50-530 95-002-00:
plant operation in excess of 3800 MW thermal.
This item was described
in NRC Inspection Report 50-528,529,530/95-18
and was
dispositioned
as NCV 50-530/95018-01,
Blowdown System Misalignment Leads To
Operation Above 100'percent.
This item is closed.
08.2
Closed
LER 50-528 95-002-01:
accident analysis failed to consider shutdown
margin.
This item was described
in NRC Inspection Report 50-528,529,530/97-11
and was dispositioned
as a NCV 50-528,529,530/97011-02,
Violation of Criterion
III of Appendix B to 10 CFR Part 50. This item is closed.
08.3
Closed
Violation 50-528 96-16-01:
failure to follow the RCS drain down
procedure.
The inspectors verified the corrective actions described
in the licensee's
response
letter, dated January 3, 1997, to be acceptable
and complete.
No similar
problems were identified.
II. Maintenance
M1
Conduct of Maintenance
M1.1
General Comments on Maintenance Activities
a.
Ins ection Sco
e 62707
The inspectors observed
all or portions of the following work activities:
Clearance 97-01636:
WO 786054:
31 MT-9DG01:
LPSI Flow Control to RC 2A Containment Isolation
Diesel Engine Emergency Generator,
Unit 2
Chemical Passivation
Of Spray Pond Piping, Revision
1
Diesel Engine Surveillance Inspection, Revision 15, Unit 2
Emergency Diesel Generator A, Revision 24, Unit 2
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b.
Observations
and Findin s
The inspectors found the work performed under these activities to be professional
and thorough.
All work observed was performed with the work package present
and in active use.
Technicians were experienced
and knowledgeable of their
assigned tasks.
M1.2
General Comments on Surveillance Activities
a.
Ins ection Sco
e 61726
The inspectors observed
all or portions of the following surveillance activities:
18 Month Surveillance Test Of Diesel Generator
Shutdown Cooling Initiation
RCS and Pressurizer
Heatup and Cooldown Rates 4.4.8.1.1,
4.4.8.2.1
and 4.4.8.2.2.
Mode Change Checklist
b.
Observations
and Findin s
The inspectors found these surveillances were performed acceptably and as
specified by applicable procedures.
M1.3
Conclusions
on Conduct of Maintenance
and Surveillance Activities
Routine maintenance
and surveillance activities were generally conducted
in a
safety conscious manner by knowledgeable
technicians using current procedures.
M2
Maintenance and Material Condition for Facilities and Equipment
M2.1
Unit 2 Containment Closeout Ins ection
62707
On October 10, 1997, the inspectors performed
a containment closeout inspection.
Prior to entry into containment the inspectors reviewed completed
Procedure 40ST-9ZZ09, Containment Cleanliness Inspection, Revision 0. The
procedure performed
a final closeout of containment prior to Mode 4 entry.
A
thorough list of equipment to be left in containment through entry into Mode 3 was
provided to the inspectors.
The inspectors identified small miscellaneous
debris, but
no major items outside of the licensee's list were identified.
Radiation protection
personnel
removed the debris from the containment,
The items were not of
sufficient size or quantity to affect the operability of the containment emergency
No active boric acid leaks were identified.
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Maintenance Procedures
and Documentation
SG Nozzle Dam Installation
Unit 2
Ins ection Sco
e 62707
The inspectors reviewed activities associated
with the SG nozzle dam installation;
Procedures
31MT-9RC48, "SG Nozzle Dam Installation and Removal," Revision 15,
and Procedure
30DP-OWM2, "Housekeeping
and System Cleanliness,"
Revision 1,
and personnel training records for Zone III workers.
In addition, the inspectors
discussed
system cleanliness with maintenance
department managers.
Observations
and Findin s
The inspectors reviewed Procedure 31MT-9RC48 used to install the SG nozzle
dams.
On September
9, 1997, the inspectors observed that the procedure was
detailed and properly performed.
In addition, the inspector reviewed
Procedure
30DP-OWM2 to verify proper FME controls were in place for personnel
and equipment that entered and exited the SG.
The inspector noted that a sticklight
that was used in the nozzle dam installation was not recorded on the Zone III
material and tool access
log for entering and exiting the SG
1 cold leg until
September
17. The inspectors questioned
the individual making the late entry and
the'individual indicated that they observed the sticklight enter and exit the SG
manway during the nozzle dam installation and added the line entry to ensure
completeness
of the log.
The inspectors questioned
the licensee about the FME process for the SG nozzle
dam installation.
The licensee indicated that the FME responsible
person observed
the activity from across
a table on a video monitor and did not have a headset
on
for communicating with personnel entering the SG.
The licensee has since provided
communication improvements for the FME responsible
person. The inspectors
further questioned
the licensee about the adequacy of the location of the FME
responsible
person since the person did not observe and record a sticklight entering
or exiting the SG.
The licensee interviewed the personnel
involved in the SG nozzle
dam installation and identified that the FME responsible
person did not have an
optimal view of the items entering and exiting the SG.
However, in conjunction
with the additional FME trained personnel
present and the procedural controls in the
nozzle dam installation procedure,
proper FME controls were maintained.
The
licensee concluded that the FME responsible
person not observing the sticklight
enter and exit the SG was an isolated event and did not warrant a change to the
FME program.
The inspector agreed with the licensee's conclusions.
The inspectors reviewed the training records of all the personnel that crossed the
Zone III boundary and entered the SGs.
The inspector observed that the training
records for all individuals were current.
The inspectors observed that the
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Procedure 31MT-9RC48 specifically directed the installation and removal of the
sticklight and the nozzle dam installers recalled taking the sticklight into and out of
the SG.
The inspectors concluded that the licensee complied with Procedure
since all material that entered
and exited the SG was observed,
accounted for, and
documented
of the log sheet, although the sticklight was not logged at the time of
the work.
Conclusions
The licensee installed SG nozzle dams in the Unit 2 SG during the Cycle 7 refueling
outage to support eddy current testing of the SG tubes.
The licensee did not
provide the FME responsible
person the viewing point and communication tools to
properly monitor all items entering and exiting the SG Zone III area;
a weakness that
has since been corrected.
However, the licensee's
SG nozzle dam installation
procedure
and FME training provided'o the nozzle dam installers ensured that
acceptable
FME practices were maintained.
Maintenance Staff Knowledge and Performance
Miscalibration of RWLIS Instrumentation
Unit 2
Ins ection Sco
e 61726
On September 8, 1997, the inspectors observed control room and ISC technicians
respond to RWLIS level error indications during draining of the RCS to establish
midloop conditions.
The inspectors examined IRC troubleshooting
activities and
calibration records.
The inspectors
also witnessed the recalibration of the RWLIS
instrumentation.
Observations
and Findin s
During the draining procedure the midloop operations'crew
observed
RWLIS remain
constant at a level above that which was expected.
Indicated RWLIS level was
holding at 103 feet 8 inches with RCS letdown of 130 gpm.
This condition is
normally experienced
at the 103 foot
1 inch level, when RWLIS water level reaches
the top of the RCS hotlegs and the SG tubes begin to drain into the RCS.
The control room staff stopped draining operations
and equalized charging and
letdown flow. The midloop coordinator held a briefing to discuss the disparity
between indicated RWLIS level and where known RWLIS should have been.
was contacted
and reviewed the calibration records of the RWLIS level transmitters.
The midloop coordinator discussed
with the control room staff the possible causes
of the level deviation.
Upon review of the level transmitter calibrations records, lhC
believed that a possible maintenance
and test equipment (MRTE) error could have
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been introduced during the calibrations of the level transmitters in that all four level
transmitters were found to have as-found readings out of tolerance,
and were all
recalibrated with the same MME.
The inspectors accompanied
the ISC technicians into containment
and observed
them recalibrate one of the RWLIS level transmitters,
in accordance
with
Procedure 36MT-2RC03, "Refueling Water Level Indicating System Instrumentation
Calibration-Train A," Revision 6. The transmitter's as-found valUes were found to
be out of tolerance.
The ISC technicians recalibrated
all four level transmitters.
The licensee initiated CRDR 2-7-0301 to document the problem and determine the
root cause and transportability of the error.
The licensee's
CRDR evaluation initiated a human performance evaluation that
determined that the 8 inch RWLIS level deviation was a human performance
error.
In subsequent
efforts to determine the cause of the problem, the technicians who
performed the original calibrations r'ealized they had not opened the level transmitter
cell vent plugs as required by Procedures
36MT-2RC03/04, Steps 4.16.4.4 and
4.18.4.4.
Venting of the transmitter cell would have allowed the draining of water
in the line between the cell and the 3-way valve manifold where the M&TE was
connected.
This condition allowed the instruments to indicate approximately
8 inches high.
The licensee's
initial corrective actions included positive coaching of the IKC
technicians
on procedural compliance and attention to detail, and the issuance of a
newsflash
IS.C communication
t'o section and department
leaders describing the
event. 'The licensee is planning to revise the maintenance
test procedures to
separate
the procedure
steps into two specific actions and add a note in the
procedure to compare readings with other transmitters for calibration comparisons.
The licensee will also add this event into the next Industry Event" Training for IRC.
This licensee-identified
and corrected violation is being treated as a noncited
violation, consistent with Section VII.B.1 of the NRC Enforcement
Policy (50-528/97016-02).
Conclusions
When calibrating the RWLIS detectors to support the Unit 2, Cycle 7, refueling
outage, ISC personnel failed to adhere to procedural guidance.
This resulted in a
non-conservative
eight inch error in reactor water level indication.
This noncited
violation of procedures
represents
poor work practices by the technicians.
The
licensee's corrective actions w'ere sufficiently complete and thorough.
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III. En ineerin
E1
Conduct Of Engineering
E1.1
Shutdown Coolin
S lit Flow Test
Unit 2
a.
Ins ection Sco
e 37551
On September
10, 1997, the inspectors observed the control room operators
and
the Engineering Department perform Procedure 70TP-9PC01, "Temporary Procedure
For Evaluating Cross Tie Between Shutdown Cooling and Spent Pool Cooling,"
Revision OA. The inspectors
also reviewed calculation 13-MC-PC-217, "Shutdown
Cooling System Augmentation of the Fuel Pool Cooling-HX Performance,"
Revision 1, and the associated
10 CFR 50.59 screening
and evaluation.
b.
Observations
and Findin s
The inspectors observed
all or portions of the split flow test conducted to evaluate
the effectiveness of the shutdown cooling (SDC) to the SFP and refueling pool
lineup.
The licensee's
design basis calculation 13-MC-PC-217 questioned
the ability
of the SFPC system to remove heat under specific refueling conditions.
The split
flow test was conducted to collect data needed to evaluate the effectiveness of the
lineup.
The licensee's
UFSAR discusses
the ability of the SDC system to backup the SFPC
system.
During refueling outages
one train of SDC is normally removed from
service for maintenance.
To meet the commitment in the UFSAR, the operating
train of SDC will be required to cool the fuel in the reactor vessel and supplement
the SFPC system.
The licensee's calculation 13-MC-PC-217, Revision 1, indicates
the current SDC and SFPC systems can perform the function of keeping the SPF
temperature below the UFSAR limits.
Temporary Procedure
70PT-9PC01, was conservatively conducted
by the licensee
to validate this alignment and the design calculation.
The results of the split flow
test concluded that the licensee's
engineering calculations were correct.
The
licensee's
10 CFR 50.59 screening
and evaluation was complete and thorough.
The inspectors attended the licensee's sensitive issues briefing. The briefing was
thorough and encouraged
open communications
between all work groups.
C.
Conclusions
The engineering department
performed an accurate calculation and generated
a
good temporary procedure to verify the adequacy of the SDC system to cool the
fuel in the reactor vessel and supplement the SFPC system,
as required in the
UFSAR. Although calculations indicated performance of this test was unnecessary,
-1 1-
the licensee's
decision to verify the calculations through performance of the test
was a good example of conservative plant operations.
IV. Plant Su
ort
R1
Radiological Protection and Chemistry Controls
R1.1
General Comments
71750
The inspectors observed
radiation protection (RP) personnel,
including supervisors,
,routinely touring the radiologically controlled areas.
Licensee personnel working in
radiologically controlled areas exhibited good radiation work practices.
Contaminated
areas and high radiation areas were properly posted.
Area surveys
posted outside rooms were current.
The inspectors checked
a sample of doors,
required to be locked for the purpose of RP, and all were in accordance with
requirements.
The Unit 2, Cycle 7, refueling outage was conducted
during this inspection period.
The licensee had taken a variety of steps to keep radiation exposure to personnel
as
low as reasonably achievable.
The use of extensive planning, remote technology
and dry runs, combined with careful attention to plant operations
and chemistry
control, helped keep radiation doses during the outage to an all time low for the
site.
R4
Staff Knowledge and Performance
R4.1
Reactor Vessel Core Su
ort Barrel
Removal
Unit 2
a.
Ins ection Sco
e 71750
62707
The inspectors reviewed Procedure
31MT-9RC34, "Reactor Vessel Core Support
Barrel Removal and Installation," Revision 0, attended
RP and core barrel prejob
'riefings,
and discussed
the liftwith RP and Maintenance
personnel.
b.
Observations
and Findin s
On September
15, 1997, the inspectors attended
a prejob briefing for the first core
barrel liftfor the 10 year inservice inspection of the reactor vessel.
The briefing
included guidance for communications
(emphasizing
closed loop communications),
contingency actions, and a discussion of previous industry events.
The inspectors performed
a walkdown of containment
and observed the setup for
the evolution.
The licensee positioned several cameras to observe the evolution
from a remote station inside containment
and used telemetric dosimetry to monitor
i
-1 2-
radiation levels.
The licensee performed
a "dry-run" with the personnel involved in
the evolution to verify communication capabilities and proper equipment operation.
On September
17, the inspectors attended
a RP brief for the core barrel removal.
The licensee emphasized
the potential radiological hazards of the job and the
methods that RP would use to control access to containment
and the locked high
radiation areas that this evolution would create.
C.
Conclusions
The licensee removed the Unit 2 core barrel during the Cycle 7 refueling outage for
the 10 year inservice inspection.
The licensee's thorough planning, coordination of
activities, and training of personnel resulted in a successful
removal of the core
support barrel from the reactor vessel with minimal radiation exposure to personnel.
The licensee's activities to ensure that radiation dose rates remained low were
excellent.
V. Mana ement Meetin
s
X1
Exit Meeting Summary
The inspectors presented
the inspection results to members of licensee management
at the conclusion of the inspection on October 15, 1997.
The licensee
acknowledged the findings presented.
The inspectors
asked the licensee whether any material examined during the
inspection should be considered
proprietary.
No proprietary information was
identified.
~ ATTACHMENT 1
PARTIAL LIST OF PERSONS CONTACTED
Licensee
D. Fan, Section Leader, System Engineering
R. Fullmer, Director, Nuclear Assurance
J. Hesser, Director, Design Engineering
and Projects
D. Kanitz, Engineer, Nuclear Regulatory Affairs
A. Krainik, Department Leader, Nuclear Regulatory Affairs
D. Mautdin, Director, Maintenance
T. Radke, Director, Outages
J. Scott, Director, Site Chemistry
M. Shea, Director, Radiation Protection.
D. Smith, Director, Operations
J. Taylor, Unit 3 Operations Department Leader
C. Zell, Senior Engineer, Nuclear Regulatory Affairs
-2-
INSPECTION PROCEDURES USED
37551
60710
61726
62707
71707
71750
92901
Onsite Engineering
Refueling Activities-
Surveillance Observations
Maintenance
Observations
Plant Operations
Plant Support Activities
Plant Operations Follow-up
ITEMS OPENED
CLOSED AND DISCUSSED
~Oened
50-529/97-1 6-01
failure to maintain at least the minimum shutdown cooling
flow required by TS
50-529/97-16-02
miscalibration of RWLIS instrumentation
Closed
50-530/95002-00
LER
plant operation in excess of 3800 MW thermal
50-528/95002-01
LER
accident analysis failed to consider shutdown margin
50-528/96-16-01
failure to follow RCS drain down procedure
50-529/97-16-02
miscalibration of RWLIS instrumentation
II
-3-
LIST OF ACRONYMS USED
CRDR
MME
RWLIS
SFPC
TS
condition report/disposition request
instrumentation
and controls
loss of power
maintenance
and test equipment
radiation protection
refueling water level indication system
spent fuel pool
spent fuel pool cooling
senior reactor operator
Technical Specification
Updated Final Safety Analysis Report
f
i
I