ML18011A529
| ML18011A529 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 07/25/1994 |
| From: | Tedrow J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18011A527 | List: |
| References | |
| 50-400-94-13, NUDOCS 9408090157 | |
| Download: ML18011A529 (24) | |
See also: IR 05000400/1994013
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2100
ATLANTA,GEORGIA 303234199
Report No.:
50-400/94-13
Licensee:
Carolina
Power
and Light Company
P. 0.
Box 1551
Raleigh,
NC 27602
Docket No.:
50-400
Facility Name:
Harris
1
Inspection
Conducted:
June
4 - July 1,
1994
Inspectors:
J.
e
w, Senio
Re ident Inspector
License No.:
Da e Signed
D.
R
rts
Resident
Inspector
Approved by:
H. Christensen,
Acting Chief
Reactor Projects
Branch
1
Division of Reactor Projects
D te
S gned
'!~l>~
Date Signed
SUMMARY
Scope:
This routine inspection
was conducted
by two resident
inspectors
in the areas
of plant operations,
review of nonconformance
reports,
maintenance
observation,
surveillance observation,
design
and testing of modifications,
plant housekeeping,
radiological controls, security, fire protection,
emergency
preparedness,
review of licensee
event reports,
and licensee
action
on previous inspection
items.
Numerous facility tours were conducted
and
facility operations
observed.
Some of these tours
and observations
were
conducted
on backshifts.
Results:
Two violations were identified:
Failure to preplan
non-emergency
work,
paragraph 3.a(2);
Failure to calibrate
a high voltage probe measuring
device,
paragraph 3.b(l).
A non-cited violation regarding the failure to maintain configuration control
of a valve in the high head safety injection system,
paragraph
2.b.
9408090i 57 940725
ADOCK 05000400
2
Deficiencies
were noted in scheduling safety-related
work/testing,
paragraph
3.a(1),
and during the observation of a practice
emergency drill, paragraph
5.e.
The design of the spent fuel pools
and cooling systems
was adequate
and
operation
was satisfactory,
paragraph
5.b(1).
The licensee's
efforts to
minimize radiation exposure
during the annual
spent fuel shipping cask
inspections
were successful,
paragraph
5.b(2).
REPORT DETAILS
1.
Persons
Contacted
2.
Licensee
Employees
- D. Batton,
Manager,
Work Control
D, Braund,
Manager,
Security
- B. Christiansen,
Manager,
Maintenance
- J. Collins, Manager, Training
J.
Dobbs,
Manager,
Outages
- J. Donahue,
General
Manager,
Harris Plant
H.
Hamby,
Manager,
Regulatory Compliance
- D. HcCarthy,
Manager,
Regulatory Affairs
- J. Nevill, Manager,
Technical
Support
- R. Prunty,
Manager,
Licensing
5 Regulatory
Programs
- W. Robinson,
Vice President,
Harris Plant
- W. Seyler,
Manager,
Project
Management
- D. Tibbitts, Manager,
Operations
B. White, Manager,
Environmental
and Radiation Control
- 0. Wilkins, Manager,
Spent
Fuel
M. Worth, Manager,
Onsite Engineering
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
chemistry/radiation
and corporate
personnel.
- Attended exit interview
and initialisms used throughout this report are listed in the
last paragraph.
Operations
'a
~
Plant Operations
(71707)
The plant continued in power operation
(Hode 1) for the duration
of this inspection period.
(1)
Shift Logs and Facility Records
r
The inspector
reviewed records
and discussed
various entries
with operations
personnel
to verify compliance with the
Technical Specifications
(TS)
and the licensee's
administrative procedures.
The following records
were
reviewed:
shift supervisor's
log; control operator's
log;
night order book; equipment
inoperable record; active
clearance
log; grounding device log; temporary modification
log; chemistry daily reports; shift turnover checklist;
and
selected
radwaste
logs.
In addition, the inspector
independently verified clearance
order tagouts.
The inspectors
found the logs to be readable,
well
organized,
and provided sufficient information on plant
status
and events.
Clearance
tagouts
were found to be
properly implemented.
No violations or deviations
were identified.
Facility Tours
and Observations
Throughout the inspection period, facility tours were
conducted
to observe activities in progress.
Some of these
observations
were conducted
during backshifts.
Also, during
this inspection period, licensee
meetings
were attended
by
the inspectors
to observe
planning
and management
activities.
The facility tours
and observations
encompassed
the following areas:
security perimeter fence; control
room;
emergency
diesel
generator building; reactor auxiliary
building; waste processing
building; turbine building; fuel
handling building; emergency
service water building; battery
rooms; electrical
switchgear
rooms;
and the technical
support center.
During these tours,
observations
were
made regarding
monitoring instrumentation
which included equipment
operating status,
electrical
system lineup, reactor
operating
parameters,
and auxiliary equipment operating
parameters.
Indicated parameters
were verified to be in
accordance
with the
TS for the current operational
mode.
The inspectors
also verified that operating shift staffing
was in accordance
with TS requirements
and that control
room
operations
were being conducted
in an orderly and
professional
manner.
In addition,
the inspector
observed
shift turnovers
on various occasions
to verify the
continuity of plant status,
operational
problems,
and other
pertinent plant information during these turnovers.
The
licensee's
performance
in these
areas
was satisfactory.
Since the plant startup
from the refueling outage,
the
inspectors
have noted
increased
seal
leakage
from the "A"
and "B" Charging/Safety
Injection Pumps.
During this
inspection period, licensee
personnel
attempted
to reduce
the seal
leakage
from the "A" CSIP but were only partially
successful.
The "B" CSIP will be worked following
completion of repairs to "A" CSIP.
The excessive
seal
leakage
does not adversely effect
pump operation.
No violations or deviations
were identified.
Review of Nonconformance
Reports
(71707)
Adverse Condition Feedback
Reports
were reviewed to verify the
following:
TS were complied with, corrective actions
and generic
items were identified and items were reported
as required
by
ACFR 94-2263 discussed
an incident involving poor configuration
control which was discovered
by an Auxiliary Operator.
During
performance of rounds
on June
21, the
AO heard flow noise through
the normal miniflow line for the "8" CSIP which was not operating.
The
"C" CSIP Alternate Hiniflow Hanual
Isolation to "8" Header,
unlocked
and turned about
a quarter turn
off of its seat.
Further investigation
by the operator determined
that the valve was required to be locked closed for the existing
operating condition ("C" CSIP in service replacing the "A" pump)
by procedure
Chemical
and Volume Control
System.
The
valve served to maintain train separation
between
the "8" and
"C"
pumps'lternate
miniflow lines when both
pumps were aligned to
start
on
a safety injection signal.
On June
22,
an operator
was
dispatched
to shut
and lock the valve.
The operator
was
successful
in closing the valve,
but flow noise
was still detected
in the line indicating that there
was leakage
past the valve seat.
Following identification of the valve position discrepancy,
several
actions
were taken.
Licensee
personnel
reviewed control
room logs, valve line-ups,
and equipment clearance
records for the
previous
two months to determine
the cause of the valve being in
the incorrect position.
The valve lineup sheets
indicated that
the valve was last checked to be locked shut
on Hay 3,
1994.
The
inspectors
interviewed licensee
personnel
who indicated that valve
was also observed
to be locked shut just days before the
June
21 incident when operators
were at the valve hanging
a
deficiency tag addressing
valve stem leakage.
At the close of the
inspection period, licensee
personnel
had not determined
why the
valve was not in the configuration required
by the operating
procedure.
Licensee
personnel
conducted
in
accordance
with procedure
THH-408, Operability Determination,
which concluded that the degraded
component
could still perform
its intended safety function without any compensatory
actions.
Specifically, it was concluded that since the miniflow lines are
isolated during Safety Injection, seat
leakage
by valve 1CS-750
was not
an immediate safety concern.
Valve leakage
would be
unexpected
during dual
pump operation with the "8" and
"C"
alternate miniflow paths fully pressurized
by their respective
pumps.
For the postulated
scenario of an inadvertent
and main
steamline
break,
any additional valve leakage
under single
pump
operation
would not be detrimental.
Therefore,
the safety
significance of this incident was minor.
Operating
procedure
OP-107 requires
1CS-750 to be locked closed
when the
"C" CSIP is in service replacing the "A" CSIP.
The
position of valve
1CS-750 identified by licensee
personnel
on June
21 is contrary to that requirement
and is considered
to be
a
violation.
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 Enforcement Policy.
Non-cited Violation (400/94-13-01):
Failure to maintain
configuration control for alternate miniflow valve 1CS-750.
Corrective actions for the above incident included issuance
of an
Operations
Night Order,
on July 8, discussing
the event
and
reinforcing the need to check procedures
for configuration
control.
Licensee Action on Previously Identified Operations
Inspection
Findings
(92901)
(Closed) Violation 400/94-05-01:
Failure to implement procedures
adequately.
The inspector
reviewed
and verified completion of the corrective
actions listed in the licensee's
response letter dated April 8,
1994.
The following actions
were accomplished:
~
For the filter backflush evolution, night orders
were
written to emphasize
clear communications
among operating
personnel
during filter backflush evolutions.
Individuals
were counseled,
and operating
procedures
were revised to
specify single point accountability
and control of the
activity.
For the cold weather event,
licensee
personnel
performed
an
engineering
evaluation
which concluded that equipment in the
ESW structures
could operate
properly with air temperatures
as low as
32 degrees
F.
Procedure
AP-301, Adverse Weather
Operation,
was revised to reference
a list of heaters
and
the method to be used to verify proper operation.
Annual
inspections of the heaters
have
been established
and
scheduled for performance prior to cold weather.
Increased
emphasis will be provided
on deficiencies identified by
these corrective actions.
For the wiring identification problem, training was provided
to craft personnel
and to quality control inspectors
on the
requirements
of procedure
EM-003, Termination
and Testing
Wire and Cable.
This training included contractors utilized
for the last refueling outage
and
a provision was
implemented to ensure this training is provided
on
a
recurrent basis.
3.
Maintenance
'a ~
Maintenance
Observation
(62703)
The inspector observed/reviewed
maintenance activities to verify
that correct equipment
clearances
were in effect; work requests
and fire prevention work permits were issued
and
TS requirements
were being followed.
Maintenance
was observed
and work packages
were reviewed for the following maintenance activities:
Repair mechanical
seal
leak on the "A" CSIP, in accordance
with procedure
CH-H0019, Pacific Charging/Safety
Injection
Pump Size 2-1/2"
RL Type IJ Disassembly
and Maintenance.
Preventive
maintenance
on safety
bus lA-SA overcurrent
relays in accordance
with procedure
MPT-E0022,
General
Electric Overcurrent
IFC-53 (Safe
Shutdown)
Relay
Calibration.
Inspect
sump lube oil cooler for the "8" CSIP.
~
Troubleshoot
RCS Flow Loop 3,
Channel II to determine
why
channel failed low, using procedure
HST-I0062,
Reactor
Coolant
Flow Instrument
(F-0435) Calibration.
~
Replace
selector
valve for leaking lube oil duplex filter on
the "B" Emergency
Diesel
Generator
(EDG) in accordance
with
procedure
HPT-M0028,
Emergency Diesel
Generator
Full Flow Filter Inspection
and Cleaning.
~
Remove the turbine driven auxiliary feedwater
pump suction
relief valve
and verify setpoint in accordance
with
procedure
EST-211, Auxiliary Relief Valve Testing.
In general,
the performance of work was satisfactory with proper
documentation of removed
components
and independent verification
of the reinstallation.
(1)
Two ACFRs were generated
concerning the poor scheduling of
emergent
work.
Both ACFRs 94-2224
and 94-2231 discussed
situations
where emergent
work was scheduled
simultaneously
with previously scheduled
work affecting opposite train
components.
Specifically,
ACFR 94-2224 documented that
on
June
13, work was
added to the schedule
which required the
removal of safety-related
air handler
AH-15B from service
while the "A" EDG was
removed from service.
Since this
action would have resulted
in a support
system for the other
train
EDG being unavailable,
both
EDGs would have
been
considered
ACFR 94-2231
documented
that three
days later, while air handler
AH-15B was inoperable,
a
prescheduled
TS surveillance test affecting the "A" train
solid state protection
system could not be performed.
While not documented
in an
ACFR, the inspector
was informed
of another
example of poor scheduling
on June
23.
While
various
"B" train systems,
including Emergency Service
Water,
were out-of-service for a preplanned train outage,
work on valve
which is an "A" train
ESW pump
discharge strainer backflush valve,
was scheduled
and
discussed
in the manager's
morning meeting minutes
as
an
immediate attention
item.
The mechanic working this job
called the control
room and
asked if the valve could be
stroked closed,
rendering the "A" ESW system inoperable.
Permission
was denied thereby avoiding
a TS 3.0.3 entry.
The operators
were diligent in preventing conflicting train
work activities for the two cases
documented
in the above
ACFRs.
The inspectors
have
documented
other
examples of
poor scheduling
in
NRC Inspection
Reports
50-400/94-05
and
50-400/93-21.
Those reports
discussed
the poor scheduling
of maintenance
on heating
and ventilation systems
and
unnecessary
out-of-service times.
During
a review of the shift supervisors
log, the inspector
noted that
on June
29,
1994, priority "E" work had
been
authorized to open the "A" ESW strainer backflush valve
1SW-
20 which had failed closed.
Priority "E" emergency
work
could be authorized to begin prior to planning being
completed
and documented after the fact.
Maintenance
was in
progress
on
a "B" train control
room emergency ventilation
system
component.
Since the service water valve affected
"A" ESW cooled components,
the associated chiller for the
"A" control
room emergency ventilation system
was considered
to be unavailable.
Plant operators
therefore
entered
due to both control
room emergency ventilation systems
being inoperable.
Technical specification 3.0.3 requires
that the plant
be shutdown to hot standby within seven
hours
followed by cold shutdown within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The emergency
work was authorized to avoid the unnecessary
plant transient
which would result from fulfillingthe
TS 3.0.3 action
statement.
Procedure
PLP-710,
Work Management
Process,
Attachment
5, allowed the shift supervisor to initiate
emergency
work whenever
was entered.
The inspector discussed
this activity with licensee
personnel.
The actual
work performed
on this safety-related
valve involved the removal of instrument air tubing from the
top of the valve actuator, reinstalling
a failed air line,
and removing instrument tubing from the associated
solenoid
valve and regulator.
This work succeeded
in opening the
valve and overrode the valve actuator
such that the valve
remained
opened.
During the event review for reportability determination,
licensee
personnel
determined that
was not
applicable for this situation,
and therefore the event
was
not reportable.
The inspector
concluded that the failure of
valve
1SW-20 was actually not
an emergency situation
and
therefore appropriate
preplanning
should
have
been
accomplished.
Failure to properly implement the
requirements
of procedure
PLP-710 to preplan
non-emergency
work is contrary to the requirements
of TS 6.8. l.a and is
considered
to be
a violation.
Violation (400/94-13-02):
Failure to preplan
non-emergency
work on valve
Surveillance Observation
(61726)
Surveillance tests
were observed to verify that approved
procedures
were being used; qualified personnel
were conducting
the tests;
tests
were adequate
to verify equipment operability;
calibrated
equipment
was utilized;
and
TS requirements
were
followed.
The following tests
were observed
and/or data reviewed:
~
Delta T/Tavg Loop (T-0412) Operational
Test
~
HST-I0208
Pressurizer
Level
Loop (L-0459) Operational
Test
~
Neutron Flux Monitoring System Train A (NI-60)
Source
Range Calibration
~
Hain Steamline
Pressure,
Loop
1 (P-0474),
Operational
Test
~
OST-1026
Leakage
Evaluation Daily
Interval
The performance of these
procedures
was generally found to be
satisfactory with proper
use of calibrated test equipment,
necessary
communications
established,
notification/authorization
of control
room personnel,
and knowledgeable
personnel
having
performed the tasks.
(1)
During the performance of procedure
HST-I0071
on June
17,
1994, the inspector
observed
the technicians
measure
the
detector
high voltage
power supply.
Section
7. 1.3 of the
procedure directed the technicians
to connect
a high voltage
probe to the center conductor of the triax connector
and
a
digital voltmeter to the connector outer shield.
The
acceptance
criteria for these
steps listed
784 - 816
VDC for
the high voltage
and 300 - 340
VDC for the loss of high
voltage alarm setpoint.
Actual voltage measured
on the
digital voltmeter was 0,800
VDC and 0.322
VDC respectively
(0 - 20
VDC scale).
The inspector
asked the technicians
about the measured
voltages
and
was informed that the high
voltage probe included
a division ratio of 1000: 1 and that
the voltage readout displayed
on the digital voltmeter was
equivalent to kilovolts.
Licensee
personnel
provided the inspector with the high
voltage probe technical
manual
which confirmed what the
technician
had stated.
The inspector noted that the digital
voltmeter was included in the licensee's
calibration -program
and
a calibration sticker
had. been attached
indicating that
it was within the calibration frequency.
The inspector
asked
about the calibration of the probe since
a calibration
sticker was absent.
Licensee
personnel
stated that the
probe did not receive
a calibration check
on site.
Furthermore,
vendor testing of the probe
was not acceptable
since the vendor did not have
a quality assurance
program
approved
by the licensee.
Failure to utilize a calibrated
high voltage measuring
device during the performance of
surveillance testing
on safety-related
equipment is contrary
to the requirements
of 10 CFR 50 Appendix
B Criterion XII
and is considered
to be
a violation.
Violation (400/94-13-03):
Failure to calibrate
high voltage
probe measuring
device.
Subsequent
to the inspector's
inquiry, licensee
personnel
verified the
1000 to
1 voltage divider of the probe
and
found it to be within manufacturer's
accuracy limits.
The inspectors
reviewed
Nonconservative
Leakage Calculation,
for its potential
impact
on the Harris plant.
The
information notice discussed
a problem identified at another
facility concerning
a nonconservatism
associated
with the
RCS unidentified leakage calculation required
by TS.
This
calculation
was performed considering total
volume changes
in various closed
system tanks; i.e., reactor coolant drain
tank, pressurizer relief tank,
volume control tank.
The
information notice stated that several
valve leakoff lines
associated
with the cold leg accumulators
in the safety
injection system drain into the
RCDT.
Since
RCS 'identified
leakage
was determined
by comparing
volume changes
in the
RCDT with changes
in the
VCT or the pressurizer,
additions
of non-RCS water to the
RCDT could falsely increase
the
identified leakage
value.
This inflated identified leakage
value would result in non-conservative
estimates
since unidentified leakage
was determined
by
subtracting
the identified leakrate
from total system
leakage.
The inspector
reviewed
system drawings
and procedure
OST-1026.
From this review, the inspector discovered that
valve stem leakoff lines from three safety injection system
cold leg accumulator discharge
isolation valves
(1SI-246,
247,
and 248),
and 1SI-354
and
353 in the low head
system,
were connected
to the
RCDT.
Discussions with
licensee
personnel
indicated that
RCS leakage for the Harris
plant was calculated
in the
same
manner
as the subject plant
in the information notice.
The inspector
concluded that the
same potential
nonconservatism
existed for calculating
at Harris.
The inspector
reviewed data
for the current operating cycle and found that combined
unidentified
and identified leakage did not exceed
the
TS
limit for unidentified leakage.
The inspector
concluded
that
no immediate concern existed.
The inspector discussed
this issue with licensee
personnel
who issued
action item CAP-94H0454 to address
the potential
impact of non-RCS valve stem leakoff on
RCS leakage
calculations.
Engineering
Inspector
Followup Item (400/94-13-04):
Follow the
licensee's
activities to address
the impact of non-RCS valve
leakoff on
RCS leakage calculations.
Design, Installation
and Testing of Hodifications
(37551)
Plant
Change
Requests
(PCR) involving the installation of new or
modified systems
were reviewed to verify that the changes
were reviewed
and approved
in accordance
with 10 CFR 50.59, that the changes
were
performed in accordance
with technically adequate
and approved
procedures,
that subsequent
testing
and test results
met approved
acceptance
criteria or deviations
were resolved in an acceptable
manner,
and that appropriate
drawings
and facility procedures
were revised
as
necessary.
In addition,
PCRs documenting
engineering
evaluations
were
also reviewed.
The following modifications and/or testing in progress
was observed:
~ PCR-0420
RTD Bypass Elimination
~ PCR-5308
Safety Injection/Charging
Thermal Stratification
Evaluation
~ PCR-7339
Evaluation of OST-1214
CSIP Oil Cooler Flow Data
a ~
The inspectors
continued to review installation
and testing
documentation
associated
with PCR-0420.
As mentioned in NRC
Report 50-400/94-10,
the response
time testing for the resistance
temperature
detector
(RTD) instrument loop had
been
separated
into
three sections.
Sections
two and three collectively tested
the
response
time from the detector's
input to process
instrument
cabinets
PIC-1,
PIC-2,
and PIC-3, to the opening of the "A" and
"B" reactor trip breakers.
Those two sections
were performed
previously and verified by the inspectors
to meet acceptance
10
criteria.
Section
one of the instrument loop testing,
to
determine
the thermal
response
time of the newly installed
RTDs,
was reviewed during this inspection period.
Procedure
EST-300,
Reactor Trip Response
Time Evaluation,
documented
the testing for
the entire instrument loops
and included the results of the
thermal
response
time testing.
The inspector verified that each
of the
new
RTDs met the thermal
response
time acceptance
criteria
of less
than four seconds.
When the thermal
response
times were
added to the results of the circuit response,
reactor trip breaker
response,
and control rod gripper release
time tests
done
previously, the overall response
time of the
RTD loops
was within
the six seconds
assumed
in the
FSAR chapter
15 accident analysis.
In addition to
RTD response
time testing,
an
RCS hydrostatic test
was required
as
a result of the modification to reactor coolant
pressure
boundary piping.
This test
was conducted
on Nay 9 using
procedure
EPT-159,
ASME Section XI, Article IWB-5000 102 Percent
Hydrostatic Test.
During the test,
RCS pressure
was increased
from the normal operating
pressure
of 2235 psig to approximately
2290 psig,
and held there for four hours.
Licensee
personnel
then
performed
a visual examination of components within the
hydrostatic test
boundary in accordance
with procedure
EST-201,
ASHE System
Pressure
Tests.
The only deficiency noted during the
test
was
a small leak on
a quarter-inch
compression fitting near
valve
A work ticket was initiated and the deficiency was
corrected
as required
by the procedure.
The inspectors
reviewed
completed
copies of both procedures
EPT-159
and
EST-201
and
concluded that this post modification testing for PCR-0420
was
conducted satisfactorily.
A final review of work tickets associated
with installing and
testing the
new
RTDs was conducted
by the inspectors
as well.
The
work tickets covered
implementation of PCR-0420 including the
demolition of the old
removal of main
control
room annunciators,
meters,
and switches;
determinating
and
reterminating of cables
outside the containment building;
and work
associated
with the
PIC cabinets.
The inspectors
concluded that
the overall
implementation of PCR-0420
was satisfactory.
On June
11 during the performance of procedure
OST-1214,
Emergency
Service water System Operability Train A, licensee
personnel
measured
emergency
service water flow to the CSIP oil coolers.
In
the normal
system valve alignment,
the
CSIP oil coolers receive
cooling water flow from both
through isolation
and check valves.
The return flowpath is through isolation valves
to each of the
ESW discharge
During the test,
one
header is idle with the
pump secured
and auxiliary reservoir
discharge
isolation valve closed.
Due to the absence
of installed
instrumentation,
a test rig consisting of a throttling valve,
venturi,
and strap-on flow detector
was utilized.
The test rig
was connected
to spare
one inch pipe instrument connections
located
downstream of the oil coolers.
Normal cooler return lines
11
were isolated to direct flow through the test rig.
The return
flowpath for the test rig was poly-tubing directed to a floor
drain.
Also pressure
indicators
were installed
on one inch drain
lines likewise located
downstream of the coolers.
As
a reference
point, pressure
data
was obtained during normal
system operation
through the coolers.
Utilizing the test rig, flow was throttled
in an attempt to recreate
normal
system operating
pressures.
The
actual
flow obtained
from this measurement
was 28.2
GPH for the
"B" CSIP coolers,
32.4
GPH for the
"C" CSIP coolers,
and 28.8
GPH
for the "A" CSIP coolers.
The licensee
had established
a limit of
30
GPH flow through these
coolers in the procedure to satisfy
technical
manual
recommendations.
Since both the "A" and
"B" CSIP
coolers did not pass sufficient flow the
pumps were declared
and
an engineering
evaluation initiated.
A work
request
was written to inspect the "B" CSIP
Inspection of this cooler revealed
no flow blockage.
Since the
"A" CSIP oil coolers
were inspected
during the recent refueling
outage,
these
coolers
were not reinspected.
Based
upon actual
data collected,
licensee
personnel
calculated
the headloss
of system piping and evaluated
the pressures
obtained
during the test.
The actual test
downstream
pressures
were
58
psig for the "A" CSIP
and
63 psig for the "B" CSIP
as
compared to
normal operating
pressures
of 40 psig.
Using the differential
pressures
actually measured
and the calculated
headloss
of system
piping,
a calculated
flowrate of over 60
GPM was determined to be
present
during normal
system operation
which greatly exceeded
the
30
GPM limit.
The licensee
concluded that sufficient flow was
available to support
pump operation.
The "B" CSIP was declared
The "A" CSIP remained
under
an equipment
clearance for
maintenance.
On June
27 procedure
OST 1215,
Emergency Service
Water System
Operability Train B, was performed which included
a revision to
utilize the calculations
performed for the opposite train test.
This test
was completed unsatisfactory
due to excessive
backpressure
present
downstream of the "A" CSIP oil cooler.
Attempts
by licensee
personnel
to depressurize
the idle
ESW return
thereby reducing the backpressure
on the oil coolers,
were
unsuccessful.
Licensee
personnel
suspect
seat
leakage
past the
normal service water supply valve (ISW-39) to the "A" ESW supply
The inspector
reviewed the licensee's
calculations
and inspected
the test rig utilized for the performance of the test.
The
inspector
also discussed
this situation with licensee
engineering
personnel.
Since the flow to the
CSIP oil coolers
was very
susceptible
to the backpressure
present
at the cooler outlet, the
inspector
asked licensee
personnel
to investigate
the potential
effect that
a single valve failure, consisting of an
ESW auxiliary
reservoir discharge
isolation valve
(1SW-270,
1SW-271) failing
closed,
might have
on CSIP cooling capability.
This failure might
12
produce similar backpressure
conditions
as to those
measured
during the test.
Presently
licensee
personnel
are reviewing the
system design
and are developing
a better method to measure
the
cooler flowrate.
Inspector
Followup Item (400/94-13-05):
Examine the licensee's
design
review of the
ESW system cooling water supply to the
CSIP
oil coolers
and development of a better test method.
On July
1 licensee
personnel split the cooling water flow return
from the
CSIP oil coolers
by closing the "A" CSIP oil cooler
return valve
(1SW-149) to the "B"
ESW discharge
and the "B"
CSIP oil cooler return valve
(1SW-170) to the "A" ESW discharge
The "C" CSIP oil cooler return valve
(1SW-161) for the
"B"
ESW discharge
was also closed
since the
"C" CSIP was in
service replacing the out of service
"A" CSIP.
This system
configuration prevented
the potential single failure discussed
above from disabling all three
CSIPs.
Evaluation
PCR-5308
was performed to analyze
thermocouple
temperatures
measured
on safety injection,
normal charging
and
alternate
charging piping located
between
the
RCS loops
and the
first system
Data from cycle four and cycle five
operations
was evaluated for thermal stratification
and cycling
effects.
The licensee
began monitoring this piping in response
to
Thermal
Stresses
in Piping Connected
to
This matter
was previously reviewed in
NRC Inspection
Report 50-400/92-13
(IFI 400/90-10-04).
To check
for the existence of pipe flaws, licensee
personnel
had previously
non-destructively
examined the three cold leg injection and the
auxiliary charging lines in 1988.
No flaw indications were
identified at that time.
The monitoring program was established
to ensure
adverse
thermal stratification
and cycling conditions
did not occur.
The cycle four and cycle five data
was submitted to the licensee's
nuclear
steam
system supplier for analysis.
The analysis
was
completed
and transmitted to the licensee
on September
21,
1993.
This analysis
determined that several
valves exhibited -leakby with
resultant piping thermal stratification.
measured differential
temperatures
between
the top and bottom of piping consisted of the
following: 90 degrees
F for 1SI-81 (cold leg injection to loop 1),
150 degrees
F for 1SI-82 (cold leg injection loop 2),
90 degrees
F
for 1SI-83 (cold leg injection loop 3),
and
230 degrees
F for
valve
1CS-486 (alternate
charging line).
Data taken at two minute
intervals over
a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period was also evaluated
which indicated
that
no temperature
cycling was occurring.
The cycling of thermal stratification stresses
may lead to pipe
cracking.
Since there
was
no evidence that the temperatures
observed
were cycling, the analysis
concluded that the piping
structural integrity was not jeopardized.
However, the analysis
13
did contain several
recommendations
to ensure
continued
safe
operation.
The recommendations
included continued monitoring of
the piping, utilization of the alternate
charging flowpath as the
normal charging flowpath, repair of the valve seat
leakage,
and
non-destructive
examinations of affected welds near 'the
RCS loop
connections.
The licensee
repaired
valves
and 1SI-52 to
correct seat
leakage
through the alternate
charging line and cold
leg safety injection lines during the recent refueling outage.
In
addition, non-destructive
examinations
were performed
on the
affected welds.
No adverse
indications were identified.
The
licensee
does not plan to alter the normal charging flowpath.
No violations or deviations
were identified.
Plant Support
a ~
Plant Housekeeping
Conditions
(71707)
- Storage of material
and
components,
and cleanliness
conditions of various
areas
throughout
the facility were observed
to determine
whether safety and/or fire
hazards
existed.
b.
Radiological
Protection
Program
(71750)
- Radiation protection
control activities were observed
to verify that these activities
were in conformance with the facility policies
and procedures,
and
in compliance with regulatory requirements.
The inspectors
also
verified that selected
doors which controlled access
to very high
radiation areas
were appropriately locked.
Radiological postings
were likewise spot checked for adequacy.
The inspectors
noted
that progress
had
been
made in reducing the
amount of contaminated
areas
in the plant.
The "A" Residual
Heat
Removal
(RHR) heat
exchanger
and
pump rooms were decontaminated
during this
inspection period improving access
to these
areas.
(I)
The inspectors
reviewed the licensee's
activities for
controlling the specific activity in the spent fuel pools.
This issue
was previously reviewed in NRC Inspection
Reports
50 400/94 04)
93
16
93 02)
92 25)
92
12
92 04)
92 01)
91-22,
91-01,
and 90-21
by both the resident
inspectors
and
regional specialist
inspectors.
As mentioned
in
NRC
Inspection
Report 50-400/92-04,
the licensee
has
abandoned
the attempt to vacuum
up the cobalt
and iron particulates
(crud) from the bottom of the pools
and plans to leave the
crud
on the pool bottom for cleanup later after radioactive
decay.
Since it is not planed to utilize the
"D" spent fuel
pool for fuel storage until the year 2025, licensee
personnel
have
been using this pool
as
a repository for the
highly radioactive
crud which is transported
with the
boiling water reactor fuel assemblies
and settles
to the
bottom of the shipping casks.
In preparation for the annual
inspection of the spent fuel shipping cask,
licensee
personnel
pumped the crud which settled
on the bottom of the
cask to the
"D" pool.
The water in the
"D" pool is normally
segregated
from the other pools
and transfer canals
by
gates.
The inspector discussed
this matter with licensee
personnel
to review the fuel storage
design,
fuel pool cooling, fuel
pool inventory, potential
accident scenarios,
and determine
what precautions
had
been taken to control the crud.
The
inspector questioned
whether the activity within the pools
was still within the limits assumed
in the
FSAR (reference
NRC Inspection
Report 50-400/90-21, violation 400/90-21-04).
Although the
"C" and
"D" spent fuel pools
have cooling and
cleanup piping connected,
the construction of these
systems
has not been
completed
and therefore
these
systems
are not
available.
In addition, the
"C" and
"D" pools
have not been
racked to store
spent fuel.
Long term plans would include
plant modifications to provide these
components
and systems
prior to pool usage.
Temporary pipe caps
have
been
installed in piping connections
to the
"D" pool.
Blank
flanges or valves
seal
the end of unconnected
piping.
The
licensee
plans to install permanent
pipe covers
over the
pool connections this year under modification PCR-6414,
Fuel
Pool
C 5
D Seismic Evaluation.
The "A" and
"B" spent fuel
pools are connected
to
a fuel pool cooling and cleanup
system
and are intermittently operated
to provide cooling
and chemistry control.
Two separate
cooling systems
are
provided.
Piping connections
are located
near the top of
the pools
such that inadvertent
pipe ruptures
would not
uncover the spent fuel being stored.
Sections 3.8.3.6. 1.3
and 3.8.4. 1.3 of the
FSAR discuss
the qualifications of the
spent fuel pools
and the
FHB and state that they are
seismically designed
to withstand the effects of a safe
shutdown earthquake.
Sections
2.4. 12, 2.4. 13,
11. 1.7,
and 15.7.2 of the
discuss
a potential
release
of spent fuel pool water through
a ruptured Refueling Water Storage
Tank
(RWST) to the site
environment.
Specific activity limits in Table
11. 1-7-1
ensure that in the event of this tank rupture, activity
concentrations
in surface water
and ground water would be
below the allowable concentrations
of 10 CFR 20.
Any spent
fuel pool leaks or leaks in connected
piping would be
contained within the seismically qualified
FHB or
WPB and
be
processed
accordingly before release offsite.
Since the
"C"
and
"D" pools are usually isolated
from the rest of the
pools,
a leak path from these
pools would most likely flow
to the
FHB.
Since the
FHB and spent fuel pools are
seismically qualified, failure of these structures
was not
considered
to be credible.
The evaluation
and calculations
for potential
accidents
were previously reviewed in
NRC
Inspection
Report 50-400/92-01.
15
In addition, Table
11. 1-7-1 also listed normal activity
levels which would limit general
area radiation levels to
less
than 2.5 mR/hr.
A review of radiation surveys
performed for these
areas
indicated general
area
dose rates
typically less
than
1 mR/hr at the walkways.
General
area
radiation dose rates
were approximately 2-3 mR/hr near the
"D" pool.
Underwater radiological
surveys of the
interconnecting
canals
indicated decreasing
radiation levels
as the spent fuel
was
moved from the north transfer
canal
through the main transfer
canal to the "A" and "B" pools.
This indicated that the crud was trickling off as the fuel
elements
were moved through the water
and
was mostly
deposited
in the north end of the canals.
Dose rates varied
from 21 R/hr at the bottom middle of the main transfer
canal
up to 621 R/hr in the north transfer
canal
where the
shipping cask basket
was flushed.
Dose rates
measured
at
the bottom of the
"D" pool indicated
a fairly uniform
distribution of crud over the pool bottom with an
approximate
20 R/hr radiation field.
Licensee
personnel
perform rotating weekly checks for pool
leakage
which is trended monthly.
The inspector
reviewed
these trends
and verified that only very slight leakage
has
been
noted thus far (less
than 0.5 gallons per month total
leakage
from all pools).
Routine radiological
surveys of
the
FHB operating floor are
done daily for general
area
radiation
and contamination.
In addition,
continuous
airborne activity devices
and general
area radiation devices
monitor these
areas.
The licensee's
control of items stored in the spent fuel
pools
was last inspected
in NRC Inspection
Report 50-400/91-
23.
The inspector
reviewed the licensee's
latest inventory
of these
items.
In addition to the crud, the licensee
has
stored
an underwater
pump in the
"D" pool.
Filters from
vacuuming the crud were presently stored in the north
transfer
canal
and were very radioactive.
A total of four
inventory items were temporarily stored in the
"C" and
"D"
pools.
Other than spent fuel
no items were stored in the
"A" or "B" pools.
The inspector toured the
FHB with
licensee
personnel
to identify the inventory items.
The inspector requested
to review the latest activity
samples of the pool
and canal water.
The licensee
had not
obtained
samples
from the areas of maximum crud deposition.
Although licensee
personnel
sample the "A" and "B" pools
and
the south transfer
canal
on
a monthly basis,
these
samples
are not representative
of crud concentrations
since these
samples
are taken from the water surface
and the crud has
typically settled to the bottom of the pools
and canals.
The results
from these
samples
were well below the
limits.
No trends of the sample results
were available.
16
The licensee
was unable to quantify the present specific
activity in the fuel pools
and canals.
The limits imposed
by the
FSAR were calculated
assuming
the fuel pools were
filled to capacity
(7298 bundles)
and
an estimated
weight of
crud attached
to each
bundle which disperses
once the
assembly is moved.
The calculation also
assumed
that the
crud was homogeneously
mixed throughout the pools
and
canals.
Since the licensee
has only 1321 bundles presently
stored
in the pools,
the current specific activity levels
should
be within the limits specified in the
FSAR.
In
addition,
since the crud settles
to the bottom of the pools,
the inspector considered it unlikely that sufficient
quantities
would be released
during
a rupture of the
since piping connections
are located
near the top of the
pools.
The inspector concluded that the design of the spent fuel
pools
and cooling systems
was adequate
and that the licensee
was presently operating within the limits imposed
by the
FSAR.
Licensee
management
stated that
a review of crud
controls
was presently
underway
and that the quantification
of existing crud in the pools would be addressed.
Inspector
Followup Item (400/94-13-06):
Review the
licensee's
activities to quantify the
amount of crud in the
spent fuel pools.
The inspector
reviewed the
ALARA job briefings, radiological
surveys,
and interviewed involved health physics
personnel
in the last shipping cask
annual
inspection
in Hay 1994.
During handling of the first cask
and removal of the
internal basket,
approximately
746 millirem of personnel
exposure
was received
by plant personnel.
Teledosimetry
devices
were utilized to avoid exposures
due to direct
monitoring.
A shield wall, consisting of plastic
drums
filled with water,
was erected to create
a low dose
area
near the work area for both the workers
and health physics
personnel
monitoring the job. In addition,
a video tape of
this process
was taken
and reviewed prior to the handling of
the second
cask.
The inspector
watched the video.
Hovement
techniques
were reviewed
by licensee
personnel
and low dose
worker locations reestablished
to reduce
personnel
exposure.
Approximately 416 millirem of exposure
was received during
the second
basket
removal which indicated that the
licensee's
efforts were successful
in reducing the radiation
exposure.
Radiation levels
on the shipping casks
were approximately
2,000
R on contact.
During crud transfer
from the cask to
the
"D" spent fuel pool, general
area radiation levels rose
to approximately
10 mR/hr which decreased
as the crud slowly
settled to the bottom of the pool.
While crud was present
17
at the top of the pool, radiation dose rates
at the pool
surface
were approximately
75 mR/hr.
Security Control
(71750)
- The performance of various shifts of
the security force was observed
in the conduct of daily activities
which included:
protected
and vital area
access
controls;
searching of personnel,
packages,
and vehicles;
badge
issuance
and
retrieval; escorting of visitors; patrols;
and compensatory
posts.
In addition, the inspector
observed
the operational
status of
closed circuit television monitors, the intrusion detection
system
in the central
and secondary
alarm stations,
protected
area
lighting, protected
and vital area barrier integrity,
and the
security organization interface with operations
and maintenance.
Fire Protection
(71750)
- Fire protection activities, staffing and
equipment
were observed
to verify that fire brigade staffing was
appropriate
and that fire alarms,
extinguishing equipment,
actuating controls, fire fighting equipment,
emergency
equipment,
and fire barriers
were operable.
During plant tours,
areas
were
inspected
to ensure fire hazards
did not exist.
Emergency
Preparedness
(71750)
- Emergency
response facilities
were toured to verify availability for emergency operation.
Duty
rosters
were reviewed to verify appropriate staffing levels were
maintained.
As applicable,
emergency
preparedness
exercises
and
drills were observed to verify response
personnel
were adequately
trained.
On June
9,
1994, the inspector
observed
an emergency
preparedness
exercise
designed
to train one of the plant's four emergency
response
teams.
The objective of this exercise
was to demonstrate
for drill controllers/evaluators
that members of the control
room
staff and players stationed
in each of the three
emergency
response facilities could adequately
assess,
mitigate,
and report
accident conditions
as they progressed.
Several
attributes
were
tested
including communications
among
and between
response
facilities, provision of offsite dose
assessment,
and ability to
coordinate
and
augment
manpower
as
needed.
The inspector's
observations
throughout the exercise varied.
The
first three
hours of the scenario
were observed
from the Technical
Support Center.
Initially, command
and control of activities
by
the Site
Emergency Coordinator (lead person
in the
TSC) were weak.
The inspector
observed difficulties in establishing
phone
communications with other facilities, difficulties in finding
phone
numbers,
and
a delay in obtaining the status of an ongoing
repair activity (personnel
airlock door).
Finally, drill
briefings conducted
from the
TSC were not clear
and several
items
had to be repeated
due to audibility problems with the other
response
organizations.
18
The inspector also observed
the activities from the Operational
Support Center.
The inspector did not note
any deficiencies
in
prioritizing work activities,
but did observe
an example of
passiveness
concerning
one of the repair jobs.
When asked
by the
SEC about the status of the repairs
on the personnel
airlock door,
the
Damage Control Coordinator
responded
that
he didn't know
because
he hadn't
seen the auxiliary operators
return to the
operational
support center.
The inspector questioned
the status
of the efforts to fix the "A" CSIP breaker.
Several
personnel
in
the
OSC had to ask around before stating that attempts to replace
a control
power fuse were unsuccessful.
The inspector provided the above observations
to the emergency
preparedness
manager.
The inspector also reviewed
a draft of the
licensee's
own drill critique.
The critique contained
some of the
same
comments
noted
above including the difficulties in
establishing
phone communications
from the TSC,
and problems with
the drill briefings.
The critique did not identify some of the
other deficiencies
noted
above, specifically, the observations
from the
OSC.
The critique evaluated
the performance of the
as being satisfactory
and gave the
DCC credit for quickly
realizing the significance of the personnel
air lock release
path
and acting accordingly.
The inspector
acknowledged that the
June
9 exercise
was
a training scenario
designed to get
new
players qualified for the various
emergency
response
organization
positions.
However,
some of the above observations
involved
personnel
who had already
been qualified for their positions.
The
inspector did note that
command
and control in the
TSC improved
midway through the scenario
when the
SEC position was taken over
by the plant general
manager.
This was also noted in the
licensee's
critique.
At the close of the inspection period, the
licensee
was considering
plans to enhance
the emergency
response
organization
by relocating certain positions
among the response
facilities.
The inspectors
found plant housekeeping
and material condition of
components
to be satisfactory.
The licensee's
adherence
to radiological
controls, security controls, fire protection requirements,
emergency
preparedness
requirements
and
TS requirements
in these
areas
was
satisfactory.
No violations or deviations
were identified.
Review of Licensee
Event Reports
(92700)
The following Licensee
Event Report
was reviewed for potential generic
impact, to detect trends,
and to determine
whether corrective actions
appeared
appropriate.
As applicable,
events that were reported
immediately were reviewed
as they occurred to determine if the
TS were
satisfied.
LERs were reviewed in accordance
with the current
NRC
19
(Closed)
LER 93-04:
This
LER reported
a TS violation regarding
two
control
room ventilation system valves which had not been tested within
their required quarterly surveillance test intervals.
This matter
was
previously discussed
in
NRC Inspection
Report 50-400/94-05.
The
licensee
completed
implementation of PCR 7014, Correct
EBASCO Valve and
Damper Nomenclature
on Control
Room Switches,
the week of June
27,
1994.
The inspector
reviewed the implementation of this modification and
considered it satisfactory.
The valves affected
by the missed
surveillances
were given
new numbers
which are
now distinguishable
from
the dampers that were previously mistaken for them.
Exit Interview (30703)
The inspectors
met with licensee
representatives
(denoted in paragraph
1) at the conclusion of the inspection
on July 1,
1994.
During this
meeting,
the inspectors
summarized
the scope
and findings of the
inspection
as they are detailed in this report, with particular emphasis
on the Violations and Inspector
Follow-up Items addressed
below.
The
licensee
representatives
acknowledged
the inspector's
comments
and did
not identify as proprietary
any of the materials
provided to or reviewed
by the inspectors
during this inspection.
No dissenting
comments
from
the licensee
were received.
Item Number
Descri tion and Reference
400/94-13-01
400/94-13-02
400/94-13-03
400/94-13-04
400/94-13-05
400/94-13-06
Non-cited Violation:
Failure to maintain
configuration control for alternate miniflow valve
paragraph
2.b.
Violation:
Failure to preplan
non-emergency
work on
valve
paragraph
3.a(2).
Violation:
Failure to calibrate
high voltage probe
measuring
device,
paragraph
3.b(1).
Inspector
Followup Item:
Follow the licensee's
activities to address
the impact of non-RCS valve
leakoff on
RCS leakage calculations,
paragraph 3.b(2).
Inspector
Followup Item:
Examine the licensee's
design review of the
ESW system cooling water supply
to the CSIP oil coolers
and development of a better
test method,
paragraph
4.b.
Inspector
Followup Item:
Review the licensee's
activities to quantify the amount of crud in the spent
fuel pools,
paragraph
5.b(1).
and Initialisms
ACFR
-
Adverse Condition Feedback
Report
ALARA -
As
Low As Reasonably
Achievable
ASNE
CFR
CSIP
DCC
EROS
FHB
GPN
IFI
LER
mR
NRC
TS
VDC
WPB
20
Auxiliary Operator
American Society of Hechanical
Engineers
Code of Federal
Regulations
Charging Safety Injection
Pump
Damage Control Coordinator
Emergency Diesel
Generator
Emergency
Response
Data System
Emergency Service Water
Fuel Handling Building
Final Safety Analysis Report
Gallons per Hinute
Inspector
Followup System
Licensee
Event Report
Niliroentgens
Nuclear Regulatory
Commission
Operational
Support Center
Process
Instrument Cabinet
Plant
Change
Request
Pounds
per Square
Inch Gage
Reactor Auxiliary Building
Reactor Coolant Drain Tank
Residual
Heat
Removal
Resistance
Temperature
Detector
Refueling Water Storage
Tank
Safety Injection
Technical Specification
Technical
Support Center
Volume Control Tank
Volts Direct Current
Waste Processing
Building