ML18012A806
| ML18012A806 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 06/09/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18012A804 | List: |
| References | |
| 50-400-97-04, 50-400-97-4, NUDOCS 9706180250 | |
| Download: ML18012A806 (90) | |
See also: IR 05000400/1997004
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket No:
License
No:
50-400
Report
No:
50-400/97-04
Licensee:
Carolina
Power
IE Light (CPImL)
Facility:
Shearon Harris Nuclear
Power Plant, Unit 1
Location:
5413 Shearon
Har ris Road
New Hill, NC 27562
Dates:
March 30
- May 10,
1997
Inspectors:
Approved by:
J. Brady, Senior Resident
Inspector
D. Roberts,
Resident
Inspector
J. Coley, Reactor
Inspector
(Sections
H2.5, H2.6,
and
H2.7)
P. Fillion, Reactor
Inspector
(Sections El, E2,
and
E7)
J.
Lenahan,
Reactor Inspector
(Sections
E1.
E2.
E7,
and
E8)
G. HacDonald,'Project
Engineer
(Section H1.3)
W. Rankin, Senior Project
Manager
(Section Rl)
H. Whitener,
Reactor
Inspector
(Sections Hl.2 and
H2.2)
G. Wiseman,
Reactor
Inspector
(Sections
Fl through
F8)
R. Hall, General
Engineer
(Intern)
H. Shymlock, Chief, Projects
Branch 4
Division of Reactor Projects
Enclosure
2
9'706180250
970609
'DR-
ADQCK 05000400
O.-
EXECUTIVE SUMMARY
Shearon Harris Nuclear
Power Plant,'Unit
1
NRC Inspection Report 50-400/97-04
This integrated
inspection included aspects
of licensee operations,
engineering,
maintenance,
and plant support.
The report covers a'ix-week
period of resident inspection;
in addition, it includes the results of
announced
inspections
by six regional specialists
and
a regional project
engineer.
0 erations
~
Movement of fuel assemblies
during refueling was conducted in an
acceptable
manner.
The licensee
made conservative
decisions
when
problems
arose while moving fuel assemblies,
and the use of specialized
equipment
was beneficial
(Section 01.2).
~
A violation was cited f'r failing to comply with Technical Specification 3.0.4.
Although the violation was licensee-identified,
the licensee's
initial corrective actions
were inadequate
(Section 01.3).
~
Equipment operability, material condition,
and housekeeping
were
acceptable
in all cases
observed
by the inspectors.
No substantive
concerns
were identified during plant walkdowns (Section 02.1).
~
A violation with three
examples of failure to properly implement
corrective actions
was identified.
Two of the examples
involved boron
dilution events
(Sections
04. 1 and 04.2).
Each dilution event
represented
failures of control
room supervision to adequately
supervise
board operators
and properly communicate expectations.
Additionally,
each event pointed out weaknesses
in the management
of reactivity
manipulations.
The third example involved ineffective corrective action
for LER 96-013-01
as evidenced
by recurrence of a Technical Specification 3.0.3 entry during chemical addition to the component
cooling water
system
(Section 08.1).
Maintenance
Maintenance
personnel
were knowledgeable of their assigned
tasks,
approved
procedures
were at the job and followed, work areas
were
controlled and instruments
were calibrated
(Section Hl.l).
Transportation of the Reactor Coolant
Pump motor into containment
was
well executed.
Load paths
were evaluated
and contingencies
for
potential
damage to the Refueling Water Storage
Tank were taken (Section
H1.2) .
Inspection of Emergency Diesel Generator
(EDG) overhaul
met the
requirements of plant procedures,
the vendor manual,
and the vendor
service information memorandum
regarding
10-year
surveillance
and
mai.ntenance activities.
The
EDG work activities were conducted in a
professional
manner
by knowledgeable
personnel.
The engine/component
inspections
performed were thorough
and identified problems
were
conservatively resolved.
Some discrepancies
were noted regarding
documentation of NDE inspections
on, EDG cylinder liners.
(Section Hl.3)
Licensee activities involving the detection
and recovery of foreign
objects in the "A" Steam Generator
were conducted in an acceptable
manner
.
The licensee
performed
an adequate
analysis of the cause of the
foreign objects,
and
a review of the potential for foreign objects
entering the other
(Section Hl.4).
Surveillance procedure
problems were observed in several tests during
the refueling outage including the remote
shutdown
system test
and the
high head safety injection pump test (Sections
H2.1, H2.2,
and H2.3).
A non-cited violation was identified for failing to establish
and
implement adequate
procedures
for using test equipment
on the
"A"
emergency battery.
The use of an improper jumper cable resulted in a
small battery fire (Section H2.4).
Ultrasonic examinations
and interpretation/evaluation/acceptance
of the
reactor
vessel
ISI test results
were conducted in a proficient manner
by
experienced
and knowledgeable
examiners
(Section H2.5).
eddy current activities were well managed.
Program
and
examination procedures
were very good, knowledgeable/skillful
vendor
personnel
were utilized,
and state-of-the-art
examination
equipment
was
used
(Section H2.6).
The licensee's
disposition of the containment liner thickness
issue
was
resolved in a sound technical
manner.
Licensee ultrasonic
examination
personnel
performing the containment liner thickness
measurements
were
resourceful, skillful and very knowledgeable of the ultrasonic method
(Section H2.7).
An apparent violation was identified for an inadequate
10
CFR
50.59'afety
evaluation which ultimately led to the removal of containment
equipment
hatch missile shield protection while it was required to
remain installed
dur ing Hode 3 operations
(Section H3.1).
En ineerin
The licensee's
current design
change control procedures
complied with
the requirements of 10
CFR 50.59,
and
Criterion III (Section El.l).
I
A non-cited violation was identified for failure to implement the
design verification requirements of 10 CFR 50, Appendix B,
Criterion III for safety-related
configuration change Engineering.
Service Requests
completed
between
June 3,
1996,
and February
11,
1997 (Section E1.1).
Hodifications packages
reviewed were of good quality and complied with
design control requirements
(Sections
E1.2 and E1.3).
Plant engineers
conducted
a good indepth evaluation of the containment
lines corrosion problem after it was identified by the inspectors
(Section E1.4).
The licenseee
has established
acceptable
procedures
for the review and
evaluations of NRC information notices
(Section E2.2).
The licensee's
self-assessments
in engineering
were adequate
(Section E7.2).
The Harris Engineering Support Section
was proactive in support of
the plant when emergent
conditions were identified (Sections
E2. 1
and E2.3).
Plant
Su
ort
The radiological controls program was being effectively implemented
overall with good radiation control performance
demonstrated
during
outage conditions (Section Rl.1).
One non-cited violation was identified for failure of radiation workers
to promptly leave
a work area
when their electronic dosimeters
alarmed
(Section R1.2) .
One non-cited violation was identified for failure to tag and label
radioactive material in accordance
with procedure
(Section R1.3).
Contamination control
was effective overall with personnel
contamination
events
on
a favorable reducing trend (Section R1.4).
The ALARA program was effectively controlling total site dose to record
lows for the site (Section Rl.5).
The l-icensee
has
been proactive in the resolution of the Thermo-Lag
issue
(Section F1.2).
Good compliance with plant fire prevention procedures
has resulted in a
low incident of fire within the plant protected
area
(Section F1.3).
There
was not
a significant corrective action maintenance
backlog
associated
with the fire protection systems.
The material condition of
fire protection
components
was good (Section
F2. 1).
A violation of Technical Specification 6.8. l.a was identified for
failing to establish written procedures
to verify the functional
operability of the seismic fire protection check valves that provide
fire protection
and emergency service water
system integrity following a
Safe
Shutdown Earthquake
(Section F2.2).
4
C
Implementation of the fire protection suiveillance
program
has not been
fully effective.
As previously identified in licensee self assessments,
the number of fire protection surveillance
procedures
being performed
within their grace period continued to be excessive
(Section F2.3).
The fire protection program implementing procedures
were good and met
licensee
and
NRC requirements.
The fire fighting pre-fire plans were
satisfactory.
Appropriate fire prevention controls were being applied
to refueling outage activities (Section F3).
The fire brigade organization
and training met the requirements of the
site procedures
(Section F5).
A 1997 assessment
of the facility's fire protection program was
comprehensive
and was effective in identifying fire protection program
performance deficiencies to management.
Planned corrective actions in
response to the audit issues
were acceptable
(Section F7).
4
R~Dt
Summar
of Plant Status
Unit 1 began this inspection period at 100 percent
power.
The unit was
maintained at this power level until April 4,
1997,
when operator s reduced
power in preparation for the refueling outage,
RFO-7.
Operators
manually
tripped the reactor
and the unit entered
Hode 3 (Hot Standby)
on April 5.
Hode 4 (Hot Shutdown)
was entered
on April 5 and operators
continued to reduce
reactor coolant system temperature,
placing the plant in Hode 5 (Cold
Shutdown)
on April 6.
The unit entered
Hode
6 (reactor vessel
head
detensioned
with fuel in the vessel)
for refueling on April 16 and defueling
of the reactor
core was completed
on April 23.
The reactor
vessel
10-year
inspection
was completed during the defueled period.
Node
6 was re-entered
on
Hay 6,
and the unit remained there until Hay 14 when Hode
5 was entered
(reactor
vessel
head fully tensioned with fuel in the vessel).
The unit
remained in Hode
5 for the remainder
of the period.
I. 0
rations
01
Conduct of Operations
Ol. 1
General
Comments
71707
Using Inspection Procedure 71707, the inspectors
conducted
frequent
reviews of ongoing plant operations.
These included reactor
shutdown
and plant cooldown activities conducted in accordance
with procedures
GP-006,
Normal Plant Shutdown from Power Operation to Hot Standby
(Hode
1 to Hode 3), Revision 13;
and GP-007,
Normal Plant Cooldown
(Hode 3 to
Hode 5), Revision 15.
The inspector s also observed all or portions of the following core
alterations
during the use of procedure
GP-009,
Refueling Cavity Fill,
Refueling and Drain of the Refueling Cavity, Revision 13:
Integrated
Reactor
Vessel
Head removal
and installation
Removal
and installation of the Upper Internals
Package
from the
reactor vessel
Removal
and installation of the Lower Internals
Package
from the
reactor vessel to facilitate the 10-year reactor vessel
inspection.
In general,
the conduct of plant operations
was professional
and safety-
conscious.
Technical specification requirements
for equipment
oper ability, instrument
channel
checks,
and plant cooldown rates
were
adhered to for specific activities observed
by the inspectors.
Specific
events
and noteworthy observations
covered
by other procedures
are
detailed in the sections
below.
0
01.2
Fuel
Novement
a.
b.
Ins ection Sco
e
60710
The inspectors
used Inspection
Procedure
60710 to observe the refueling
activities involving fuel assembly
movement.
The inspectors
observed all or portions of the following fuel handling
procedures:
~
FHP-014,
Fuel
and Insert Shuffle Sequence,
Revision 12/1.
~
FHP-020, Refueling Operations,
Revision
13 and 13/1.
~
FHP-025,
HNP Insert Handling Operations,
Revision 6.
Observations
and Findin s
The inspectors
found the fuel movement performed under these activities
to be professional
and thorough.
All work observed
was performed with
the procedures
present
and in active use.
Operators
were experienced
and knowledgeable of their assigned
tasks.
The inspectors
frequently
observed
supervisors
and system engineers
monitoring job progress,
and
quality control personnel
were present
whenever
required by procedure.
Foreign material exclusion areas
were maintained
as required.
The licensee
had problems with three fuel assemblies.
A leaking fuel
rod in assembly
(HA-50) was identified by using in-mast sipping,
a
technique
used to detect the presence of certain radionuclides
along the
length of the fuel assembly.
Assembly HA-50 was not scheduled to be
reloaded in the core and was stored in the spent fuel pool.
Assembly,
HJ-48, did not indicate being fully latched to the fuel handling crane
in the spent fuel handling building.
This was caused
by the indicator
flag not remaining in the full up position when the assembly
was lifted.
After several
attempts
and troubleshooting,
the licensee
used
an
- underwater
camera to verify the assembly
was latched before finally
moving the fuel assembly in the fuel handling building.
This assembly
was subsequently
reloaded in the core with no problems.
Another
,assembly,
HJ-57,
had
a thimble guide tube lodged in the instrument tube
of the assembly.
The licensee
was able to remove the thimble guide tube
using
an underwater
camera
and consultation with fuel vendor
representatives.
Assembly,
HJ-57,
was ultimately reloaded in the core,
but was placed in a location where insertion of a thimble guide tube was
not necessary.
c.
Conclusions
The inspectors
concluded that licensee activities involving the movement
of fuel assemblies
were conducted in an acceptable
manner.
The licensee
made conservative troubleshooting
and contingency decisions
when
problems
arose,
and the use of specialized
equipment
was beneficial.
01.3
Prohibited
Hode
6 Entr
Ins ection Sco
e
71707
b.
On Hay 8,
1997 at 7:18 a.m. the unit entered
Hode 6 (fuel in the reactor
vessel,
reactor vessel
head
removed or detensioned)
to load the core for
cycle 8.
The inspectors
observed the Hode
6 entry from defueled to
determine if procedures
were followed and Technical Specification
Limiting Conditions for Operations
(TS LCOs) were satisfied.
Procedure
GP-009,
Refueling Cavity Fil'1, Refueling
and Drain of the Refueling
Cavity, Revision 13,
was applicable to this evolution.
Observations
and Findin s
The inspectors
observed that the prerequisites
for Hode
6 entry from
defueled
were completed prior to the 6:30 a.m. shift turnover meeting
on
Hay 8,
1997.
The prerequisites
were contained in procedure
GP-009.
A
problem with the IDP-lA-SIII instrument
bus occurred at 6:44 a.m. that
morning which caused the SIII inverter output breaker to trip.
This
caused
equipment served
by that bus to be inoperable
as listed in
Loss of Uninterruptible Power
Supply, Revision 11.
Included
were the fuel handling building (FHB) emergency
exhaust train "A" (E-12
fan)
and the control
room emergency filtration train "A" (R-2A fan)
which were required for Hode 6.
Immediately after the shift turnover,
FHB emergency exhaust train "B" (E-13 fan)
was placed in service to
comply with TS 3.9. 12 since the operable
emergency
power supply
(emergency diesel
generator
B-SB) was on that train.
The shift
operations
crew assumed that entry into the 7-day action statement
for
TS
LCO 3.7.6 for having one train of control
room ventilation inoperable
would allow compliance with that specification.
The shift operations
crew assessed
that Hode 6 could be entered in this condition and that
which prohibits TS Operational
Hode entry while relying on TS
LCO
action statements,
did not apply.
The operations
crew did not reassess
the control
room ventilation equipment failure against the GP-009
Hinimum Equipment List in Attachment
6 for the defueled to Hode
6
change.
Attachment
6 identified that both trains of control
room
ventilation were required for Hode
6 entry.
Hode
6 was subsequently
entered
at 7:18 a.m. with one train of'ontrol
room ventilation
The inspector
observed that at 8: 15 a.m. the work control center
informed the control
room operators that Technical Specification 3.0.4
had been violated due to the plant reliance
on
a TS 3.7.6 action
statement
for
Hode
6 entry.
Condition Report 97-02485
was written to
document this problem.
The inspector
noted that TS 3.9.12 (for FHB
emergency
exhaust)
had
an exemption to TS 3.0.4 while TS 3.7.6 did not.
The licensee
evaluated this failure to comply with TS 3.0.4
and
determined that since it had been missed, it would not make sense to
defuel, wait for restoration of the "A" train control
room ventilation
system to operable,
and then re-enter
Hode 6.
The licensee
continued
with fuel reload
as if TS 3.0.4
had been met,
and continued to rely upon
the TS 3.7.6 action statement
for the inoperable ventilation train.
The
work to repair the SIII instrument
bus was not considered
as
a restraint
to fuel movement.
The inspector
reviewed the TS 3.0.4 Bases section
and discussed
the
significance of TS 3.0.4 with licensee
management.
The TS 3.0.4 basis
state that the intent is to ensure that facility operation is not
initiated with either required equipment or systems
inoperable or other
specified limits being exceeded.
The inspector pointed out that TS 3.0.4 established
the safety level at which
a mode change
can
be made
by
ensuring that the full complement of systems,
equipment,
and components
are operable.
The inspector
also pointed out that TS 3.0.4 does not
have
an action statement,
therefore it must
be complied with.
Even
though
a mistake
had been
made in making the mode change without
complying with TS 3.0.4,
once discovered,
the intent must be complied
with.
After discussing
TS 3.0.4 with the licensee,
the inspector
observed that the licensee
immediately stopped fuel load until all
equipment required for Node
6 was operable.
Re ulator
Si nificance
02
02.1
Technical Specification 3.0.4 requires that entry into an Operational
Hode or other specified condition shall
not be made unless the
conditions for the Limiting Condition for Operation
are met without
reliance
on provisions contained in the Action requirements.
Exceptions
to these
requirements
are stated in the individual specifications.
In
this case
was not met at the time that
Node
6 was entered
from
defueled
and did not contain
an exception to TS 3.0.4.
This was also
contrary to the prerequisites
established
in procedure
GP-009.
This
failure was identified by the licensee,
but not corrected until prompted
by the inspectors.
The failure to comply with TS 3.0.4
and procedure
GP-009 is identified as
a violation (50-400/97-04-01).
Conclusions
The inspectoi
concluded that
a violation of TS 3.0.4
had occurred'.
Although the violation was licensee-identified,
the inspector
concluded
that the licensee's initial corrective action was inadequate.
Operational
Status of Facilities and Equipment
En ineered Safet
Feature
S stem Walkdowns
Ins ection Sco
e
71707
The inspectors
used Inspection
Procedure
71707 to walk down accessible
portions of the following ESF systems
inside reactor
containment during
the refueling outage:
~
Residual
Heat Removal/Low Head Safety Injection System
(FSAR
Section 5.4.7)
~
System
(FSAR Section 10.4.9)
~
Containment
Spray System
(FSAR Section 6.5.2)
~
Component Cooling Water
System
(FSAR Section 9.2
~ 2)
~
Chemical. and Volume Control System
(FSAR Section 9.3.4)
The inspectors
used the current simplified flow diagrams
and equipment
lineup checklist from the operating procedures of each
system to verify
the correct valve and instrument lineup.
Observations
and Findin s
The inspectors
found valve and breaker positions to be in accordance
with the applicable
mode of the unit.
Haterial condition of'he systems
were adequate.
Conclusions
'quipment
operability, material condition,
and housekeeping
were
acceptable
in all cases.
The inspectors identified no substantive
concerns
as
a result of these
walkdowns.
Operator
Knowledge and Performance
.Boron Thermal
Re eneration
S stem
BTRS
Over -Dilution Event
Ins ection Sco
e
71707
The inspectors
reviewed
and evaluated the circumstances
surrounding the
first of two reactor coolant system
which
occurred within two weeks of each other.
The first event occurred
on
Harch 29,
1997, the last day of the previous inspection period,
and was
fully evaluated
during this inspection period to assess
root and
contributing causes
along with corrective actions.
Observations
and Findin s
On Harch 29,
1997, with the plant operating in Hode
1 at 100 percent
power,
a control board operator initiated
a routine
evolution for what was intended to be 2 minutes using the
BTRS in dilute
mode.
This system
uses
a temperature
dependent
ion-exchange
process
via
one of several
demineralizer
beds to raise
or lower boron concentration.
The
BTRS system
reduces
radioactive waste
and offers finer control of
average
RCS temperature
near
the end of the fuel cycle when control rods
are full out and cannot
be relied upon for that function.
The operator
intended to "bump up"
RCS average
temperature
(to match reference
temperature)
just before shift turnover for the oncoming shift.
The operator obtained permission
from the Unit Senior Control Operator
(SCO) to perform the evolution and initiated the dilution at 5:16 a.m.
without notifying anyone else
on shift of his actions.
The operator
was
somehow distracted
and his attentions
were diverted from this evolution.
The
RCS dilution via BTRS continued for thirty minutes until
approximately 5:46 a.m.
when the operator walked by the digital nuclear
instrumentation
drawers which indicated that reactor
power
was at 100.3
percent.
The operator
immediately realized the error,
secured
the
dilution, and informed his management of the incident.
Operations
personnel
generated
Condition Report 97-01348 for this event.
Safet
Si nificance
As
a result of the error,
RCS temperature
increased
approximately 0.2
degrees
Fahrenheit,
and indicated reactor
power increased to 100.3
ercent.
A subsequent
required flux map indicated that no core thermal
imits were exceeded.
was reduced less than
approximately
6 parts per million as determined
by comparing the
Harch 29,
1997
RCS sample results to those of the previous day.
While
these
numbers
represented
only a slight adjustment in core reactivity,
the event itself uncovered
some nonconservative
approaches
to reactivity
management.
First,
BTRS dilution evolutions were not routinely entered
in the control
operator
's logbook by all operators.
These dilutions
were considered to be so frequent
and short in duration that logging was
arbitrary.
Secondly,
the reactor operator did not feel the need to
communicate this reactivity manipulation to the
BOP operator
or other
crew members.
The operator also did not use
a 5-minute timer that was
provided
as
an operator
error reduction tool for this evolution.
Finally, the Unit SCO did not adequately
supervise
the
RO or monitor
reactivity manipulations.
The inspectors
considered
these actions to be
precursors
to potentially more significant reactivity control problems
given different circumstances.
Re ulator
Si nificance
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that
conditions adverse to quality, such
as failures, malfunctions,
deficiencies,
deviations,
defective material
and equipment,
and
nonconformances
are promptly identified and corrected.
This requirement
is further delineated in the licensee's
Corporate Quality Assurance
Program Hanual, Section 12.0, Conditions Adverse to Quality (CATQ) and
Corrective Action, Revision 18.
The licensee's
corrective actions for
recent violations associated
with operator errors included establishing
a Near
Term Improvement Plan with several initiatives for improving
performance.
These corrective actions
were discussed
in the licensee's
response to
NRC Violation 50-400/96-09-01
dated
December
9,
1996.
Among those initiatives were improving consistency
between shifts,
improving communications within operations,
improving utilization of
human error prevention techniques,
and improving human performance in
general.
Licensee
personnel
failed to effectively implement the
previous corrective actions
as exemplified by the
human errors which
lead to the Harch 29 over-dilution event is considered
a violation of
10 CFR 50, Appendix B, Criterion XVI (50-400/97-04-02,
Example 1).
Conclusions
The Harch 29 over-dilution event represented
failures in several
areas
including operations
crew supervision, reactivity management,
and
communications
between operators.
This example
marked
a continuing
trend in human performance
problems which have lead to
a number of LERs
and
NRC violations in late
1996 and early 1997.
One violation was
identified for ineffective implementation of actions to correct this
adverse trend.
04.2
Chemical
and Volume Control
S stem
Boron Dilution Event
a.
Ins ection Sco
e
71707
The inspectors
reviewed
and evaluated
the circumstances
surrounding the
second of two boron dilution events
which occurred within two weeks of
each other.
The second
event involved errors in operations
and
engineering with respect to the design
and operation of the primary
makeup portion of the
CVCS.
The inspectors'eviewed
the licensee's
root cause investigation for this event to determine if root and
contributing causes
and corrective actions
were adequately
addressed.
The engineering contributions to the primary makeup system
problems
were
thoroughly resear ched by the licensee
and are discussed
in report
Section E2.1
~
b.
Observations
and Findin s
On April 7,
1997, with the plant in Cold Shutdown
(Node 5), operators
were preparing to fill the
RCS pressurizer
solid in accordance
with
plant procedures.
Initial RCS boron concentration
was 2340 parts per
million (ppm).
During previous plant outages,
operators
had received
boric acid flow deviation alarms while attempting to maintain adequate
boric acid flow to support the required
RCS boron concentration of 2340
ppm during
RCS fill evolutions.
In preparation for the April 7
evolution, operators
discussed
the potential for the deviation alarms
and
recommended
corrective actions
based
on previous experiences
following indications of'nadequate
boric acid flow from flow control
valve FCV-113A.
A combination of erroneous
assumptions
and poor
communications
between. shift super vision and control board operators
lead to the events that followed.
Se
uence of Events
Following an automatic
makeup to the volume control tank
(VCT) on
April 7,
a boric acid flow deviation alarm occurred which automatically
secured
primary makeup.
This alarm was due to inadequate
makeup flow to the blender, (actual flow did not match the
demand flow of
39 gpm as sensed
by flow transmitter
FT-113).
Operators
responded
by
starting the standby boric acid transfer
pump
(BATP) and restarting
automatic
makeup.
This initial action cleared the flow deviation alarm
but was not an action identified in annunicator
panel
response
procedure
(ALB-006-8-4).
All subsequent
makeups
were to be performed in the
manual
mode,
as instructed to operators
by the shift superintendent.
The April 7 automatic
makeup occur red due to low VCT level
and was
unrelated to the pressurizer fillingevolution.
All subsequent
(manual)
makeups
were
made to support fillingthe pressurizer
to
a solid (water-
filled) condition.
The control board operator initiated
a manual
makeup
to the
VCT at 5:00 a.m on April 8 in accordance
with OP-107,
Chemical
and Volume Control System,
Revision 15, Section 8.7.
Blended primary
makeup/boric acid flow was directed to the top of the
VCT (through the
VCT spray nozzle)
versus the normal flow path to the suction of the
charging/safety injection pumps
(CSIPs).
The operator
chose this
flowpath because of a concern for possible thermal affects
on reactor
coolant
pump seals
(even though this concern
was unfounded since
automatic
makeup normally flows to the suction of the CSIPs
anyway).
Flowing blended primary makeup/boric acid water to the top of the
through the spray nozzle limited boric acid flow to approximately half
of the 39
gpm needed to support the shutdown boron concentration of over
2340
ppm.
Both boric acid flow deviation and total
makeup water flow
deviation alarms
came in but were assumed
by the control board operator
to be expected
due to the manual
mode of operation.
The control board
operator did not refer to the annunciator
panel
response
procedures for
these
alarms
and did not check boric acid or primary makeup water
flow
rates.
The control board operator initiated three subsequent
manual
makeups with similar results
(actual boric acid flow rates of 19-20
gpm
versus the demanded
39 gpm and resultant flow deviation alarms).
The
flow deviation alarms
were dismissed
as
"nuisance alarms".
Two of the
.three subsequent
evolutions were not entered in the control operator's
logbook.
Each of the four manual
makeups during this shift lasted only
minutes at
a time and involved single
BATP operation.
Following shift turnover at 6:54 a.m.
on April 8, the oncoming shift,
who had been briefed on the "nuisance
alarms", initiated its first
manual
makeup to the
same potentiometer
settings for boric acid flow and total
makeup flow that were used
by the
previous shift.
Upon receiving the flow deviation alarms again, the
control operator
referred to the annunciator
panel
response
procedure
and, in an attempt to increase
boric acid flow, started the standby
BATP.
This only increased
boric acid flow from 18 to 20
gpm as limited
by the flow path alignment to the top of the
VCT.
The operator
initiated
a second
manual
makeup to the top of the
VCT a few minutes
later (the first had been secured
due to the
VCT reaching the upper
end
of its operating pressure
band).
Again boric acid flow was .limited and
deviation alarms
came in.
Operators
suspected
that the boric acid
filter was clogged
and directed
an auxiliary operator to bypass it.
With the boric acid filter bypassed,
a third and final manual
make-up
was initiated at 7:40 a.m.,
again with two BATPs running and similar
results.
Following the third (seventh total) manual
makeup,
the April 8 day shift
Unit Senior
Control Operator
made
a decision to return the primary
makeup system to the automatic
mode and that both BATPs would be used.
The rationale
was that the automatic alignment (to CSIP suction versus
the top of VCT) would provide sufficient boric acid addition to keep
up
with the pressurizer fill rate at the higher boron concentrations.
At
this point, another control board operator
raised the concern that the
previous
manual
makeups
might have reduced overall
concentration.
At 8:20 a.m, the plant was declared solid and
an
boron sample
was ordered.
The resultant
boron concentration
was 2283
ppm, or 57
ppm less than the last sample indicated the day before.
This
boron dilution represented
the cumulative result of the seven
manual
makeup operations
performed
between 5:00 a.m and 7:40 a.m on April 8..
Licensee
personnel
generated
Condition Report 97-01582 for this event.
Safet
Si nificance
An important implication of this event
was that operators
inadvertently
inserted positive reactivity into a shutdown reactor.
The safety
consequences
from this event were minimized by the fact that the minimum
required boron concentration to ensure
shutdown margin was 801 ppm.
The
2283
ppm boron concentration
at the end of the dilution event
was more
than twice this amount.
However, this incident,
when coupled with the
example discussed
in report Section 04. 1, represents
a failure of the
licensee's
organization to effectively implement corrective actions or
lessons
learned
from previous events.
These include other industry
events related to reacti,vity management
and events at the Harris plant
related to recent operator
human performance trends.
Another
consequence
of the second shift's actions to start
a second
BATP
.with blended primary makeup/boric acid water discharging to the
spray nozzle
was that the "A" BATP was deadheaded
for several
minutes.
Previous
NRC generic
correspondence
to licensees
Potential
Safety-Related
Pump Loss) cautioned against parallel
pump
operation with both pumps in a piping configuration that did not
preclude
pump-to-pump inter action during miniflow operation.
While the
bulletin and the licensee's
resultant
procedural
cautions
were focused
on restrictions during miniflow operation,
the intent of this guidance
was to prevent the type of operation that occurred
on April 8,
1997.
The inspectors
concluded that
some operations
personnel
did not fully
under stand the intent of the guidance
and that this guidance
was not
clearly stated in oper ating procedure
Revision 15,
or in the
CVCS System Description,
SD-107, Revision 6.
The practice of not.referring to annunciator
panel
response
procedures
following alarms
was the most safety significant factor related to
overall plant operation
revealed
from this event.
This practice
had
been previously discussed
in Inspection Report 50-400/97-300,
in
relation to operator
license examination observations;
Inspection Report
50-400/97-03,
in relation to tr aining staff performance;
and for
Violation 50-400/96-11-01,
Example 2, in relation to heat trace
temperature
monitoring alarms.
Re ulator
Si nificance
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that
conditions adverse to quality, such
as failures, malfunctions,
deficiencies,
deviations.
defective material
and equipment,
and
nonconformances
are promptly identified and corrected.
This .requirement
is further delineated in the licensee's
Corporate Quality Assurance
Program Hanual, Section 12.0, Conditions Adverse to Quality (CATQ) and
10
Cor rective Action, Revision 18.
As discussed
in report'section
04. 1,
the licensee
has initiated extensive corrective actions to address
previous violations associated
with operator
performance.
Although this
event
was licensee identified, the licensee's
implementation of actions
in response
to previous violations was not effective in preventing the
dilution events
discussed
in this report.
The failure to effectively
implement corrective actions to prevent the April 8 dilution event is
considered
the second
example of the violation cited in report section
04. 1 against
10 CFR 50, Appendix B, Criterion XVI (50-400/97-04-02,
Example 2).
Corrective actions
completed during this inspection period included
replacing the valve trim (plug and cage
assembly) for FCV-113A to allow
greater
boric acid flow.
Post-modification testing
had not been
completed at the end of the inspection period.
Additionally, procedure
OP-107 was revised to preclude aligning blended boric acid/primary
makeup water flow to the
VCT spray nozzle
and to provide better
guidance
for responding to the boric acid and total flow deviation alarms.
Conclusions
07
07.1
. The boron dilution event discussed
in this section
was the result of
human performance error s during the operation of the primary makeup
portion of the
CVCS system.
The inspectors
concluded that, prior to the
event,
some operators
did not thoroughly under stand certain limitations
of the system.
This lack of understanding
lead to errors in judgement
and decision making.
The practice of not referring to annunciator
panel
response
procedures
following alarms
was also
a significant factor.
In
addition,
poor communications
between shift supervision
and control
board operators
contributed significantly to the event.
One violation
was identified for failing to effectively implement actions to correct
human performance
problems associated
with previous violations in plant
operations.
guality Assurance in Operations
Licensee Self-Assessment
Activities
40500
During the inspection period, the inspectors
reviewed multiple licensee
self-assessment
activities, including the root causes
for the violation
examples
discussed
in Operations
and Haintenance.
The inspectors
considered
the licensee's
root cause efforts to be thorough for the
boron dilution events
and the TS 3.0.3. entry for CCW.
As discussed
in
report section
H3. 1, the root cause investigation for the containment
hatch missile shield removal did not consider
prior opportunity to
identify or
address this issue.
4
11
Niscel 1aneous
Operations
Issues
(92700,
90712,
92901)
08
08. 1
Closed
LER 50-400/97-007-00:
Component Cooling Water
System
-Technical Specification 3.0.3 Entry
This event
was reported
because
the li'censee
connected
the non-
seismically qualified chemical addition piping section to both trains of
the Component Cooling Water
(CCW) System at the
same time.
LER 96-013-
Ol had reported
the licensee's
discovery that the chemical
addition
section piping was not seismically qualified.
In LER 96-013-01 the
licensee stated in the corrective actions
completed section that the
System Operating Procedure
(OP-145)
was revised
on November 14,
1996 to
ensure that the
CCW trains are separated
prior to and during chemical
addition and that the affected
CCW train during this evolution would be
declared
LER 97-007-00 states that the November
1996
procedure revision did not separate
the trains.
This was discovered
on
January 4,
1997 when operations
personnel
were reviewing the procedure
prior to use.
The procedure
was revised
and was used successfully after
that.
On Harch 25,
1997, this procedure
was used to add chemicals to the
.system
and both trains were connected to the chemical addition piping
section.
A note
had been left in the procedure that stated to ensure
the chemicals
are flushed to the in-service header.
This note did not
make sense
because
the procedure
required the headers to be split prior
to the chemical addition evolution which placed both headers
in ser vice.
This confused the operators
and after stopping the evolution and
discussing this note they decided that the A-train was the previously
in-service
and would be the train that the chemicals
would be
discharged into.
The operators f'rgot that the 8-train had been lined
up to the chemical addition piping to supply flushing water.
Nine
minutes after the alignment
was established
the operators
realized that
they had made
an error,
stopped the evolution,
and realigned the valves.
The
LER listed the cause
as
a combination of not following procedure
convention regarding the use of parenthetical
component
names/numbers
for dual tr ain systems,
inadequate familiarity with the intent of a
procedure
change,
and
a misleading note in the procedure that
contributed to confusion in this scenario.
However, the inspector
concluded that the note concerning
alignment to the inservice
was
what caused the confusion
and that this should have
been
removed by
November
14,
1996 as stated in LER 96-013-01.
The confusion in
following convention
was caused
by trying to comply with the note.
Re ulator
Si nificance
10 CFR 50 Appendix 8 Criterion XVI requires that conditions adverse to
quality be identified and corrected.
For significant conditions adverse
to quality, measures
shall
be taken to determine the cause
and
corrective action taken to preclude repetition.
The licensee
established
corrective actions for a significant condition adverse to
quality in LER 96-013-01.
Those corrective actions
were not adequately
12
implemented in that the procedure
change identified was not adequate
to
. correct the problem, resulting in its recurrence
on March 25,
1997.
This is considered
a violation of 10 CFR 50 Appendix B Criterion XVI for
ineffective corrective action (50-400/97-04-02,
Example 3).
Corrective action for this
LER will be tracked
and reviewed
as part of
the violation.
This
LER is closed.
08.2
Closed
LER 50-400/97-005-00:
Failure to Perform Core Flux Mapping
Following Plant Operation with Reactor
Power Greater than
100 percent.
This event
was reported
due to
a failure to perform core flux mapping
when power was found above
100 percent.
This event is addressed
by
violations 50-400/97-01-03
and 50-400/97-03-01.
Corrective actions will
be reviewed during closure of the violations.
This
LER is closed.
II. Maintenance
H1
Conduct of Haintenance
Hl.l
.General
Comments
62707
The inspectors
observed all or portions of the following work
activities:
96-AHBH1
96-ACMB1
AMPA-001
AGWG-.002
ALCC-001
HST-E0001
FHP-044T
PH-I0009
AEQP-001
Perform CM-M0009, Jamesbury Butterfly Wafer-Sphere
Valves
- 14-20" Disassembly
and Maintenance,
Revision
5,
on Valve 1SW-83.
'erform
CH-M0226, Anchor/Darling Butterfly Valves,
Revision 0,
on Valves
1SW-274 and
Perform HPT-H0091,
Heat Exchanger
Opening/Closing for
NRC Generic Letter 89-13 Inspection,
Revision 4,
on
the Component Cooling Water "B",Heat Exchanger..-
Perform CM-I0002,
AC Limitorque Setup
Check
and
Stroking, Revision 9,
on Valve 1SI-327.
Perform PH-I0043,
Motor Operated
Valve Testing
and
Calibration, Revision 5,
on Valve 1RH-63.
6.9 kv Reactor
Coolant
Pump Circuit Breaker Inspection
and Testing,
Revision 6.
TAVGKDelta T Control Including:
Rod Control,
Power
Hismatch,
Low Power
Feedwater Control,
Steam
Dump
Control,
TREF-TAVG, Rod Control
(speed
and direction),
and Reduced
TAVG Load Follow, Revision 6.
Siemens
S-0253-31/NF991004
Temporary Procedure for
Instrument Thimble Extraction from Fuel Assembly HJ57,
Revision 0.
Incore Instrument Thimble Insertion, Retraction,
Removal,
and Replacement,
Revision 5.
Perform MST-M006, Emergency Diesel Generator
Fuel Oil
Storage
Tank Inspection,
Revision 7.
13
H1.2
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,
procedures
were present
and
followed, work areas
were controlled,
and instrumentation
was
calibrated.
The inspector s frequently observed
supervisors
and system
engineers
monitoring job progress,
and quality control personnel
were
present
whenever required by procedure.
When applicable,
appropriate
radiation control measures
were in place.
Transfer of Heav
load Into Containment
a. Ins ection Sco
e
62707
b.
The inspectors
reviewed
and observed portions of the movement of a
replacement
Pump
(RCP) motor into the containment.
Structural
engineering evaluations
and contingency plans were also
reviewed.
Observations
and Findin s
The licensee
changed
out one of the
RCP motors with a refurbished
motor
as part of their preventative
maintenance
program.
The licensee
plans
to replace the other two RCP motors during the next two refueling
outages
at
a frequency of one per
outage.
The licensee will then
replace
each
RCP motor on
a ten year
cycle at the refueling outage.
This outage,
RCP "B" motor was replaced.
The inspector observed the
replacement
motor lifted by the vendor's
crane
over the refueling water
storage
tank
(RWST) and lowered into the containment
hatch bay.
Transport of the motor
was well controlled.
From the bay, the motor
was
moved into containment
on
a specially constructed rail car,
and was
seismically restrained to the equipment
hatch platform.
The inspectors
reviewed the preparations
for transporting
the
RCP motor.
Since the path exposed the
RWST to potential
damage if the load dropped,
lant systems
were realigned to provide alternate
bor ation sources.
The
oad was over the tank for
a minimal time (20 seconds).
The alternate
path,
over the waste process building, required walking the crane with
the load lifted high and.involved lowering the crane
boom to
a
potentially dangerous
angle to reach the equipment
hatch bay.
The Plant
Nuclear Safety Committee reviewed
and approved the transport path.
The
inspector s determined that prior to the load lift, the crane
was
inspected
and load tested to 125 percent of capacity.
Also, crane
operators
were experienced
and certified.
Conclusions
The inspectors
concluded that transport of the reactor coolant
pump
motor into containment
was well executed.
4
H1.3
14
Observation of RFO-7
Emer enc
Diesel Generator
10-Year'ns ection /
'ver
haul
Ins ection Sco
e
62707
b.
The inspectors
reviewed the work scope for the RFO-7 Emergency Diesel
Generator
(EDG) 10-Year inspection/overhaul,
observed
inspections
and
over haul work in progress
on the "A" and "B" EDGs,
and reviewed
completed
wor k packages
for the "B" EDG.
Training records
were also
reviewed for selected
EDG outage
maintenance
personnel'bservations
and Findin s
Review of RFO-7
EDG Work Sco
e
RFO-7 was the first 10 year inspection/overhaul
scheduled f'r the two
EDGs.
The inspectors
reviewed: Harris Operating License,
Technical
Specifications,
[SER on Operability and Reliability of
Transamerica
Delaval, Inc.
(TDI) EDGs],
TDI EDG Owners Group Generic
Topical Report TDI-EDG-001A, TDI EDG Vendor Manual
MBO, Procedure
PLP-113,
Emergency Diesel
Generator Reliability Program,
Revision 2,
.Cooper Enterprise Service Information Memorandum
(SIH) 402A (Nuclear
Haintenance
Management
System
- Preventive
Maintenance
Program),
and the
RFO-7
EDG work activities.
PLP-113 included the requirements
specified
in the TDI EDG vendor manual
MBO and Cooper Enterprise
SIH 402A.
Observation of EDG Ins ection/Overhaul
Work Activities
The inspectors
witnessed
work activities and inspections in progress
during the overhaul of "A" and "B" EDGs.
Activities were well
coordinated
and controlled and work was done in accordance
with wor k
packages
which were present
at the work location.
The work was
performed by a crew consisting of licensee
shared
resource
personnel
and
vendor maintenance/engineering
personnel
under direction of Harris
maintenance
personnel.
The personnel
were knowledgeable of their
assigned
tasks.
Engine/Component
inspections
performed were thorough
and marginal
components
and parts
were identified f'r disposition.
System engineer
and vendor
engineers
were involved in resolving the issues.
Examples of
marginal parts discovered
and replaced
included the "8" EDG camshafts,
and
a fuel tappet
and jacket water drive gear
on the "A" EDG.
C linder Liner Ins ection
During RF0-7,
6 cylinder liners were replaced
as scheduled
in the "A"
EDG and
10 in the "B" EDG.
These cylinder liners were removed
and
inspected
using pro'cedure
Piston,
Rod and Liner Removal
and Inspection,
Revision 6.
The inspectors
witnessed
wet bath fluorescent
magnetic particle non-destructive
examination
(NDE) inspection of the cylinder liner flange radius area
on
several
cylinder liners removed from the
"A" EDG.
There
was
a 10
CFR 21
report on loose fit liner cracking in this area
and the'inspections
were
..
recommended
by the vendor.
The vendor recommendation
was that for
engines with less than 3000 operating hours,
25 percent of the cylinder
liners should be inspected 'for circumferential
cracking at the top liner
flange radius at the next refueling outage.
All liners should
be
inspected/replaced
prior to 3000 operating hours.
The "A" EDG and the
"B". EDG had approximately
1300
and
1000 operating
hours respectively.
If any liner was detected to have
a continuous circumferential
(360
degree)
indication then that liner would be removed from service
and
additional liner s would be inspected.
Cylinder liners removed from the
Harris
EDGs were replaced with new liners,
no liners were reused.
Upon
initial NDE inspection,
2 liners showed
360 degree indications,
2 showed
partial indications,
and two showed
no indications.
These were
documented
on
NDE data sheets.
Subsequently
the liner radius areas
were
further cleaned
and re-examined.
This additional examination
was not
documented
on the
NDE data sheets.
The licensee
sectioned
several of
the liner s and sent them to the
CP8L metallurgical laboratory for
analysis.
Licensee
system engineering
and the vendor
were involved in
evaluating the liner issue
The CPEL metallurgical laboratory indicated that the liner surface
.conditions
obser ved were machining marks
and grain boundaries
and not
true indications.
The inspectors
observed the samples
at the
metallurgical laboratory and discussed
the issue with laboratory
personnel.
Cooper
Energy Services
Engineering personnel
provided
an
engineering evaluation which indicated that all the liners 'should
be
inspected
by the 3000 hour0.0347 days <br />0.833 hours <br />0.00496 weeks <br />0.00114 months <br /> operating limit.
The inspectors
reviewed the
licensee
EDG overhaul
plan and verified that the liner replacement
would
be complete
by RFO-10 well before the 3000 hour0.0347 days <br />0.833 hours <br />0.00496 weeks <br />0.00114 months <br /> operating limit.
The
evaluation of the
EDG cylinder liner issue
was thorough.
Review of Com leted
Wor k Packa
es
The inspectors
reviewed the following completed work packages
for work.
,
performed
on the "B" EDG: 96-AEDX1, AGXH002, 97-AEBG1, 97-ADRK1,-96-- "
AFZL1, 95-ALLJ1, AEOT001,
and 96-AFZHl. Training records for selected
CP8L shared
resource
personnel
and vendor personnel
were reviewed.
The
inspectors
noted that the instrumentation
used
was in calibration and
that personnel
signing procedure
steps
had been trained for the work
activities.
Work packages
were generally complete
however
a discrepancy
was noted
regarding the
NDE data sheet
for the cylinder liner flange filet radius
inspections
performed
on the liners removed
from the
"B" EDG.
The
description of work performed in work package
96-AEDXl indicated that
the inspections
were performed
on 10 liners removed from the "B" EDG and
that no reportable indications were observed.
The
NDE report was not
contained in the work package
and could not be located.
The
inspector
was interviewed
and the inspectors verified from the
discussion
and his notes that
he had performed the inspection
and that
no reportable indications were found.
This information agreed with the
C.
16
description of work included in the work package.
The licensee
completed
a new data sheet to include in the package.
Conclusions
H1.4
The work scope for the RFO-7
EDG inspection overhaul
met the
requirements
of plant procedures,
the vendor manual,
and the vendor
service information memorandum
regarding 10-year surveillance
and
maintenance activities.
The
EDG wor k activities observed
were conducted
per procedure in a professional
manner
by knowledgeable
personnel.
The
engine/component
inspections
performed were thorough
and identified
problems
were conservatively resolved.
Some discrepancies
were noted
regarding documentation of NDE inspections
on
EDG cylinder liners.
"A" Steam Generator
Forei
n Ob 'ects
a.
Ins ection Sco
e
71707
b.
The inspectors
used Inspection Procedure 71707 to observe the licensee's
activities involving the removal of foreign objects
from the "A" steam
generator.
The inspectors
observed the videotapes of the licensee's
.inspection of the "A" steam generator,
the foreign objects
removed from
the
"A" steam generator,
and the feedwater
where
two bushings
found in the "A" steam generator
originated from.
Observations
and Findin s
A foreign object was detected in the feedwater preheater
section of the
"A" Steam Generator,
during the inservice inspection of the tubes.
A
section of the feedwater line was
removed
and
a camera
was used to
search for foreign objects.
The licensee
found two hinge pin bushing
sets
from feedwater
a piece of duct tape,
and
a
piece of the center rib from the preheater
section of the "A" steam
generator
.
These objects
were removed from the "A" steam generator,
and
the licensee
evaluated
and plugged the tubes
damaged
by the foreign
objects'he
two hinge pin bushing sets
(each consisting of'wo eccentric
held together
by a tack weld) were located
on individual shafts
inside valve 1FW-158 and each held in place by a single tack weld to the
check valve disk.
Each weld was in the feedwater
flow path,
and
had
deteriorated
due to erosion.
Once the welds broke, the bushings
came
off their respective shafts
and entered the "A" steam generator
through
the main feedwater nozzle.
All three of the feedwater
(1FW-158,
and
1FW-276) were inspected
and refurbished using
new
The bushings
were attached to the disk using several
welds of
increased
size in lieu of the original single tack weld method.
Parts of the "A" steam generator
preheater
ribs around the inconel
target plate were found to be eroded.
The licensee
documented
the
erosion of the center
ribs (upper
and lower)
and the two side ribs of
the "A" steam generator
preheater
region in Condition Report
(CR)
17
, 97-02600.
The steam generators'endor
was evaluating their condition
for operability at the end of the inspection period.
c.
Conclusions
The inspectors
concluded that licensee activities involving the
detection
and recovery of foreign objects in ihe "A" Steam Generator
were conducted in an acceptable
manner
.
The licensee
performed
an
adequate
analysis of the cause of the foreign objects,
and
a review of
the potential
for foreign objects entering the other steam generators.
The licensee
was evaluating the operability of the "A" steam generator
for the degraded
preheater
condition at the end of the inspection
period.
H2
Maintenance
and Material Condition of Facilities and Equipment
M2.1
Surveillance Observation
a.
Ins ection Sco
e
61726
The inspectors
observed all or portions of the following surveillance
tests:
OST-1033, Daily Surveillance
Requirements
Daily Interval,
Revision 12.
OST-1091,
Containment Closure Test Weekly Interval During Core
Alterations and Movement of Irradiated
Fuel Inside Containment,
Revision 4.
OST-1801,
ECCS Throttle Valve,
CSIP and Check Valve Verification,
Revisions
10, 10/1,
and 10/4.
OST-1824,
1B-SB Emergency Diesel Generator Operability Test,
Revision 11/1.
EST-209,
Type
B Local Leak Rate Tests,
Revision 9.
HST-M0006,
Fuel Oil Tank Inspection,
Revision 7.
b.
Observations
and Findin s
The inspector
found that the testing
was adequately
performed.
During
the loss of offsite power and safety injection actuation testing
(procedure
OST-1824), plant equipment
responded
as expected.
Some of
.
the outage-related
surveillance
procedures
required temporary
changes
either immediately prior to or during their performances.
The changes
were either technical or administrative in nature,
but indicated that
some of the test conditions
or requirements
had not been fully thought
out during the procedure
development
and review stages.
Specific
problems with certain surveillance tests
are discussed
in sections
H2.2
and M2.3 below.
Conclusions
18
M2.2
The sur veillance performances
were adeq'uately
conducted.
However,
many
of the surveillance test procedures
required temporary
changes
immediately prior to or during their performance indicating that many of
the test conditions or requirements
had not been thoroughly examined
during the procedure
development
and review stages.
The deficiencies
were identified by licensee
personnel
and documented in condition
reports.
Problems with Remote
Shutdown
S stem Test Procedure
a.
Ins ection Sco
e
62700
b.
The inspectors
reviewed
and observed portions of Operations Surveillance
Test
OST- 1813,
Remote
Shutdown System Operability, Revision 7/4..
Observations
and Findin s
E
Subsequent
to the test the licensee
issued
a condition report
(CR)
97-01890
on anomalies of the test.
Fifteen recommendations
were
made to
improve the test consisting mostly of procedure
changes to identify
expected
equipment
responses
and improve test
sequences.
OST-1813,
an 18-month
(outage) surveillance test,
was performed to
verify the ability to control plant cooldown from outside the main
.control
room.
Operability of transfer
switches,
monitoring
instrumentation
and annunciators
were verified as required by Technical Specification 4.3.3.5.2.
The inspectors
observed the pre-briefing,
portions of Section 7.2 Test
B:
NNS Transfer
Panel
1A-SA and Auxiliary
Transfer
Panel
and portions of Section 7.3 Test
C: Transfer
Panel
1B.-SB and Auxiliary Transfer
Panel
Observations
were
made from
the transfer panels,
the auxiliary transfer panels,
and the auxiliary
control panel.
The inspectors
noted that
an approved,
continuous
use
procedure
was present
and followed by the test personnel.
Communications
were established
between the control
room, auxiliary
control panel,
the auxiliary transfer panels,
and the transfer
panels.
The steps
were performed in sequence
at the
command of the test
director,
and the results
recorded
and evaluated.
The inspectors
noted that
some events
such
as equipment starts
and
alarms
were not anticipated
as the transfers
were made.
The
- inspectors
considered that the procedure
caused
a number of unnecessary
delays.
In one case,
upon the initiation of transfer of the
SSPS,
alarms
(Low Pressurizer
Pressure
SI and
Low Steam Line
Pressure
SI) were unexpectedly
received.
The licensee
stopped the test
and investigated the cause of the alarms.
The alarms
were determined to
be valid but were not identified as expected
by the procedure.
4
19
Conclusions
As
a result of the procedure
problems,
the test performance
was
considered
weak.
This test
has
been performed at each of the previous
six outages
and procedure
problems still existed.
Pr'oblems with Hi h 'Head Safet
In 'ection
S stem Test
Ins ection Sco
e
61726
The inspector
observed portions of OST-1801,
ECCS Throttle Valve, CSIP,
and Check Valve Verification, 18-Honth Interval,
Node 6, Revision 10.
Observations
and Findin s
The inspectors
observed
operators
perform Section 7.3 of OST-1801,
which
established
a differential
pressure
for the "B" charging/safety
injection pump (CSIP) to setup for collecting pump performance
data.
During the test, after operators
started the
pump and throttled the
discharge isolation valve to obtain the desired differential pressure,
the pressure
exceeded
the allowable band by 47 psid.
The pump was
secured
and the procedure
reviewed to determine if there
was
a problem
with the system alignment.
Plant personnel
discovered that the'B" CSIP
was aligned to the alternate
cold leg injection path for this test which
was
a different alignment than
had been specified in previous procedure
revisions.
The procedure
was revised to incorporate the normal flow path through
the boron injection tank (BIT) and when the test
was subsequently
run,
the
pump performance
data
was still outside the acceptance criteria.
The pump was again secured
and troubleshooting
began.
Plant personnel
determined that the seal injection flow path from the CSIPs
was not in
service,
another
anomaly that was different from the previous revisions
of the procedure.
The procedure
was again
changed
and the test rerun
with similar ly unacceptable
results.
The procedure
went through four
temporary changes
before the test data
(which was still outside the
acceptance criteria range established
in the procedure)
was presented
to
engineering for further. evaluation.
Licensee
personnel
later determined that the pump's data matched the
test performance
curve with negligible degradation
indicated, that the
pump's operability was unaffected,
and that the procedural
acceptance
criteria was erroneous
(for either of the flow paths).
Licensee
personnel
later informed the inspector that the flow and differential
pressure criteria specified in the test procedure
was the
same criteria
established
in the procedure
during the previous refueling outage
and
that test results then exceeded
the allowable range
as well.
Conclusions
The inspector
concluded that although the licensee's
actions to evaluate
the data against the
pump performance
curve for operability before
H2.4
20
making any changes to the system flow characteristics
were commendable,
the licensee's
surveillance
procedure
review process
was deficient to
not have identified the erroneous criteria during or following the
previous outage's
performance of OST-1801.
Safet
Batter
Fire Durin
Five-Year Dischar
e Test
Ins ection Sco
e
61726
b.
The inspectors
reviewed circumstances
surrounding
a small fire on the
1A-SA emergency battery during
a discharge
performance test
on
April 28,
1997.
The inspectors
assessed
licensee
performance errors
that led to the event
and observed
subsequent
reperformance of the test
to verify that the proper corrective actions
had been
implemented.
Observations
and Findin s
On April 28,
1997,
maintenance
technicians
were per forming procedure
HST-E0013,
lE Battery Performance
Test,
Revision
6 for the 1A-SA
emergency battery.
This procedure
implemented Technical Specification
Surveillance
Requirement 4.8.2.1.e.
by verifying every five years that
the emergency batteries'apacities
were at least
80 percent of the
manufacturer's
rating when subjected to a performance
discharge test.
About one hour into the test,
the technicians,
who were sitting outside
the battery
room monitoring test parameters
on
a computer,
smelled
smoke
coming from the room.
Upon entry, they discovered
small
flames coming
from a jumper cable attached to the number
1 battery cell.
A technician
extinguished the fire with a carbon dioxide extinguisher while another
notified the main control
room who then sounded
an alarm and dispatched
the plant fire brigade to the scene.
The inspectors
arrived at the battery room within minutes of the fire
and noted that minimal
damage
had occurred.
The top plastic cover of
the
number
1 cell was burned through in an approximated
two square
inch
area
due to hot melted plastic insulation from the jumper cable that
had
been attached to it.
The number
1 cell was the only one (of 60 total)
that was damaged.
The discharge test
had been terminated
and
technicians
had secured
the test equipment.
The damaged cell
was later
replaced
and the discharge test
was rerun the next day after the battery
was recharged.
The inspectors
learned through discussions
with the technicians that the
wrong jumper cable
had been
used to connect the load unit to the
battery.
Instead of using the parallel
conductor
1/0 cables
(with a
mechanical
bolted connection)
which had been specifically designed
for
this test,
the technician
connected
a single conductor
1/0 cable which
used
a standard alligator-style clamp-on connection.
The combined
effect of using
a single conductor
cable with a questionable
connection
to carry 298
amps resulted in the jumper cable. plastic insulation
heating
up excessively,
which caused
the fire.
The single conductor
was
usually used for another (lesser
18-month surveillance test.
The five-year test
had been prebriefed the day before,
and the
21
technician performing the test
knew which cable to use,
but made
a'ognitive
error while connecting the load unit to the battery.
The
procedure
did not specify which of the two jumper cable types to use.
Prior to reperforming the test,
HST-E0013 was revised to include
cautions to use the parallel
conductor cables.
The inspector
observed
the retest
and verified that battery test acceptance
criteria were
satisfied.
The inspector considered
licensee
personnel
actions to
revise this procedure to specify the parallel conductor cables to be
appropriate.
Technical Specification 6.8.1.a.
Appendix A,
Section B.b.(l)(q), require written procedures to be established,
implemented,
and maintained covering emergency
power tests.
The failure
to adequately establish
and implement procedural
guidance for using the
correct test equipment for the 1A-SA Emergency Battery was contrary to
this requirement
and is considered
a violation.
This licensee-
identified and corrected violation is being treated
as
a Non-Cited
Violation, consistent with Section VII.B.1 of the
(NCV 50-400/97-04-03).
Conclusions
A small fire resulted
from using improper cables to test the 1A-SA
emergency battery.
The safety consequences
from the fire were minimal
in terms of plant equipment
damage
and personnel
safety.
One Non-Cited
Violation was identified.
Observation of Inservice Ins ection
Work Activities For the
Reactor
Vessel
Ins ection Sco
e
73753
The inspector
reviewed examination procedures,
vessel
scan plans,
programmed calibration setup data,
examiner certifications,
and observed
examination/evaluation
activities for the first 10-year interval
ultrasonic examinations of the Shearon Harris Reactor
Vessel.
See
NRC
Inspection Report
No. 50-400/97-03 for a programmatic review of the
first 10-year
inservice inspection interval program.
Observations
and Findin s
Shearon Harris started
commercial
operation
on Hay 2,
1987; therefore,
the April 1997 refueling outage is the final outage of the first 10-year
ISI Inspection Interval.
One major inspection required for completion
of the first ISI interval is the volumetric examination of the Reactor
Pressure
Vessel
(RPV) and the attachment
piping welds.
The vessel
examinations
were conducted
by Southwest
Research Institute
(SwRI) and
selected
examinations
were witnessed
by the inspector during the
refueling outage
(RFO-7).
The 1983 Edition with Summer
1983 Addenda
(83S83) is the
ASNE BSPV Code,
Section XI "Code-of-Record" for the first
10-year inspection interval.
22
The inspector
reviewed the ISI outage examination plan, 'the vessel
scan
plan,
programmed calibration setup parameters,
examiner certification
records
and the following ultrasonic examination/operation
procedures
to
determine
whether
the procedural
content,
technical instructions
and
'erification
documentation
were adequate:
SHH-AUT14, Automated Ultrasonic Inside Surface Examination of
Pressure
Piping Welds, Revision
1
~
SHH-AUT15, Automated Inside Surface Examination of Ferritic
Vessels
Greater than 4.0 Inches in Thickness,
Revision
1
~
SwRI-AUT2, Automated Inside Surface
Examination Indication
Resolution,
Revision. 10
SwRI-AUT5, Southwest
Research
Institute
PaR Device and Attachments
Operation,
Revision 4
~
SwRI-AUT7, Southwest
Research
Institute
PaR Device Assembly,
Revision 4
SwRI-AUT8, Southwest
Research
Institute
PaR Device Calibration,
Revision
3
~
SwRI-AUT34, Southwest
Research
Institute
PaR Device Checkout,
Revision
3
~
SwRI-AUT36, Checkout
and operation of the 8-channel
Enhanced
Data
Acquisition System,
Revision
0
~
SwRI-AUT38, Automated Ultrasonic System Performance Verification,
Revision
1
~
SwRI-EDAS2,
Enhanced
Data Acquisition System-II Performance
Verification Procedure
(Test Plan), Revision 3
~
SwRI-PDI-AUTl, Automatic Inside Surface Ultrasonic Examination of
Ferritic Vessel
Wall Greater than 4.0 Inches in Thickness,
Revision
2
~
SwRI-PDI-AUT2, Automated Inside Surface Ultrasonic Flaw Evaluation
and Sizing, Revision
2
In addition to the above reviews, the inspector
analyzed examination
data for the following welds concurrently with the
SwRI Level III
'nalyst to determine if the examiner
was knowledgeable of the procedure
requirements
and whether
examination results
were recorded
as specified
in the ISI program
and in the nondestructive
examination
(NDE)
procedures:
~
Outlet Nozzle to Shell
9 25
, Weld No. RV-NOZ-AO-N-06
~
Outlet Nozzle to Shell 9 265',
Weld No.
RV-NOZ-BO-N-02
23
Meridional Weld 8 165',
Weld No.
MHW-RV-14
Meridional Weld 8 285',
Weld No.
MHW-RV-12
Meridional Weld 8 345',
Weld No. MHW-RV-ll
Intermediate
Shell to Lower Shell
Weld No.
CSW-RV-03
Outlet Nozzle to Shell
8 145',
Weld No. RV-NOZ-CO-N-04
Meridional Weld 8 45',
Weld No.
MHW-RV-16
Conclusions
Ultrasonic examinations
witnessed
by the inspector,
and interpretation
/evaluation/acceptance
of the test results
were conducted in a
proficient manner
by experienced
and knowledgeable
examiners.
Edd
Current Examination
and Data Evaluation
Activities
Ins ection Sco
e
73753
and 50002
The inspector
reviewed the licensee's
eddy current
program
and examination procedures,
examiner certification records,
and
observed site resolution analysts
evaluating
eddy current data.
The
site resolution group analysts
resolved differences
encountered
in
interpretation of data
from the first eddy current data review group
made
up with a combination of Duke and ASEA, Brown, Boveri
(ABB)
analysts
and located at the McGuire Nuclear Plant
and the 2nd eddy
current data review group performed by Framatone
Technologies in
Lynchburg, Virginia.
Observations
and Findin s
During RF0-7, the licensee
had planned to perform
a total of 18,948 eddy
current examinations in the three Shearon Harris Steam Generators.
The
examinations
were conducted
using
a combination of bobbin and Plus Point
coil probes.
The examinations
performed with the Plus Point probe
was
a
new addition to the technology used by the licensee to properly identify
discontinuities in areas
such
as the top of tubesheet
on the hot leg,
rows
1 thru 3 U-behds,
special interest
areas,
and the preheater
expansion
zone for steam generator
A only.
As a result of using the
plus point probe, the licensee
also expected to plug
a higher number of
tubes this outage.
The inspector
examined the licensee's
eddy current
activities by reviewing the procedures listed below:
Carolina
Power
and Light Company
(CP8L) Steam Generator Strategic
Plan,
"Harris Nuclear Plant Strategic Plan," Revision
0
CPSL Procedure
PLP-651,
Program,
Revision
0
CP&L Procedure
EST-216,
Tube Indication Tracking
and Reporting Procedure,
Revision
5
~
CP&L Procedure
HNP-100-005,
Eddy Current
Interpretation Guidelines,
Revision
1
In addition, the inspector
reviewed all examiner certification records
and observed
two resolution group analysts
perform their analyses
of the
eddy current data.
During the eddy current examinations
on "A" Steam
Generator,
foreign objects
were discovered in the preheat
area
below the
feedwater inlet adjacent to the
Row 49,
Column 59 tube.
These
items
were subsequently
removed (report section H1.4).
At the conclusion of
the inspection,
the licensee
was also predicting that approximately 28
tubes
would have to be plugged this inspection.
This was
a much higher
number than normally plugged during previous outages.
However, it
reflected the improvements in inspection technology used this outage for
the detection
and evaluation of eddy current indications.
Discussions
with licensee
cognizant engineers
and vendor
analyst 'personnel
indicated
that these individuals were well-trained,
knowledgeable,
and dedicated.
c.
Conclusions
eddy current activities were well-managed.
Program
and
examination procedures
were very good, knowledgeable/skillful
vendor
personnel
were utilized,
and state-of-the-art
examination equipment
was
used.
H2.7
Ultrasonic Examination of Containment
Liner
a.
Ins ection Sco
e
57080
The inspector
observed ultrasonic thickness
examinations of the
containment liner below the top surface of the concrete floor slab at
the 0'nd 85'zimuth.
This inspection
was performed to investigate
corrosion noted
on the liner during walkdown visual inspections
documented in Condition Report 97-01880.
The engineering evaluation of
this issue is addressed
in section E1.4 of this inspection report.
b.
Observations
and Findin s
The following account of the inspection
observed
by the inspector
was
written in part,
by the Level III ultrasonic examiner
who developed the
techniques
used to acquire the containment liner measurements.
"As part of resolution of potential
containment liner corrosion, it was
deemed
necessary to perform ultrasonic thickness testing
(UT-T) of the
liner below the 221-foot floor elevation.
Because of the narrow gap
where the Ethafoam
had been
removed
between the containment liner
and
the concrete floor slab
(1 inch
- 5/8 inch range),
conventional direct
contact ultrasonic thickness testing with an inspector's
hand
on the
transducer
could not be done.
Thus, it was necessary
to devise
an
extension
piece which could be used to position the transducer
down in
the gap and in suitable contact with the liner surface to obtain the
thickness
measurements.
25
The transducer
extension
was devised
by mounting
a select
UT transduc'er
on the end of an approximately 5i-foot length of i inch x 1 inch flat
metal bar stock.
The actual transducer
mounting location on the bar was
machined to form a depression
with a gradual
taper
so 'as to somewhat
'ecess
the transducer
body and it's coaxial cable connection in the
bar,
thereby reducing the overall thickness
dimension of the extension piece.
UT couplant
was delivered to the transducer
face area
by small plastic
tubing connected to a plastic
hand syringe.
Index marks were
made
on
the bar at six inch intervals measured
from the transducer
centerline to
facilitate positioning the 'transducer to obtain thickness
measurements
at six inch intervals
down the liner from the floor level.
To'obtain thickness
measurements,
the extension
was lowered down into
the gap to the first measurement
position at the bottom, the couplant
syringe
pumped couplant to the transducer
face area
and the bar
positioned
so that the transducer
face was in contact with the liner
plate surface.
For each oi the subsequent
thickness
measurements,
the
bar
was raised to the next 6 inch index mark on the bar was at floor
level
and the operation
repeated.
Thickness
measurements
of the liner below 221-foot floor elevation using
the extension
process
were taken at two containment
azimuth locations:
355'zimuth
(general
referred to as the zero degree
azimuth)
and 85'
azimuth (general
referred to as the 90'zimuth).
The nominal thickness of the containment liner was
.375 inch.
The
minimum UT thickness
reading obtained at the 0'zimuth was
.401 inch.
The minimum UT thickness
reading obtained at the 85'zimuth
was
.403
inch.
C.
Conclusions
The inspector considered
the licensee disposition of the containment
liner thickness
issue
documented in Condition Report 97-01880, to have
been resolved in a sound technical
manner.
Licensee ultrasonic
examination personnel
who performed the containment liner thickness
measurements
were resourceful, skillful and very knowledgeable.
Haintenance
Procedures
and Documentation
H3.1
Containment
E ui ment Hatch Hissile Shield Removal
a.
Sco
e
37551
The inspector
reviewed the licensee's
investigation
and actions related
to a problem found while removing the containment
equipment
hatch
missile shields.
Condition Report 97-01499
was written to address this
issue.
The inspector
reviewed procedure
CH-H0100, Containment
Equipment
Hatch Removal
and Replacement,
Revision
6 to determine whether the
procedure
allowed removal of the missile shields in Hode 3.
The
inspector
reviewed the
10
CFR 50.59 safety evaluation screen,
performed
as Attachment
1 to procedure
AP-011,
10
CFR 50.59 Safety Evaluations.
26
The inspector
reviewed Technical Specification 3.6. 1.1 and its
associated
basis,
and
FSAR section 3.3, 3.5,
and 3.8.
Observations
and Findin s
The inspector
found that the licensee
Nuclear Assessment
Section
had
identified on April 5,
1997 at approximately 1:00 p.m. that the
containment
equipment
hatch missile shields
were being removed
and
questioned
whether containment integrity as required by Technical Specification 3.6.1.1
was being maintained.
The licensee's
investigation concluded that the plant had entered the Limiting
Condition for Operation of Technical Specification 3.6. 1. 1 at 3:20 a.m.
on April 5,
1997.
The action statement
required that the unit be in Hot
Standby in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />,
however,
the unit was already in that condition,
and
Cold Shutdown in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The licensee initiated
Condition Report 97-01499 'einstallation of the missile shields
was
completed at 4:50 a.m.
on April 6,
1997, within the time required by the
action statement.
The inspector
found that procedure
CH-H0100 was revised
on April 2,
1997
(Revision 6).
The revision included
a note under section
7. 1, Hissile
Shield Removal, that allowed the missile shields to be removed anytime
in Hode 3 through 6.
The 10
CFR 50.59 safety evaluation screen
was
completed
on April 1,
1997 and concluded that the activity does not
require
a change to the Technical Specifications.
The licensee
concluded that the 50.59 screening
review was inadequate
because it did
not identify that the change to allow removal of the missile shields in
Hode 3 required
a Technical Specification
change.
Technical Specification 3.6. 1. 1 requires
containment integrity be maintained in
Hodes
1 through 4.
The inspector observed that
FSAR section 3.3,
Wind and Tornado Loadings,
described
the containment structure
as
one that was designed to
withstand design wind and tornado generated
missiles.
FSAR se'ction.3.5,
Hissile Protection,
states that protection of safety related
systems
and
equipment,
including the containment liner, from missiles is
accomplished
by various methods including barriers.
Table 3.5.2. 1,
Barriers
Designed
For Hissiles, lists the containment building as the
structure that is designed to prevent external missiles
from damaging
the liner.
Figure 3.5.1-01,
Safety Related Structures
Systems
and
Component Protected Against Tornado Hissiles,
shows the removable
missile shield
as protection for the equipment hatch.
The inspector
found that the missile shields
were not specifically called out in the
written portion of the
FSAR.
However,
based
on the written words for
the containment building being
a barrier for the liner
and the missile
shields being shown on Figure 3.5.1-01
around the equipment hatch,
the
missile shields
performed the
same function for the equipment
hatch that
the containment building performed for the liner.
Licensee
review of
this information during the post event discussion
on April 6,
1997 had
come to the same conclusion.
27
The inspectors
considered that reviews of the outage schedule,
out'age
risk assessment,
and operations
review and work authorization could have
caught this problem prior to initiation of missile shield removal.
The
inspector
discussed this aspect with licensee
management
who initiated
condition report 97-02333,
since the original investigation
had focused
only on the inadequate
procedure
change
and safety review.
Re ulator
Si nific nce
10
CFR 50.59,
Changes,
Tests,
and Experiments,
allows licensees
to make
changes in the facility and procedures
as described
in the safety
analysis report without
NRC approval
unless it involves
a change,to
the
technical specifications
or an unreviewed safety question.
The
procedure
change authorized
an evolution in
a mode that was prohibited
by the plant's technical specifications
and therefore required that
a
technical, specification
change
be submitted
under
10
CFR 50.90.
This is
considered
an apparent violation of 10
CFR 50.59 for making
a change to
the facility through
a procedure that required
a technical specification
change without first seeking
NRC approval
(50-400/97-04-04).
Conclusions
The inspector
concluded that
an apparent violation of 10 CFR 50.59
had
occurred.
The violation was licensee-identified
and was promptly
addressed
and corrected.
III. En ineerin
El
El. 1
Conduct of Engineering
Desi
n Chan
e Processes
'a.- Ins ection Sco
e
37550
The inspectors
reviewed the procedures
listed below which control design
and design
changes to determine if the procedure
implement the
requirements of 10 CFR 50, Appendix B, Criterion III and
10
CFR 50.59.
The following procedures
were reviewed:
EGR-NGGC-0001,
Conduct of Engineering Operations,
Revision 2,
dated February 3,
1997
EGR-NGGC-0003,
Design Review Requirements,
Revision 0, dated
June 3,
1996
EGR-NGGC-0005,
Engineering Service
Requests,
Revision 4, dated
March 25,
1997
EGR-NGGC-0006,
Vendor Manual
Program,
Revision 1, dated August 6,
1996
28
EGR-NGGC-0007,
Haintenance of Design Documents,
Revision" 0, dated
December
17,
1996
EGR-NGGC-0156,
Environmental Qualification of Electrical
Equipment
Important to Safety,
Revision 0, dated
March 5,
1997
EGR-NGGC-0320, Civil/Structural Operability Reviews,
Revision 0,
dated
Hay 8,
1996
EGR-NGGC-0351,
Performance
Monitoring of Structures
and Tanks,
Revision 3, dated
March 17,
1997
ENP-011,
Preparation
and Control of Design Analyses
and
Calculations,
Revision 5, dated
December
19,
1996
Observations
and Findin s
The inspectors verified that the procedures
adequately
addressed
design inputs,
design calculations,
design verification, drawing
changes,
post-modification testing,
control of field changes,
10
CFR 50.59 safety evaluations,
training,
and ALARA reviews.
The inspectors verified that Revision 4 of procedure
EGR-NGGC-0005
complied with the design verification requirements of 10 CFR 50, Appendix B, Criterion III. This procedure is
a corporate
procedure
which specified the requirements
for preparation of
design
changes
at the Brunswick, Harris,
and Robinson plants.
The
inspectors identified
a violation at the licensee's
Brunswick
Plant
(see
NRC Inspection Report number 50-325,
324/97-02)
because
Revision
3 and previous editions of procedure
EGR-NGGC-0005 did
not comply with the design verification requirements of 10 CFR 50, Appendix B, Criterion III.
The violation is summarized
as
follows.
The engineering service requests
(ESR) is the process
used for
performing engineering
work.
EGR-NGGC-0005 defines three types of ESRs.
These
are design
change
(DC), configuration change
(CC),
and engineering
disposition
Design change
ESRs were defined
as
a change
which affects the design input of a system,
structure,
or component
(SSC); while a configuration change
was
a change to a
SSC which did not
change the design inputs.
Both of these
ESRs produced design output
documents
which could have resulted in modifications to a SSC.
Engineering disposition
ESRs were used to supply information and do not
produce design output documents
or change
any SSC.
ESRs designated
as
design
change
ESRs required design verification to meet the requirements
of 10 CFR 50 Appendix B, Criterion III, ANSI N45.2.11,
and Regulatory
Guide 1.64.
The qualifications for design verifier s were addressed
in
paragraph
4.9 of EGR-NGGC-0001.
ESRs designated
as configuration
changes
required
an engineering
review, instead of a design
verification.
There were
no specific requirements listed for
individuals who performed the engineering
review.
The engineering
review,
as defined by CP8L procedure
EGR-NGGC-0003 did not meet the in-
29
depth review and independent
review requirement's of Appendix B,
Criterion III, ANSI N45.2.11,
These
requirements
specify that the design control measures,
including design
verification activities,
be established to assure
the design basis is
cor rectly translated into design outputs (e.g.,
drawings,
specifications,
procedures,
and/or instructions).
The requirements
also
specify that design
changes
be subjected to the
same controls
as those
applied to the original design.
On February 11,
1997,
as
a result of the identification of'his concern
at the Brunswick Nuclear Plant, the licensee
issued
a temporary change
to procedure
EGR-NGGC-0005 which implemented the
NRC requirements
for
design verification of safety-related
ESRs.
This temporary change
included provisions for all in-process
and non-field-complete
configuration change
ESRs to receive design verifications prior to their
next approval
step.
The licensee
issued
CR 97-01255
on Harch 25,
1997,
to document
and disposition this problem at the Harris plant.
In
addition to revising procedure
EGR-NGGC-0005, the licensee's
corrective
actions,
which were in progress
during the inspection,
also included
review of all safety-related
configuration change
ESRs to determine if
an appropriate
design verification was performed.
Use of Revisions
0 through
3 of EGR-NGGC-0005 to control design
activities
and failing to perform design verification of safety-related
was identified as
a violation of 10 CFR 50, Appendix B, Criterion
III. This violation is considered licensee-identified
at the Harris
facility because
plant personnel
took immediate action to resolve the
issue
once it was identified as
a violation at another facility.
This
licensee-identified
and corrected violation is being treated
as
a
Non-Cited Violation, consistent with Section VII.B.l of the
NRC
Enforcement Policy (NCY 50-400/97-04-05,
ESR Design Verification
Requirements).
Conclusions
4
The inspectors
concluded that the licensee's
current design
change
control procedures
complied with the requirements of 10 CFR 50.59,
and
10 CFR 50, Appendix B, Criterion III.
However,
a non-cited violation
was identified for failure to perform design verification of safety-
related configuration change
ESRs from June 3,
1996, the effective date
of Revision
0 of'GR-NGGC-0005,
through February
11,
1997,
when
NRC
identified that
EGR-NGGC-0005 did not comply with 10 CFR 50, Appendix B,
Criterion III at the Brunswick Plant.
Review of modifications to Electrical
S stems
Ins ection Sco
e
37550
The inspectors
performed
a review of modifications planned for refueling
outage
(RFO) 7, with a concentration
on electrical
systems.
There were
18 modification packages
prepared
for implementation
on electrical
systems:
eight "safety-related",
seven considered
important to safety by
30
the inspector,
and the remainder nonsafety-related.
Some of the
requirements
applicable to the areas of review were
10
CFR 50.59,
10
CFR 50.71
and
FSAR Sections
7 and 8
~
Each of the
18 modifications was discussed
with the cognizant engineer.
For
several
modifications, specific additional information was requested
and evaluated
by the inspectors.
Findin s and Observations
Each of the engineers
contacted
were knowledgeable of their assigned
modification, the technical
issues
involved and the relevant
requirements.
No problems
were identified with the design control
program or process.
The inspectors
observed
an effectiveness
in
resolving safety issues
and maintaining the design basis
as evidenced
by
the following examples:
The ground detection
system for the safety-related
batteries
was
upgraded (this was actually an on-line modification).
Root cause evaluations
for circuit breaker
problems were good.
Hodifications in the switchyard under the control of the
transmission
group (i.e., non-plant personnel)
were treated
as
a
plant modification for purposes of performing 50.59 evaluations.
During observation of work in progress,
the inspectors
noted
a problem
with modification
ESR 9500233,
Telemecanique
Disconnect Switch Obsolete.
This modification replaced
a number of fused disconnect
switches with
ones
from a different manufacturer.
The dimensions
provided in the
installation instructions
were incorrect which resulted in work stoppage
to revise the dimensions.
This one example of apparently not verifying
through walkdowns or
mockups the accuracy of work instructions
was
considered
an isolated
case.
Conclusions
Based
on
a review of modifications to electrical
systems
implemented in
the current refuel cycle, the licensee's
performance in the area of
design control
and compliance with the requirements
stated in the
inspection
scope section
was good.
Permanent
Cavit
Seal Installation
Ins ection Sco
e
37550
The inspectors
reviewed drawing and procedures
for installation of
a permanent cavity seal.
b.
Observation
and Findin s
31
C.
E1.4
The inspectors
reviewed
ESR 94-00013,
Permanent
Cavity Seal
Ring.
The purpose of this modification was to eliminate the need for
installation of a temporary seal
each refueling outage
which used
a pneumatic
seal with caulking
(RTD) materials to enable flooding
of the reactor cavity for refueling operations.
This modification
was originally scheduled
for installation during RF0-6, but,fit-up
problems resulted in rework of the permanent
seal
components
and
delayed installation until RFO-7.
The inspectors
reviewed
procedure
EPT-219T, Revision 4,
Permanent
Cavity Seal
Ring
Installation which contained
requirements for the seal
installation.
This procedure specified prerequisites,
installation procedures,
QC inspection requirements,
and
acceptance
testing of the completed installation.
Acceptance
testing included hatch cover leak testing,
pre-floodup inspection,
and the floodup inspections for leaks.
The procedures
also
specified requirements
for visual inspection
and non-destructive
examination
(dye penetrant testing) of welds.
The inspectors
reviewed vendor drawing numbers
6445E71 through 6445E74,
and
6445E76
and vendor technical
manual
HSE-REE-725 which specified
the installation details.
The inspectors
noted that problems
identified during
RFO 6 had been resolved.
Conclusions
The inspectors
concluded that the installation documents
were
adequate to assure
proper installation of the
new permanent cavity
seal.
The acceptance
testing specified
was adequate
to assure
the
seal
would perform its intended function.
Walkdown Ins ection of Reactor
Containment Buildin
Ins ection Sco
e
37550
The inspector
performed
a walkdown inspection of the containment
building to examine the condition of the structure
and installed
systems.
Findin s and Observations
The inspectors,
accompanied
by two engineers
from the Nucl'ear
Assessment
Section
(NAS), walked down the containment building on
elevations
221 (feet above
sea level), 236,
261,
and 286 and
. examined the containment structure,
pipe supports,
instrumentation
and cable tray supports
and the condition of protective coatings.
During the walkdown, the inspector
identified some areas
where the
liner plate appeared to be corroded at elevation
221 from azimuth
60 through
120
adjacent to the concrete slab..
Some small
areas
with corrosion were also identified adjacent to the sumps,
and the
silicone expansion joint sealer
was separated
from the liner plate
in some areas.
The purpose of .the silicon seal
was to keep
c
~
E2
E2.1
32
moisture out oi the one inch wide Ethafoam expansion joint between
the liner plate
and five foot thick concrete
base slab inside
containment.
The licensee initiated CR'7-01880 to document
and
disposition this problem.
'The licensee
removed the corrosion
and
perform
NDE (ultrasonic testing) to determine if the corrosion
had
reduced the thickness of the liner plate.
The
UT showed that the
liner plate exceeded
the nominal thickness of 0.375 inches.
The-
licensee
removed p'ortions of the silicon seal
and the expansion
joint material
(one inch thickness of ethafoam)
and examined the
liner visually and with UT.
The inspectors
witnessed
the
UT exams
and concur red with the licensee's
testing methods
and test results
which showed that the liner exceeded
0.375 inches (section H2.6).
The results
were documented
and evaluated
in ESR 97-00359.
During
the visual
exams,
licensee
engineers
determined that the expansion
joint gap was filled with water up to elevation
219'.
This was
the
same elevation
as the water level in the containment
The licensee
pumped the water
from the expansion joint, pumping
out in excess of 5000 gallons.
Chemical analysis of the water
showed
a
pH of'.8,
and
a boron concentration of 2700
ppm.
The
licensee
concluded that the apparent
source of water in the
expansion joint was from the sumps.
The licensee
repaired the
on the liner, repaired seals
between the expansion joint
and sumps,
and installed
a system to monitor the water level
during plant operations.
The licensee
plans to complete long term
corrective actions
(discussed
in ESR 97-00359) during the next
refueling outage.
Conclusions
Plant engineers
conducted
a good indepth evaluation of this
problem after it was identified by the inspectors.
Engineering Support of Facilities and Equipment
General
Comments
37551
The licensee's
root cause investigation into the second
reactor
coolant
system boron dilution event discussed
in report section 04.2 uncovered
several
previous engineering
problems.
These included incomplete
update
of vendor information related to the
new valve coefficient for the boric
acid flow control valve (1FCV-113A) after its internals
were replaced in
the mid-1980s.
Also, incor rect assumptions
were
made about the
capability of 1FCV-113A when
requirements
were
increased after
a plant upgrade to
a higher enrichment of nuclear fuel
in 1992.
The valve was never tested to verify that its flow capacity
would support the
new higher boron concentration
requirements.
After
repeated
problems with flow deviation alarms
due to.inadequate
boric
acid flow through the valve,
a Plant
Change
Request
(PCR 7285)
was
issued to change the valve trim.
This
PCR was subsequently
canceled in
1995 for no apparent
reason.
33
As mentioned in report section 04.2, the above engineering
problems all
contributed to the system malfunctions that ultimately lead to the
April 8,
1997 boron dilution event identified as example
3 to Violation
50-400/97-04-02.
The licensee's
root cause investigation into the
engineering
issues
related to the April 8 event
was thorough.
The
FCV-
113A valve trim was replaced during RFO-7 and was being tested
subsequent
to this inspection period.
En ineerin
Review of NRC Information Notices
Ins ection Sco
e
40500
The inspectors
reviewed the licensee's
system for processing
and
evaluating
NRC information notices.
Observations
and Findin s
The inspectors
reviewed
CPSL procedure
number AP-31, Operating
Experience
Feedback,
Revision 5, dated February
1,
1996.
This
procedure specifies the process for review and evaluation of NRC
information notices
(INs) and other operating experience
.documents.
The inspectors
also discussed
the licensee's
system
for review and evaluation of INs with licensing engineers
and
reviewed the status of recently issued
INs.
The review and
discussions
disclosed that with the exception of IN 97-09 through
97-13, all other
INs has
been reviewed in licensing
and forwarded
to.the appropriate
group (engineering,
operations,
maintenance,
etc) for evaluation.
dated
Harch 12,
1997, through IN 97-13,
dated
Harch 24,
1997,
had not yet been processed
by
licensing
and forwarded to engineering
due to the recent
retirement of the individual in licensing
who previously was
responsible for processing
the INs.
These
INs were forwarded to
engineering for evaluation.
An ESR was opened to document
Engineering actions to address
the issues
in individual INs.
Additional documents
are issued
as required to initiate
appropriate
actions to resolve
any identified issues.
A recent
assessment,
number H-SP-97-05,
completed
on April 1,
1997,
by the
Nuclear Assessment
Section
(NAS) identified an issue regarding
some discrepancies
in procedure
AP-31.
The licensee
issued
CR 97-01423 to document this finding.
The procedure will be
revised
as necessary
to address
the discrepancies.
An item for
management
consideration
was also identified by NAS regarding the
fact that the computer
database
used to track operating experience
items was not "user friendly."
The inspectors
questioned
licensee
engineers
regarding their plans
for followup on IN 97-10, Liner Plate Corrosion in Concrete
Containments.
Since this IN had not yet been sent to engineering,
no specific actions
had yet been developed to address
the IN.
However discussions
with the containment
engineer disclosed that
the licensee
was in the process of implementing the requirements
to comply with revisions to 10
CFR 50.55a which requires
34
containment inspections
and repairs
be performed in accordance
with ASME Section XI, Subsections
IWE and
IWL.
This inspection
was scheduled to be performed prior t'o the containment
leak rate
test,
approximately three
days after the inspectors
completed the
containment
walkdowns discussed
in paragraph
El, above.
Conclusion
The inspectors
determined that the licensee
has established
acceptable
procedures
for the review and evaluation of NRC
information notices.
Forei
n Material
Found in B CCW Heat Exchan
er
Ins ection Sco
e
40500
The inspectors
reviewed the licensee's
evaluations
and resolution of
foreign material
found in B CCW Heat Exchanger.
Observations
and Findin s
During the licensee's
inspection of the "B" component cooling
water
(CCW) heat exchanger,
foreign materials
were found.
The
source of the materials
was determined to be from the emergency
service water strainers that failed due to corrosion.
The purpose
of the strainers
was to filter the service water
and prevent
materials
from being introduced into the system.*
The licensee
initiated
CR 97-01661 to document
and disposition this problem.
Inspection of the "A" train
ESW pump strainers
disclosed that these
strainers,
which were the original materials,
were still functional.
The "B" train pump strainers
were replaced during
RFO 6.
The original
strainers
were fabricated
from 304 stainless
steel.
The replacement
str ainers
were made of Monel 400.
The inspectors
reviewed Material
Evaluation Report
number 001394.00 which was prepared to evaluate
the
replacement
strainers.
The substitution of Monel 400 for 304 stainless
was considered
a material
upgrade since the monel is more corrosion
resistant
than 304 stainless.
The monel
was selected
due to the
unavailability of new stainless
steel strainer s.
The material
evaluation report showed that the monel
was acceptable.
The cause of
the failure was still under investigation by licensee materials
engineers.
The licensee
decided to replace the failed monel str ainers with
new strainers
fabricated
from 304 stainless
since this was the
material originally specified,
and the service life of the 304
strainers
was satisfactory in the ."A" pumps.
The inspector s
reviewed Material Evaluation
number 002703.00
which was completed
to obtain replacement
strainers
for the failed gonel strainers
from another utility.
Replacement
strainers
were not available
from the vendor.
Documentation supplied
by the original vendor
indicated that the replacement
strainer s had been fabricated
from
35
304 stainless.
However,
upon receipt inspection
and testing
performed
by the licensee
when the .new strainers
were received at
the Harris site, the licensee
determined that
some of the
strainer s had been fabricated
from 316 stainless.
A material'old
was placed
on the strainers
pending further investigation by
procurement
engineering.
Procurement
and receiving activities were handled
under the
CPKL
corporate
Operations
and Environmental
Support Department's
Haterials Services
Section,
designated
as Procurement
Engineering.
This is
a separate
organization
from the Harris Engineering
Ser vices Section
and the corporate
Nuclear
Engineering Department.
The following documents
were reviewed which specified requirements
for procurement,
evaluation
and selection,
and receiving
inspection of plant components:
~
HCP-NGGC-0401, Haterial Acquisition, Rev. 2, dated April 15,
1997.
~
EGR-NGGC-0204,
Evaluation
and Selection of Haterials for
Plant Components,
Rev.
0, dated
December
6,
1996.
~
Procurement/Design
Engineering Interface Agreement,
dated
January 5, 1996.
The inspectors
concluded that the licensee's
controls for
procurement of replacement
hardware
complied with NRC
requirements.
The cause of the corrosion of the monel strainers
in the "B" ESW pump was still under investigation at the end of
the inspection period.
Conclusions
The inspectors
concluded that the failure of the strainers
in the
"B" ESW train were not related to an inadequate
evaluation for the
replacement
strainers.
The licensee's
procurement
engineering
program meets
NRC requirements.
Licensee engineers
wer e very
proactive in the evaluation of the strainers'ailure.
Quality Assurance in Engineering Activities
S ecial
FSAR Review
37551
A recent discovery of a licensee operating their facility in a manner
contrary to the Updated Final Safety Analysis Report
(UFSAR) description
highlighted the need for a special
focused review that compares
plant
practices,
procedures
and/or
parameters
to the
FSAR descriptions.
While
performing the inspections
discussed
in this report, the inspectors
reviewed the applicable portions of the
FSAR that related to the areas
inspected.
4
h
36
The licensee
made
a presentation
to the
NRC on May 31,
1996 concerning
their corporate-wide
plan for reviewing the
FSAR at the
CPSL sites.
The
program
has generated
a large
number of condition reports at the Harris
Plant
(311 by the end of the inspection period).
The results'from this
program will be reviewed in the closure of Unresolved
Item 50-400/96-04-
04, Tracking
FSAR Discrepancy Resolution.
The inspectors
did not find
any additional discrepancies
other
than those identified by the
licensee.
ualit
Assurance
Assessment
and Oversi ht
Ins ection Sco
e
40500
The inspectors
reviewed self-assessments
performed within the
Harris Engineering Support Section.
Observations
and Findin s
Self-assessments
are part of the overall
CPSL quality assurance
program at Harris.
The self-assessments
were performed in
accordance
with procedure
PLP-03,
Self-Assessment,
Revisions
4 and
.5.
The results of these
assessments
were categorized
as
strengths,
or findings.
The following self-assessments
were
reviewed by the inspector:
HESS96-016,
EQ Program,
May 6
- 9.
1996,
HESS96-025,
Procedure
compliance
- Corrective Action
Effectiveness,
October
1
- November 22,
1996,
HESS96-028, Service Water Program,
and
HESS97-002,
EDBS Program,
January,
1997.
Several
findings were identified in Assessment
96-016.
Six Condition
Reports
(CRs) were written to document discrepancies
identified in the
EQ program;-
However
none of the problems resulted in identification of
any inoperable
equipment.
The conclusion of the assessment
was that the
Harris
EQ program meets overall requirements.
The issues identified
primarily involved procedural
discrepancies
which were being addressed
through issuance of new procedures.
A corporate
procedure,
NGGC-EGR-
0156 was recently issued to resolve
some of the discrepancies
and
clarify some of the
EQ requirements.
One weakness
and two issues for
management
consideration
were identified in Self-assessment
96-028.
The
weakness
involved lack of'cceptance criteria in a service water
surveillance test procedure.
The areas
for management
consider ation
involved procedural
issues.
A CR was opened to address
the weakness
and
areas for management
consideration.
Five issues
and two items f'r
management
consideration
were identified in self-assessment
97-002.
Condition reports
were initiated to document
and resolve these
problems.
The primary areas of concern identified by the self-assessment
involved
inadequate
controls in procedures.
Corrective actions
were in progress
at. the end of the inspection period.
37
C.
Conclusions
The inspectors
concluded that the self-assessments
performed by
HESS were effective in identifying engineering
performance
deficiencies
and were useful in providing oversight to management.
Managers in HESS have
been proactive in following up on the
problems identified at other sites to address
any
EQ program
deficiencies.
E8
E8.1
E8.2
Miscellaneous
Engineering Issues
(92700,
92903)
Closed
Unresolved
Item 50-400/96-02-03:
Use of Potentially
Unconfirmed Information Obtained via Telecons in Design Calculations.
During review of engineering service requests
during the
inspection
documented in NRC Inspection Report 50-400/96-02,
the
inspectors identified three examples of licensee
design
engineers'pparent
use of information obtained
from vendors over the
telephone without proper verification of the'accuracy of the
information.
This issue
was originally identified during
NAS
Assessment
H-MOD-94-01.
The examples
were identified in ESR
.numbers
9400076,
9400118,
and 9500120.
Further review of the
disclosed that additional information was available in the design
backup section of the
ESR which showed the vendor
provided
additional
data to confirm the information originally provided in
the telecon.
The inspectors
reviewed the additional information
provided by the licensee
and verified that the telecon data
was
properly documented.
In one case,
ESR 9400118,
the telecon
information was used to develop the
ESR.
The
ESR wa's then sent to
the vendor for concurrence.
Licensee
engineers
reviewed design
change
packages
installed during the previous three refueling
outages,
RF0-4,
5,
and 6,
and determined that no other examples
were identified of the use of information obtained in telecons
with vendors
for design information with the exception of the
example identified by NAS.
Precautions
regarding the use of
vendor supplied design. inputs were discussed
in CPLL procedure
numbers
EGR-NGGC-0005
and 0006.
This issue
was also discussed
.
with engineering
personnel
during training.
The inspectors
also
verified during review of the
ESRs listed in paragraph
El above
that unconfirmed information was not used in preparation of design
documents.
This item is closed.
0 en
URI 50-400/96-04-04:
Tracking
FSAR Discrepancy Resolution
(Spent
Fuel
Pool Cooling).
An initial review of the spent fuel pool cooling system
based
on
problems at another facility'resulted in the opening of IFI 50-400/96-
02-04.
This item was later closed
and converted to this unresolved
item
based
on the licensee's
FSAR review program.
The
NRC completed
a
generic licensing review of spent fuel pool safety issues
and by letter
dated July 1,
1996
and September
17,
1996, transmitted the results to
the licensee.
The licensee
responded to the July 1,
1996 letter
on
38
August 8,
1996
and committed to updating the current spent fuel pool
'eat
load analysis,
updating the
FSAR to clarify the terms
abnormal
and
- normal fuel off-loads,
and revising the
FSAR to reflect the current
installed spent fuel pool configuration.
The inspectors
found that the
FSAR change
(RAF 2295)
was approved
Harch
12,
1997.
The inspectors
reviewed the
FSAR change
and associated
safety
evaluation
(per
10
CFR 50.59)
and found that the commitments
were
completed prior to core off-load.
The heat load analysis
was updated to
reflect the latest calculation.
The
FSAR was clarified to remove the
words "abnormal"
and "normal" off-load, replacing them with "full core
offload shuffle" and "post outage full core offload".
The
FSAR was
revised to reflect the current spent fuel pool cooling configuration and
latest description of equipment,
since the equipment originally
described in the
FSAR that supported the unit 2 spent fuel pools have
not been completely installed.
This item remains
open pending the
licensee's
completion of their overall
FSAR review program.
IV. Plant
Su
rt
Rl
R1.1
Radiological Protection
and Chemistry Controls
Radiolo ical Controls
a.
Ins ection Sco
e
83750
The inspectors
evaluated
radiological controls with emphasis
on external
occupational
exposures
during outage conditions'.
Areas inspected
included contro)s for locked high and very high radiation areas,
radiation area postings,
radiation work permits
(RWPs),
and controls for
radioactive material in accordance
with the requirements of 10
CFR 20.
b.
Observations
and Findin s
The inspectors
made frequent tours of the radiation controlled area
.
(RCA), observed
personnel
compliance with radiation protection
procedures
for high dose work evolutions'nd
conducted interviews with
licensee
personnel
to ascertain
knowledge of radiological controls
and
working conditions.
The inspectors verified controls for external
and
internal
exposures
met applicable regulatory requirements
and were
designed to maintain exposures
as low as reasonably
achievable
(ALARA).
The inspector s reviewed select
RWPs which controlled ongoing outage
work
within the
RCA, including high dose activities within containment,
and
noted that the controls observed
were appropriate
for the described
tasks
and radiological conditions.
During plant walkdowns within the
RCA, the inspectors
conducted
interviews at random with radiation workers both inside
and outside of
containment.
The interviews were conducted with radiation
wor kers of
various disciplines in order to determine the level of understanding
of
RWP requirements
from a representative
cross-section
of plant workers.
39
All of the workers interviewed were verified to have signed onto an
RWP,
were wearing dosimetry appropriate to their work activities
and in
accordance
with their
RWP,
and were performing specific work activities
permitted within the scope of their specific
RWP.
The workers,
by
signing onto an
RWP via the access
control computer, signified that they
understood
the conditions
and requirements of the
RWP being logged onto
in accordance
with Environmental
and Radiation Control
(EIIRC)
procedures.
The questions
asked included the
RWP number of the
signed onto, dosimetry alarm and cumulative dose limits, available
dose
remaining,
and general
radiological working conditions for the areas
wor ked in.
The workers demonstrated
generally good knowledge of RWP
requirements
and radiological working conditions.
The inspectors
reviewed totaI whole body exposures
for all licensee
radiation
wor kers
and determined that all whole body exposures
assigned
during 1996 and
1997 through the end date of inspection
were within
10 CFR 20 regulator y limits.
A review of licensee
personnel
exposure
records indicated the following maximum individual exposures
at the
plant during 1996 were: Total Effective Dose Equivalent
(TEDE): 795 mrem
and Shallow Dose Equivalent
(SDE):
5660 mrem from a hot particle.
No
internal
exposures
were reported f'r the period.
Through Harch 1997,
the licensee
incurred
a maximum TEDE of 115 mrem with no contamination
events that exceeded
the
SDE threshold requiring
a dose
assessment.
The
inspectors
determined the licensee
had adequately
monitored
and tracked
individual occupational
radiation exposures
in accordance
with 10
CFR
Part
20 requirements
and that all doses
reported
were at
a small
percentage
of applicable regulatory limits.
The inspectors
evaluated
the licensee's
program for controlling access
(HRAs) and locked high radiation areas
(LHRAs).
These
areas
were inspected
during tours for proper postings
and access
controls.
No HRAs or LHRAs were identified where required postings
wer e
needed
but not posted.
Areas controlled
as
LHRAs were inspected
and
f'ound locked or otherwise controlled in accordance
with licensee
procedures.
The licensee
had completed
a posting upgrade with respect,
to radiation areas to achieve full compliance with the regulatory intent
of 10
CFR 20.1902.
Key controls for entry into locked high radiation areas
were evaluated
against the requirements of the licensee's
administrative procedure
and
determined to be appropriate.
During a tour of the spent fuel building,
the inspectors
observed
no items hanging from the side of the pool that
were not labelled or properly controlled in accordance
with procedure.
Good radiological controls were observed to be in place in the entire
spent fuel building.
A sample of survey instruments available for
issuance
was inspected
and determined to have current calibration
dates
and be in operable condition.
Radiation workers were observed exiting
the
RCA during peak traffic periods in accordance
with procedures
for
frisking out of the
RCA.
40
Conclusions
The radiological controls
program in general
was being effectively
implemented with good radiation control performance
demonstrated
during
the refueling outage.
Radiation
Work Permit
Doses
Exceeded
Ins ection Sco
e
83750
The inspector
reviewed circumstances
surrounding
a licensee-identified
RWP dose limit violation that occur red on April 12,
1997.
Observations
and Findin s
During the removal
and replacement of insulation from the chemical
and
volume control system regenerative
heat exchanger
on the 236-foot
elevation of the reactor
containment building,
a Radiation Control
(RC)
Technician
and
an insulation contractor
each
exceeded their RWP-allowed
doses of 400 mrem. This occurred
when both individuals failed to
immediately exit their
wor k area
when their electronic dosimeters
alarmed at the accumulated
dose setpoint of 320 mrem.
Doses received
by
the
RC Technician
and the insulator during the entry were 530 mrem and
495 mrem, respectively.
The individuals indicated in written statements
they did not hear their electronic dosimeters'nitial
alarms
due to
high noise levels in the work area
and only became
aware they had
exceeded their
RWP limits when they came out to undress.
Based
on the inspector 's review of the workers'tatements,
radiation
control oversight
was inadequate
in that the
RC Technician providing
health physics
(HP) job coverage actively participated in the insulation
work in order to expedite job completion
and lost focus
on the primary
assigned
role of radiation control.
Although no administrative or
regulatory dose limits were exceeded
during the incident, the failure of
the workers to promptly exit the work area
when thei r electronic
dosimeters
alarmed is
a violation of Administrative Procedure
AP-535,
Revision 8, Section 5. 16.5,
Performing Work in Radiation Control Areas,
which required workers to immediately leave
a work area
when
an
electronic dosimeter is in alarm.
The licensee
took prompt and thorough
action in response
to the incident to include assigning
a significant
Level
1 Condition Report which will require
an in-depth root cause
analysis,
expedited
completion of required corrective actions,
counselling
and discipline with respect to the workers involved,
and
a
stand.-down
meeting with all site
HP personnel
to increase
emphasis
on
the need for strict compliance with RWP requirements
and safe radiation
worker practices.
This licensee-identified
and corrected violation is
being treated
as
a Non-Cited Violation consistent with Section VII.B.1
of the
(NCY 50-400/97-04-06).
41
Conclusions
R1.3
One Non-Cited Violation was identified for failure of radiation workers
to promptly leave
a work area
when their electronic dosimeters
alarmed.
Inade uate Labelin
of Radioactive Haterial
Ins ection Sco
e
83750
b.
The inspector
performed routine walkdowns inside the
RCA on
April 14-15,
1997, to verify that radioactive material
was tagged
and
labeled in accordance
with licensee
procedures.
Observations
and Findin s
The inspector
identified examples of radioactive material that were not
tagged
and labeled in accordance
with licensee
procedures.
The
inspectors
surveyed miscellaneous
hand tools and scrap metal pieces that
were found in an unmar ked five gallon bucket located in the vicinity of
the bead-blast
unit on the 236-foot elevation of the waste processing
building.
The inspectors identified
a hand chisel with fixed
. contamination levels which required marking per procedure or controlled
as radioactive material
and tagged
(greater than
100 net counts per
minute).
Upon the inspector's
request,
licensee
personnel
frisked the
remaining unmarked/untagged
materials in the bucket
and found additional
items not controlled in accordance
with procedure
HAS-NGGC-0003.
Another example
was identified by the inspectors
on the 291-foot
elevation of the
same building where
a bag of wrapped lead shielding was
not tagged properly as radioactive material.
All of the items
identified were judged to be of minimal safety risk due to the low
radiation levels detected.
. The failure of the licensee to label the radioactive materials with a
-clearly visible label bearing the radiation symbol
and the words
"Caution, Radioactive Haterial" is contrary to licensee
procedure
HPS-
NGGC-0003, Revision 1,
Paragraph
9.2, Tagging
and Labeling of
Radioactive Haterial which requires
each container holding radioactive
material to be so-labeled.
Additionally, in accordance
with the
same
procedure
and paragraph,
hand tools with fixed contamination greater
than
100 net counts per minute are required to be marked with purple or
magenta paint.
Based
on the relatively isolated nature of the items
identified, the licensee's
prompt and thorough corrective actions,
and
the relatively low safety significance of the radiation hazard, this
failure constitutes
a violation of minor significance
and is being
treated
as
a Non-Cited Violation, consistent with Section
IV of the
NRC
Enforcement Policy (NCV 50-400/97-04-07).
Conclusions
One Non-Cited Violation was identified for failing to tag and label
radioactive material in accordance
with procedure.
R1.4
a.
Contamination Controls
Ins ection Sco
e
83750
42
b.
The inspectors
evaluated the licensee's
controls for personnel
contamination
events
(PCEs)
and adequacy of related
PCE followup.
Also
evaluated
was the adequacy of contamination
surveys
and contaminated
area controls.
Observations
and Findin s
The inspectors
reviewed the records of all
PCEs incurred during 1996 and
1997 through the date of inspection.
During 1996, the site incurred 41
PCEs which was well within the licensee's
1996 annual
goal
of. 50 PCEs.
Based
on the history of PCEs at the site, the inspectors
determined that
the original
PCE goal
was aggressive
based
on prior PCE performance.
During 1995 and 1994, periods with outage activity, the licensee
experienced
177 and 226 PCEs,
respectively.
Although the number of PCEs
incurred is
a minor radiation safety concern,
PCEs reflect on the
effectiveness
of a licensee's
contamination control
program and on
radiation work practices.
During an evaluation of 1996 PCEs, the
.inspectors
noted that each contamination event
was evaluated
by the
licensee in accordance
with PCE procedure with corrective actions taken
in each
case,
as appropriate.
Only 5 of the 41
PCEs in 1996 were skin
contaminations
and only 2 of these
contaminations
resulted in a
SDE dose
greater
than the
100
mrem threshold requiring full dose
assessment.
Within the total 41
PCEs in 1996,
18 resulted
from work in designated
clean areas
which is
a high proportion representing
a challenge
area for
the licensee.
The inspectors
reviewed the
PCE evaluations
and noted
no
assessment
or procedural
errors.
The inspectors verified skin dose
assessments
had been performed with conservative
dose
assessment
methodology utilized.
Overall, licensee
actions with respect to
improving personnel
contamination controls were determined to be
effective with no regulatory concerns
noted.
During 1996, the licensee
achieved
a monthly average of 4183 square feet
of recoverable
contaminated floor area which was well within the 1996
goal of 4600 square feet.
This goal represents
approximately
1 percent
of the
RCA area which is relatively low.
The equivalent monthly average
for 1995 was 6362 square feet.
During the first three months of 1997,
the licensee
was able to achieve
a monthly average of 3324 square feet
prior to the RFO-7 outage.
The licensee effectively reduced
contaminated
square
footage by tracking performance
goals for each
building, eliminating contributors to contamination,
and continued
decontamination of recoverable
areas.
Overall, contaminated
areas
were
being maintained to less than one percent of total
RCA square
footage
which represents
good performance in this area.
The inspectors
reviewed
documented
contamination
surveys
performed during the ongoing refueling
outage
and observed
HP technicians
performing contamination
surveys in
accordance
with procedure.
Also, during inspection of the tool issuance
rooms,
good controls for slightly contaminated tools inside the
RCA and
for clean tools outside the
RCA were noted.
43
C.
Conclusions
Rl. 5
Contamination control
was effective overall with surface contamination
controlled adequately
at its source.
The licensee
continued to
effectively reduce
PCEs with adequate
procedural
followup on
contamination events.
Licensee initiatives to reduce
contaminated
square
footage were effective in maintaining contaminated
areas to less
than one percent of the
RCA.
As Low As Reasonabl
Achievable
Pro
ram Effectiveness
a.
Ins ection Sco
e
83750
This area
was evaluated to determine
whether the licensee
was
establishing
and tracking ALARA goals
and to evaluate the overall
effectiveness of the ALARA program.
10
CFR 20.1101(b)
requires that the
licensee
use procedures
and engineering controls based
upon sound
radiation protection principles to achieve occupational
doses that are
as low as reasonably
achievable.
Observations
and Findin s
Collective personnel
dose of 17.238 person
rem for
1996 was
a record low
for the site for
a non-outage
year.
During 1997, through the end of
Harch, the licensee
incur red 4.42 person-rem,
which continued the low
dose rate trend during periods of power operations
experienced
during
1996.
Based
on NUREG-0713 data,
the licensee's
dose performance
ranks
among the lowest doses
for single unit
PWR sites.
A relatively large
and unique dose contributor was that which occurred
due to receipt
and
decontamination of Brunswick and Robinson spent fuel shipments.
This
dose accounted for approximately
28 percent of overall site dose during
1996.
Another large non-recurrent
dose contributor during 1996 was
a
material
upgrade
and painting project that resulted in 2.256 person-rem
and represented
a 13 percent
dose contribution. Exclusive'f non-
recurrent
dose,
the licensee's
effective dose rate in person-rem
per
thousand
RWP hours
was exceptionally low and indicative of an effective
ALARA program.
The inspector
reviewed implementation of the
ALARA program with licensee
representatives
and noted that several initiatives to reduce overall
dose were implemented in 1996 and more were underway or planned for
1997.
Dur ing 1996 ALARA initiatives included:
completed loop trainer
for mock-up and scenario training; implemented
advanced
radworker
training; developed list of satellite valves for maintenance
planning;
and initiated
a radiological information tracking system for survey
and
job history records retrieval.
Planned initiatives in 1997 include:
fabricate
a seal
table'mock
up, installed permanent
cavity, seal
ring,
evaluate
increased
use of robotics,
evaluate
permanent
shielding
packages;
and initiate study on use of sub-micron filtration.
Conclusions
The licensee's
ALARA program was effectively controlling collective dose
and collective dose
was on
a favorable reducing trend.
Operational
doses
during 1996,
a non-outage year,
were at record lows for the plant.
Conduct of EP Activities
General
Comments
71750
93702
The inspectors
observed the licensee's
activities for various challenges
that involved the implementation of emergency
preparedness
procedures
during the inspection period.
These
included two RCS boron dilution
events,
a
bomb threat,
and
a small fire in the reactor auxiliary
bu'ilding.
The inspectors
concluded that emergency action level
procedures
were properly implemented
by control
room personnel
during
and following these
occurrences.
Communication between control
room
personnel
and other involved organizations
was adequate.
Licensee
personnel
properly notified the
NRC via the Emergency Notification
System in accordance
with 10
CFR 50.72 for the
bomb threat.
No
Emergency Action Level declarations
were required for the above events.
.No emergency
preparedness
drills were conducted during this period.
Conduct'of Security and Safeguards Activities
General
Comments
71750
93702
The inspectors
observed security and safeguards
activities during the
conduct of tours
and observation of maintenance activities,
and found
them to be good.
Compensatory
measures
were posted
when necessary
and
properly conducted.
Security personnel's
response to a
bomb threat
on
Hay 8,
1997 was adequate.
The bomb threat
was determined to be non-
credible.
Offsite law enforcement
agencies
were notified and
a four-
hour..report
was
made to the
NRC in accordance
with 10
CFR 50.72.
Control of Fire Protection Activities
Gener al
Comments
71750
The inspectors
observed fire protection equipment
and activities during
the conduct of tours
and observation of maintenance activities
and found
them to be acceptable.
Resolution of Thermo-La
Fire Barrier Issue
64704
Ins ection Sco
e
The inspector
reviewed the action taken to resolve the degraded
Thermo-
Lag fire barrier
issue at Harris to determined if the licensee's
action
was consistent with commitments
made to the
NRC.
Observations
and Findin s
45
In 1991, the
NRC identified that Thermo-Lag fire barrier material did
not perform to the manufacturer 's specifications.
NRC Bulletin 92-01'Failure
of Thermo-Lag 330 Fire Bar rier System to Haintain Cabling in
Wide Cable Trays
and Small Conduits
Free from Fire Damage"
was issued
which requested
licensees
with Thermo-Lag fire barriers to consider
these fire barriers to be degr aded
and take appropriate
compensatory
measures
for the areas
where the Thermo-Lag fire barriers
were
installed.
Initially, the plant had approximately 1,800 square feet of Thermo-Lag
fire wall/ceiling configurations.
This also included
a partial height,
one-hour
rated fire wall and protection associated
with fire door
transoms
and mullions.
The fire wall/ceiling configurations
are located
in the Auxiliary Control
Panel
Room and Cable Spreading
Rooms
"A and B".
The fire doors are located
on various elevations in the Reactor
Auxiliary Building (RAB).
The licensee
has evaluated
the results of data from various tests
performed by the nuclear
industry on Thermo-Lag fire barrier
.installations.
In addition, the licensee
has performed three full scale
fire tests of plant Thermo-Lag configurations
independent of industry
fire test programs to document the acceptance
of the tests
against the
as-found condition of the fire barriers.
Also, seismic evaluations
and
testing
has
been completed
on Thermo-Lag configurations.
The partial height,
one-hour fire wall was redesigned
and the Thermo-Lag
material
removed
and replaced with an alternate
gypsum board material.
Engineering evaluations
have
been
completed to address
Thermo-Lag use on
fire door
transoms.
Also, revisions to combustible loading calculations
to reflect Thermo-Lag combustibility and ampacity derating evaluations
have
been completed.
A safe
shutdown methodology re-analysis
was performed to identify the
components
required for plant shutdown following an Appendix
R fire.
The re-analysis
specified the separation to be provided between
safe
shutdown
components to meet the separation
requirements of 10 CFR 50, Appendix R,Section III.G.
This separation
was to be provided by
rerouting several
safe
shutdown cables for source
range instrumentation
and reactor
head vents to eliminate the need for Thermo-Lag protection.
As of the date of this inspection,
the licensee
had initiated the
implementation of corrective actions for Thermo-Lag issues,
except for
the installation of Thermo-Lag sleeve
upgrades
(ESR 95-00715),
corrective actions for a recently identified Thermo-Lag barrier
deficiency
(LER 50-400/97-06 discussed
in report section
F8. 1), safe
shutdown cable rerouting
(ESR 95-00682),
and completion of remaining
engineering evaluations
(ESR 95-00620).
The licensee's
LER 50-400/97-06
stated that the Thermo-Lag issue at Harris would be resolved
by
September
15,
1997.
46
Conclusions
The licensee
has
been proactive in the resolution of the Thermo-Lag
issue at Harris.
Fl.3
Fire Re orts
Ins ection Sco
e
64704
The inspector
reviewed the plant fire incident reports for
1996
and
1997, to assess
maintenance
related or material condition problems with
plant systems
and equipment that initiated fire events.
The inspector
verified that plant fire protection requirements
were met in accordance
with procedure
Fire Investigation Report,
Revision 6,
when fire
related events occurred.
b.
Observations
and Findin s
The fire incident reports indicated that there were two incidents of
fire in 1996,
and three fire events in 1997,
which required fire brigade
response.
No significant fires
had occurred during this period.
There
had been
one minor fire event in the turbine building involving cutting
or welding activities
and one minor electrical fire involving the "A"
battery
room during the current refueling outage (section H2.4).
Only
three of the five fires had occurred within the plant protected
area.
Conclusions
F2
F2.1
Good compliance with plant fire prevention procedures
resulted in a low
incident of fire within the plant protected
area.
Status of Fire Protection Facilities and Equipment
0 erabilit
of Fire Protection Facilities and
E ui ment'4704
a.
Ins ection Sco
e
b.
The inspector
reviewed open Condition Reports
(CRs)
on fire protection
components
and operation's out-of-service logs for fire protection
equipment to assess
the licensee's
performance
for returning degr aded
fire protection components to service.
In addition,
walkdown
inspections
were made to assess
the material condition of the plant's
fire protection systems,
equipment,
and features.
Observations
and Findin s
As of Hay 6,
1997, there were approximately 40 fire protection related
CRs in which the corrective actions
had not been completed.
Host of
these
involved minor
program improvement items
and did not affect the
operability of fire protection components.
All of these
CRs were
initiated in 1997 or late 1996.
The inspector
concluded that there
was
47
no significant corrective action backlog associated
with the fire
protection program or components.
Also,
as of Hay 6,
1997, there were approximately
22 degraded
or
inoperable fire protection
components.
Host of these
items were related
to degraded fire doors
and the refueling outage which was in progress.
For example,
a number of fire barrier penetrations
were open for passage
of temporary cabling for outage activities
and fire detection
was
removed from service
due to maintenance
work being performed.
The remaining degraded
features
were either in nonsafety-related
areas
or were minor discrepancies
which did not affect the operability of the
system or component.
Host of these
items,
which had been degraded
since
late 1996,
were fire doors.
The inspector verified that appropriate
compensatory
measures
had been
implemented for the degraded
components
where required.
Routine general
inspections of plant areas
are conducted
by plant
'perations
personnel
during operations
rounds in accordance
with the
Plant Overview Program
(POP) Generic
Rounds Guidance,
provided in
Attachment
1 to procedure
OHH-016, Operator
Logs, Revision 10.
Guidance
for inspection of fire protection features
and equipment include:
~
Deficiencies in fire wraps,
Thermo-lag,
and penetrations
~
combustibles
controlled
and documented
per AP-302, Fire
Protection,
Housekeeping,
and Temporary Storage,
Revision
6
~
8ot work in progress
controlled per
Duties of a
Firewatch,
Revision 12;
and FPP-006,
Control of Ignition Sources-
Hot Work Permits,
Revision
16
~
Trouble or alarm conditions
on local fire detection control panels
~
Fire system controls
and actuation
components in order
~
Oily rag cans
are emptied once per day (Day Shift)
The inspector
toured the
RAB on Hay 6,
1997, with the Senior Support
Analyst in charge of Fire Protection
and
a plant Auxiliary Operator
on
rounds within the
RAB.
The inspector
noted that the operator
performed
a thorough general
inspection of the assigned
areas in accordance
with
the fire protection guidelines provided in POP-6.
Within the areas
toured, the fire detection
and suppression
systems
were well maintained
and the material condition was good.
Conclusions
Based
on the inspector's
review of open Condition Reports
(CRs)
on fire
protection
components
and inspection of the fire protection components,
the inspector
concluded that there
was not
a significant corrective
action maintenance
backlog associated
with the fire protection systems'
48
In addition, the material condition of the fire protection
components
was good.
Surveillance
Procedures
for Fire Protection Stand i e and Hose
S
stem'ns
ection Sco
e
64704
The inspector
assessed
the scope of the licensee's fire protection
surveillance
and tests identified in procedure
FPP.;014,
Fire Protection
- Surveillance
Requirements,
Revision 8, to determine
compliance with
FSAR Section 9.5. 1,
and Technical Specifications
(TS).
Observations
and Findin s
The inspector
reviewed
FSAR Section 9.5. 1.2.3, Fire Protection Standpipe
and Hose System,
which described the functional interface of the
emergency service water
system.and
the fire protection system to provide
post-Safe
Shutdown Earthquake
(SSE)
manual fire protection capability in
areas
required for safe plant shutdown.
Valves included in this
section were the seismically qualified check valves
(numbered
and 186;
and 1FP-205,
218.
2079 and 2080) designed to prevent backflow
and outflow to other (non-seismically qualified) portions of the fire
protection water distribution system which may fail during
a seismic
event.
These
check valves were intended to prevent the loss of ESW and
maintain hose line protection after the earthquake.
The inspector
noted
that no surveillance test procedures
existed to verify that the check
valves would perform their intended function.
Technical. Specification 6.8. l.a and Regulatory Guide 1.33, Appendix A.
Section 8.b.l.h,
requi re written procedures
for fire protection
functional tests.
The failure to provide fire protection surveillance
procedures
to verify the functionality of the seismically qualified fire
protection check valves that provide fire protection
and emergency
service water system integrity (following- a SSE) is considered
a
violation of TS 6.8.1.a
(50-400/97-04-08).
Conclusion
A violation of Technical Specification 6.8.1.a
was identified for
failing to establish written procedures
to verify the functionality of
the seismically qualified fire protection check valves that provide fire
protection
and emergency service water
(ESW) system integrity following
an SSE.
This condition had existed since plant commercial operation.
Periodic Surveillance Testin
of Fire Protection Features
and
E ui ment
Ins ection Sco
e
64704
The inspectors
reviewed the following completed surveillance tests:
~
FPT-3560/F,
18 Honth, Fire Wrap Inspection.
Completed
August 13,
1995.
49
~
FPT-3002,
Monthly, Fire Main Valve Position Verification.
Completed April 4, 1997.,
~
FPT-3002,
Monthly, Reactor Auxiliary Building Fire Hose
Rack
Inspection.
Completed
March 27,
1997.
The frequency of selected
sur veillance test procedures
were also
reviewed.
b.
Observations
and Findin s
The surveillance tests
reviewed by the inspectors
had been appropriately
completed
and met the acceptance criteria.
The test procedures,
were
well written and met the fire protection surveillance
requirements of
Fire Protection Surveillance
Requirements,
Revision 8.
A review of the open scheduled
surveillance tests for 1997, indicated
'that approximately
60 percent of the long-term (either quarter ly, six-
month, annually, or 18-month frequency) fire protection surveillance
test procedures
currently scheduled
had not been completed
and have
been
extended into the allowed grace period.
The inspector
considered
the
number of fire protection surveillances
being performed in their grace
period to be excessive.
This issue
was previously identified as
a
weakness
(Wl) in a licensee fire protection assessment,
Nuclear
Assessment
Section Report H-FP-97-01,
dated February 26,
1997.
Licensee
management
was currently evaluating corrective actions to resol.ve this
issue.
There did not appear to be
a formal program for trending fire protection
condition reports
and performance of fire protection system testing.
However, periodic informal interface
between operations
and engineering
personnel
assigned fire protection related functions
was being made to
coordinate the implementation of the fire protection program.
The
surveillance
procedure test data for the capacity tests
on the fire
pumps
and the diesel fire pump oil analysis
data were reviewed by the
plant system engineer.
This data provided good verification of the
pump's performance.
c.
Conclusions
F3
Implementation of the fire protection surveillance
program
has not been
fully effective.
As previously identified in licensee self assessments,
the number of fire protection surveillance
procedures
being performed
within their grace period continued to be excessive.
Fire Protection Procedures
and Documentation
a.
Ins ection Sco
e
64704
The inspector evaluated the adequacy
and implementation of the
licensee's
Fire Protection
Program described in the
FSAR and in Plant
Operating
Manual Fire Protection
Procedure
Fire Protection-
I
+j)
l
50
Conduct of Operations,
Revision 16.
In addition,
a comparison
was
made
of the program to selected
NRC Safety Evaluation Reports which approved.
the station fire protection program.
The inspector
reviewed the
following procedures for compliance with the
NRC requirements-and
guidelines:
Revision 16, Fire Protection
- Conduct of Operations
Revision 13, Fire Emergency
Revision 7, Transient
Combustibles
Tracking
Revision 12, Duties of a Fire Watch
Revision 16, Control of Ignition Sources
- Hot Work
Permits
Revision 2, Fire Pre-Plans
Revision 16, Fire. Protection
- Hinimum Requirements
and
Hitigating Actions
Revision 8, Fire Protection
- Surveillance
Requirements
Revision 4, Fire Protection
and First Aid Team Training
ONN-016, Revision 11, Operator
Logs
Plant tours were also performed to assess
procedure
compliance.
Observations
and Findin s
The above procedures
were the principle procedures
issued to implement
the facility's fire protection program.
These procedures
contained the
requirements
for program administration,
controls over combustibles
and
ignition sources, fire brigade organization
and training,
and
operability requirements
for the fire protection systems
and features.
The procedures
were well written and met the licensee's
commitments to
the
NRC, except that
no surveillance test procedures
existed to verify
the functionality of the seismically qualified fire protection check
valves
as discussed
in section
F2.2 of this report.
The pre-fire plans reviewed by the inspector
were found to be
satisfactory
and proper ly addressed
the fire potential,
area location,
means of fire brigade
approach, fire protection equipment available,
fire brigade action, special
instructions
and hazards to be considered,
operational
safe
shutdown considerations,
and communications available.
A general
plant walkdown inspection
was performed by the inspector to
verify acceptable
housekeeping;
compliance with the plant's fire
prevention procedures
such
as
"Hot Work" permits
and transient
combustibles;
operability of'he fire detection
and suppression
systems;
emergency lighting; and installation
and operability of fire barriers,
fire stops,
and penetration
seals
(used
on fire doors,
and
electrical penetrations).
Within the areas
observed,
the inspector determined that general
housekeeping
was satisfactory,
considering that the unit was in an
extended
outage
and major
maintenance
and repair activities had been
ongoing.
The majority of storage pallets
used during outage activities
were noncombustible
and constructed of'etal.
Fire retardant plastic
C.
sheeting
and film materials
were also being used.
Lubri'cants
and oils
were properly stored in approved safety containers.
Appropriate
controls for cutting and welding operations
were being enforced.
Controls were being maintained for transient
combustibles
and areas
containing potential lubrication oil and diesel
fuel leaks,
such
as the
diesel
generator
rooms.
No discrepancies
were noted with the outside fire hose
houses, fire main
valves or headers.
However, the inspector
noted two isolated bent
sprinkler
head deflector
plates in the reactor auxiliary building
sprinkler piping.
Operability of the sprinkler system
was not impacted
by the bent deflectors since other overlapping sprinklers installed
'ear by were not affected.
The licensee
issued Deficiency Log Entry No.
97-D01184 to identify the problem and initiate corrective actions.
Corrective actions in this area will be reviewed during future
NRC
inspections.
Conclusions
F5
Except for the large
number of fire protection surveillance test
procedures
being performed in the grace period, the fire protection
program implementing procedures
were good
and met licensee
and
NRC
requirements.
The fire fighting pre-fire plans were satisfactory.
Appropriate fire prevention controls were being applied to refueling
outage activities.
Fire Protection Staff Training and Qualification
a.
Ins ection Sco
e
64704
I,
The inspectors
reviewed the fire brigade organization
and training
program for compliance with the
NRC guidelines
and requirements.
b.
Obser vations
and Findin s
The organization
and training requirements
for the plant fire brigade
were established
by FPP-016,
Revision 4, Fire Protection
and First Aid
Team Training.
The fire brigade for each shift was
composed of a fire
brigade leader
and at least four additional
brigade
members.
As of the
date of this inspection,
there were
a total of 72 trained fire brigade
. members of which 39 were from Operations,
21 from Environmental
and
Radiation Control
(ESRC),
and
11 from Haintenance.
The fire brigade
leader
was
a senior
reactor operator.
The other
member s from Operations
were non-licensed plant operators.
The inspector verified that
sufficient shift personnel
were available to staff each shift's fire
brigade with at least five qualified fire brigade
members.
Each fire brigade
member
was required to receive initial, quarterly
and
annual fire fighting related training and to satisfactorily complete
an
annual
medical evaluation
and certification by a physician for
participation in fire brigade fire fighting activities.
In addition,
each
member
was required to participate in at least two drills per year.
j
I t
52
Due to the unit being in an outage
and the high priority work in
progress,
a fire brigade drill was not.conducted. during this inspection.
c.
Conclusions
F7
The fire brigade organization
and training met the requirements of'he
site procedures.
Quality Assurance in Fire Protection Activities
a.
Ins ection Sco
e
64704
The following audit report
and the plant response to the issues
were
reviewed:
~
Assessment
H-FP-97-01 Harris Annual Fire Protection Assessment,
File No.:
HNAS97-011
~
Response
to Nuclear
Assessment
Section Report H-FP-97-01, File No.
NS-970432
b.
Observations
and Findin s
The licensee's
Nuclear
Assessment
Section
(NAS) performed
a two week
.
assessment
of fire protection
on January
13 through 24,
1997.
The
report for this assessment
(Report
No. H-FP-97-01)
was issued
on
January
29,
1997.
Findings from these
assessments
were categorized
as
strengths,
issues,
or weaknesses.
The inspector
reviewed the final report
and the licensee
response to the
identified issues,
dated February 26,
1997.
The assessment
report
identified two issues
and three weaknesses.
The issues identified by
the
NAS assessment
included problems with fire brigade training and
drill schedules
(Issue Il) and engineering
design controls associated
with a design modification that degraded fire protection in the Waste
Processing
Building (I2).
The weaknesses
identified included
insufficient management
oversight
and self-assessment
of the fire
'rotection
program
(Weakness
Wl); excessive
number of fire protection
surveillance
procedures
being performed in their grace period (Wl);
declining material condition of plant fire doors
(W2); and problems with
various types of emergency lighting (W3).
The weaknesses
identified in
the assessment
wer e in close
agreement
with problems
noted during this
inspection
and licensee identified findings such
as
LERs,
CRs, etc.
Planned corrective actions in response to the two identified issues
were
addressed
in the line organization's
response
and were acceptable.
Action on the three weaknesses
which were identified to enhance
the fire
protection program were not addressed
in the line organization's
response to NAS.
Comprehensive
resolution of the weaknesses
of the
NAS
assessment
should provide significant improvement in the implementation
of .the fire protection program at this facility.
53
c.
Conclusions
The 1997 assessment
of the facility's fire protection program
was
comprehensive
and was effective in identifying fire protection program
performance deficiencies to management.
Planned corrective
actions in
response
to the audit issues
were acceptable.
The weaknesses
identified
in the assessment
were in close
agreement
with problems
noted during
this inspection
and licensee identified findings such
as
LERs,
CRs, etc.
F8
Miscellaneous Fire Protection Issues
(92700)
F8.1
0 en
LER 50-400/97-006-00:
Breach in Reactor Auxiliary Building 3-hour
rated fire barrier (Thermo-lag wall in Cable Spread
Room).
This
LER described
a breach in the Thermo-Lag fire barrier wall which
separ ated the "A" train and "B" train cable spread
rooms within the
Reactor Auxiliary Building.
The breach
was identified during
maintenance activities to resolve
a long-standing
Thermo-Lag issue.
Follow-up investigation revealed
an additional
Thermo-Lag fire barrier
deficiency in a floor drain assembly in the cable spreading
room.
These
breaches
made it possible that
a fire in the cable spreading
room could
adversely affect the "A" and "B" train safety-related
cables.
These
conditions did not comply with the 3-hour fire-rated-barrier
requirement
contained in the Harris
FSAR and were determined to constitute operation
outside the design basis of the plant.
The licensee will resolve the
barrier breach via an on-going penetration
upgrade effort prior to
September
15,
1997.
This
LER will remain open pending the licensee's
completion of the upgrade effort.
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 May 15,
1997.
The
licensee
acknowledged the findings presented.
Proprietary information was reviewed during the inspection but is not
contained in this inspection report.
54
PARTIAL LIST OF PERSONS
CONTACTED
Licensee
D. Alexander,
Super visor, Licensing
and Regulatory
Programs
D. Batton, Superintendent,
On-Line Scheduling
D. Braund, Superintendent,
Security
B. Clark, General
Hanager,
Harris Plant
A. Cockerill, Superintendent,
I8C Electrical
Systems
J. Collins, Hanager,
Training
J.
Dobbs,
Hanager,
Outage
and Scheduling
J.
Donahue,
Director Site Operations,
Harris Plant
R. Duncan,
Superintendent,
Hechanical
Systems
W. Gautier,
Hanager,
Haintenance
W. Gurganious,
Superintendent,
Environmental
and Chemistry
H. Hamby, Supervisor,
Regulatory Compliance
H. Hill, Hanager,
Nuclear Assessment
D. HcCarthy, Superintendent,
Outage
Hanagement
B. Heyer,
Hanager,
Operations
K. Neuschaefer,
Superintendent,
Radiation Protection
.W. Peavyhouse,
Superintendent,
Design Control
W. Robinson,
Vice President,-Harris
Plant
G. Rolfson,
Hanager,
Harris Engineering Support Services
D. Shockley, Supervisor,
Configuration Hanager
V. Stephenson,
Hanager,
Rapid Response
T. Walt, Hanager,
Performance
Evaluation
and Regulatory Affairs
NRC
T. Le, Harris Project Hanager,
H. Shymlock, Chief, Reactor
Projects
Branch 4
V
IP 37550:
IP 37551:
IP 40500:
IP 50002:
IP 57080:
IP 60710:
IP 61726:
IP 62700:
IP 62707:
IP 64704:
IP 71707:
IP 71750:
IP 73753:
IP 83750:
IP 90712:
IP 92700:
IP 92901:
IP 92903:
IP 93702:
55
INSPECTION PROCEDURES
USED
Engineering
Onsite Engineering
Effectiveness of Licensee Controls in Identifying, Resolving,
and
Preventing
Problems
Nondestructive Ultrasonic Examination Observation
Refueling Activities
Surveillance
Obser vation
Haintenance
Implementation
Haintenance
Observation
Fire Protection
Program
Plant Operations
Plant Support Activities
Inservice Inspection
Occupational
Radiation Exposure Controls
In-Office Review of Written Reports of Nonroutine Events at Power
Reactor Facilities
Onsite Followup of Events
Followup
- Plant Operations
Followup
- Engineering
Onsite
Response to Events
~0ened
50-400/97-04-01
50-400/97-04-02
50-400/97-04-03
50-400/97-04-04
50-400/97-04-05
50-400/97.-04-06
ITEHS OPENED,
CLOSED,
AND DISCUSSED
Failure to comply with TS 3.0.4 prior to entry into
Hode 6 from defueled condition (Section 01.3).
Three examples of failure to effectively implement
cor rective actions for previous non-conformances
(Sections 04.1, 04.2,
and 08.1).
Failure to establish
and implement procedures
for
using appropriate test equipment
on emergency battery
during discharge test
(Section H2.4).
Inadequate
10
CFR 50.59 safety evaluation for removal
of containment
equipment
hatch missile shields while
in Hode
3 (Section H3.1).
Failure to implement the design veritication
requirements of 10 CFR 50, Appendix B, Criterion III
for safety-related
configuration changes
(Section
El.l).
Failure of workers to promptly leave
a work area
when
their electronic dosimeters
alarmed
as required
by
procedure
AP-535, Section 5.16.5 (Section Rl.2).
.50-400/97-04-07
50-400/97-04-08
Closed
56
Failure to tag and label radioactive material in
accordance
with procedure
HPS-NGGC-0003,
paragraph
9.2, Tagging and Labeling of Radioactive Material
(Section R1.3).
Failure to provide functional testing for seismically
, qualified check valves in the fire protection system
(Section F2.2).
50-400/96-02-03
Use of potenti al ly unconfirmed information
obtained via telecons
in engineering
design work
(Section E8.1) .
50-400/97-007-00
LER
component cooling water system
- technical specification 3.0.3 entry (Section 08.1).
50-400/97-005-00
LER
Failure to perform core flux mapping following plant
operation with reactor
power greater than
100 percent
(Section
08.2)'iscussed
50-400/96-04-04
Tracking
FSAR discrepancy resolution (Section E8.2).
50-400/97-006-00
LER
Breach in reactor auxiliary building 3-hour
rated fire
bar rier (thermo-lag wall in cable spread
room)
(Section F8.1) .
w) ~,,
t
'