ML17333A460
| ML17333A460 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/17/1996 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17333A459 | List: |
| References | |
| 50-315-96-04, 50-315-96-4, 50-316-96-04, 50-316-96-4, NUDOCS 9605290182 | |
| Download: ML17333A460 (40) | |
See also: IR 05000315/1996004
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
REPORT
NO.
50-315 96004'0-316
96004
FACILITY
Donald
C.
Cook Nuclear Generating
Plant
LICENSEE
Company
Donald
C.
Cook Nuclear Generating
Plant
1 Riverside .Plaza
Columbus,
OH 43216
DATES
February
27,
1996 through April 8,
1996
INSPECTORS
B.
L. Bartlett, Senior Resident
Inspector
D. J. Hartland,
Resident
Inspector
C.
N. Orsini, Resident
Inspector
G. Osterholtz,
Operating
License
Examiner
J.
Belanger,
Senior Physical
Security Inspector
J.
Foster,
Senior
Emergency
Preparedness
Analyst
R. Paul,
Senior Radiation Specialist
S. Orth, Radiation Specialist
R.-Glinski, Radiation Specialist
,
APPROVED
BY
~l )
W. J.
Kropgj Chief
Reactor Projects
Branch
3
Date
AREAS
INSPECTED
A routine,
unannounced
inspection of operations,
maintenance,
engineering,
preparation for refueling, plant support,
and review of UFSAR commitments
was
performed.
Safety
assessment
and quality verification activities were
routinely evaluated.
Fol'low-up'inspection
was also performed for non-routine
events.
9605290182
9605i6
AOQCK 050003'
6
PDH
Executive
Summar
OPERATIONS
The inspectors
continue to identify problems with the control
and
use of
procedures
and instructions.
Two of the following examples identified during
this inspection period pertained
to non-routine plant evolutions:
~
Operators
verbatim complied to
a procedure for a non-routine plant
evolution,
even though there
was
a known operator workaround that
resulted
in immediately deviating from the procedure
(Section 1.2).
Procedures
for a reactor
shutdown
and technical specification
surveillance
were revised utilizing the temporary
change
process,
even
though the revisions
changed
the intent of the approved
procedures
(Section 1.3.1).,
~
An approved
process
allowed written guidance to be provided to the
operators
that was outside of plant procedures.
The process
did not
ensure that the additional
guidance
was evaluated for the introduction
of an unreviewed safety question
(Section 1.3.2).
The following operator workarounds
were not identified by the licensee:
During the non-routine evolution of removing the Unit 2 normal
chemical
and volume control
system
(CVCS) letdown flow path from service,
the
operators
had to quickly reopen
the letdown containment isolation
valves to prevent lifting of a safety relief valve,
due to known leakby
of upstream
valves
(Section 1.2).
The automatic design feature of the condensate
booster pumps'inimum
control flow valves is procedurally defeated
during plant operations
due
to the discharge line of the
CBPs being 20" in diameter
and the minimum
flow line being
10" line (Section 3.3).
NAINTENANCE
FHE controls around the fuel handling areas,
general
containment cleanliness,
and housekeeping
were excellent.
Licensee
management
made regular tours of
containment
and the fuel handling areas
and prompt action
was taken to correct
any identified discrepancies
(Section 1.4.2).
There were missed opportunities to ensure that the installation of a
containment jig crane while the unit was at power was properly performed.
The
missed opportunities
consisted of: I) Workers not being attentive for possible
interferences
during initial rotational
checks of the jig crane
and
2) the jig
crane
was not thoroughly inspected
following inadvertent
damage to the crane
(Section 2.2).
ENGINEERING
A review of the technical specification
(TS) surveillances
for the ice
condenser identified the following concerns
(Section 3. 1):
~
The system engineer believed that the allowable ice condenser
bypass
was
50 ft', rather than the allowable
5 ft'Section 3. 1).
~
No tracking mechanism existed to ensure
the
5 ft'esign limit was not
exceeded
(Section 3.2).
PLANT SUPPORT
Radiolo ical Controls (Section 4. 1)
~
Implementation of radiological controls during the Unit 2 refueling
outage
were characterized
by good
RP controls
and careful radiological
work practices.
~
Source term exposure efforts continued to be successful
in reducing
radiation exposure.
~
Concerns
were raised
about workers loitering in the upper containment
during ongoing outage activities.
A tour of the 'auxiliary and turbine buildings
showed
good radiological
housekeeping
and worker
RP awareness.
Control
and Review of Water Chemistr
(Section 4. 1.3)
I
Contaminants
in plant water systems
were generally controlled at or
below the licensee's
aggressive. goals.
4
Periodically elevated
chemistry contaminants
were attributable to oxygen
inleakage into the condensate
system
and the limited capacity of the
~
system.
4
Some weaknesses
in chemistry technician
(CT) performance
were observed,
which was inconsistent with management's
expectations.
ost Accident
Sam lin
S stem
(Section 4. 1.5)
Based
on the
IPAP inspection,
a violation was issued for failure to perform
gC activities in accordance
with procedures.
During this inspection,
the
inspectors identified that
a
CT had difficulty in operating the
PASS in
accordance
with chemistry procedures.
0
4
Chemistr
Labo ator
u lit Control
C
(Section 4. 1.6)
~
Problems
were identified with procedural
adherence
and supervisory
review of gC data.
~
Inconsistencies
were identified concerning
the application of the
gC
program,
which may decrease
the overall effectiveness
of the program.
Emer enc
Pre
ar edness
Pro
ram (Section 4.2)
~
To enhance
the effectiveness
of the
EP program,
a new offsite EOF/ASPIC
facility has
been
purchased
and will be remodeled
(Section 4.2.3).
~
Procedures/drills
for offsite communication of Protective Action
Recommendations
(PARs) were weak in that
a key
EP director had never
had
the opportunity to exercise
his responsibility for this function
(Section 4.2.5).
~
Although identified in previous actions, training was not updated with
information on
NRC and
DOE response
practices
and operational
concepts
for key incident response
personnel.
Additionally, confusion over
initial PARs has not been resolved
(Section 5.0).
~Secnrit
(Section 4.3)
e
~
The security testing
and maintenance
program was well implemented.
The
licensee's'implementation
of a hand geometry
access
control
system
was
considered
good (Section 4.3.2).
SAFETY ASSESSMENT
AND EQUALITY VERIFICATION
Corrective actions for the damaged
fuel grids were thorough
(Section
1.4.1).
The licensee's
control, identification,
and removal of foreign material
in the areas
around the fuel handling operations
was excellent,
and
much
improved over previous inspection findings (Section 1.4.2).
The chemistry self assessments
and quality assurance
audits
were
sufficient in depth
and identified concerns with procedural
guidance,
data review,
and instruments.
Corrective actions to address
the
observations
were developed
and
implemented
(Section 4. 1.7).
Summary of Open
Items
Violations: identified in Sections
1.3. 1, 4. 1.5
and 4. 1.6.
Unresolved
Items:
non identified
Ins ector Follow-u
Items: identified in Sections'4.2.5
and 6.0.
Non-cited Violations: identified in Section
1.2
and 1.4.3.
k
!
4
I
INSPECTION DETAILS
1. 0
OPERATIONS
NRC Inspection
Procedure
71707 was
used in ongoing inspection of plant
operations.
1. 1
Reactor Tri
Due To A Controller Failure
Unit
1
On March 17,
1996, Unit
1 automatically tripped
on low feed flow coincident
with low steam generator level.
All safety
systems
responded
as designed.
The cause
was the failure of the differential pressure
(d/p) controller for
the main feed
pumps.
The licensee initiated
an investigation to determine
the cause of the d/p
controller failure and recent
problems with other controllers.
Other problems
observed,
which have not impacted. the actual
function of controllers,
were
intermittent loss of face plate display
and .loss of the audible
beep
associated
with manual input., Preliminarily, the licensee
believed that the
root cause of some of the problems
was electrostatic
discharge.
As an
immediate action,
the licensed
operators
were instructed to ground themselves
prior to operating the controllers.
The licensee
was also evaluating long-
term actions to eliminate the problem.
The
10 CFR 50.72 report stated
the control
room operators
manually started
the
motor driven auxiliary feedwater
pumps
and that
a "secondary safety" lifted
(implying a steam generator
code safety).
The
NRC identified that the trip
report filled out by the balance of plant operator
indicated that the
pumps
automatically actuated.
Also, the
NRC determined that the valve which
actuated
was
a feedwater/heater
system relief valve, not
code safety.
The licensee
investigated
the discrepancy
and concluded that the
motor driven auxiliary feed
pumps automatically actuated,
and that the shift
technical
advisor misunderstood
the operators'ommunication.
The inspectors
.will further review this event during the review of the associated
licensee
event report
(LER).
1
1.2
Procedural
Adherence
Issue
Unit 2
On March 5,
1996,
the inspectors
witnessed
the.non-routine
evolution of
removing the Unit 2 normal
chemical
and volume control
system "(CVCS) letdown
flow path from service to support repair of 2-QRV-500, the deborating
demineralizer divert valve.
The inspectors
determined that the operators
did
not follow procedure,
02-OHP 4021.003.001,
"Removing Letdown,
Charging
and
Seal
Water
From Service,"
when removing the normal letdown from service.
Procedure,
02-OHP 4021.003.001,
paragraph
2.2. 1, required closing the normal
letdown isolation valves,
the orifice isolation valves,
and the letdown
containment isolation valves
(2-QCR-300
and 2-QCR-301).
After closing these
valves,
the operators
quickly reopened
2-QRC-300
and
2-QRC-301 to prevent the
0
l
1
I
f
lifting of a safety relief valve due to known leakby of the normal letdown
isolation valves
and the orifice isolation valves.
was installed
on
a portion of the piping that
was isolated
when letdown
containment isolation valves
were closed.
During discussions
with the inspectors,
the operators
stated that since the
procedure
was not identified as
an "in-hand" procedure,
verbatim compliance
was not required.
The inspectors
determined
the licensee's
administrative
requirements for procedural
adherence
required that procedures
not designated
as "in hand" must also
be followed.
Since the leakby of the letdown
and
orifice isolation valves
was
a known problem and
was anticipated
by the
operators,
the procedure
should
have
been
changed prior to being performed.
Operations
management initially did not consider this to be
a procedural
compliance
issue
because
operators
needed
to have the flexibilityto deviate
from procedures
for the purpose of placing the plant in a safer configuration.
Since the leakby of the isolation valves
was
known by the operators,
the
inspectors
did not consider this
a valid reason to deviate
from the procedure.
Upon additional
review, the licensee initiated
a condition report to
investigate
the issue of procedure
adherence
and to document that
a
maintenance
action request
had not been initiated for the leaking orifice
isolation valves.
The inspectors
also identified that action requests
were
initiated in Hay 1995 for the leaking letdown isolation valves,
but the job
orders
(which maintenance
workers utilize to perform work on equipment)
had
not yet been written due to the relatively low priority.
The failure to adhere to plant procedures
as required
by 10 CFR 50, Appendix
B, Criterion V, constituted
a violation of minor significance
and is being
treated
as
a Non-cited Violation, consistent with Section
IV of the
NRC
Enforcement Policy. (50-316/96004-03)
The operators'esire
to quickly reopen
the letdown containment isolation
valves to prevent lifting of a safety relief valve,
due to known leakby of
upstream valves
was
a known operator workaround that was not recognized
as
an
operator workaround
by the l,icensee.
1.3
Hanual
Reactor Tri
From 20 Percent
Unit 2
Harch 23,
1996, while shutting
down the plant for a refueling outage,
the
licensee
manually tripped the reactor
from 20 percent
power.
The licensee
originally planned
the manual trip in anticipation that this would be required
in
a soon to be issued
NRC generic communication.
However,
when issued,
NRC
"Rod Insertion Problems,"
dated
Harch 8,
1996, did not require
a manual trip, but rather rod drop testing following a reactor
shutdown.
The
licensee,
however,
decided to still manually trip the reactor
from 20 percent
power to collect true as-found rod drop data.
The licensee
also intended to
use the manual reactor trip to meet the
18 month technical specification
(TS)
surveillance
requirement
(4.8. 1. 1. 1) to verify operability of the auto-
transfer of power from the normal auxiliary source to the preferred
reserve
source.
0
1.3. 1 Procedure
Revision Concerns
Prior to the trip, the inspectors
reviewed the procedural
revisions
issued for
performing this non-routine reactor
shutdown for compliance with regulatory
requirements.
The following procedure revisions
were reviewed:
~
Change
Sheet
3 to procedure
02-OHP 4021.001.003,
"Power Reduction,"
revised
the method of a planned reactor
shutdown
from an orderly reactor
shutdown from power to
a manually reactor trip from a power level that
would result in the automatic starting of engineered
safety feature
equipment
(ESF).
~
Change
Sheet
1 to surveillance
procedure
02-0HP4030.STP.026,
"Auxiliary
Power Transfer Test Surveillance
Procedure,"
revised
when to perform the
TS surveillance.
Instead of performing the surveillance
when the
reactor
was
shutdown
(Mode
5 or 6), the revision allowed the
surveillance to be performed at power
(Mode 1) using
an actual
actuation
(reactor trip).
TS 6.5.3. I.a requires that procedures
which affect plant nuclear safety,
and
changes
thereto,
shall
be prepared,
reviewed,
and approved.
TS 6.5.3. l.e also
requires that
a procedural
change
be reviewed to determine if an unreviewed
safety question exist.
To facilitate implementing
changes
to procedures
that
do not change
the intent of the approved
procedure,
TS 6.5.3. l.a describes
the
use of a temporary
change
process.
These
temporary
changes
deviate
from the
normal review and approval
process
by allowing these
changes
to be approved
by
two members of the pl'ant staff, with at least
one individual holding
a senior
reactor operator license
and allows the safety review, to determine if an
unreviewed safety question exist, to be conducted until
14 days after
implementation of the change.
The inspectors
considered
the above
changes
to
procedures
02-OHP 4021.001.003
and 02-0HP4030.STP.026
as
changes
to the intent
of the procedure
and the temporary
change
process
should not have
been
used.
The
NRC discussed
these
concerns with licensee
management
on March 22,
1996.
In response,
the licensee
revised the procedure
02-OHP 4021.001.00
using the
normal procedural
process,
including the appropriate
safety reviews, prior to
tripping the unit on the following day.
The licensee
canceled
the performance
of surveillance
02-0HP4030.STP.026
due to the time constraint
involved with
the reviews for the proposed
procedural
change.
The use of the temporary
change
process
to issue
Change
Sheet
3 to procedure
02-OHP 4021.001.003,
"Power Reduction"
and
Change
Sheet
1 to surveillance
procedure
02-0HP4030.STP.026,
"Auxiliary Power Transfer Test Surveillance
Procedure"
is
a violation of TS 6.5.3. l.a and
e (50-316/96004-01(DRP)).
1.3.2 Concern with the Process
for Written Guidance to 0 e ators
Plant Managers
Instruction
(PMI) 4090, "Criteria For Conducting Infrequently
Performed Tests Evolutions,"
defines
the controls to allow the use of written
guidance to the operators
which is outside of an approved plant procedure.
PMI 4090 did not ensure that the additional
guidance
was evaluated
for an
unreviewed safety question.
During the planning for the reactor trip from 20
percent
power, the licensee
used the PHI-4090 process
to identify the option
of a manual start of the motor-driven auxiliary feedwater
pumps prior to the
trip.
PHI-4090 required
a screening
in order to provide additional written
information to operators
during certain evolutions.
The inspectors
were
concerned that PHI-4090 did not require that
a safety evaluation
be performed
to ensure that additional
guidance to operators
during infrequent tests
evolutions did not constitute
an unreviewed safety question.
1.4
PREPARATION FOR REFUELING - Unit 2
NRC Inspection'rocedure
60705
was
used to perform
an inspection of the
licensee's
preparation for the planned Unit 2 refueling outage.
This
inspection primarily focused
on the controls
and implementation of core
unloading activities.
1.4. I Dama
e to Fuel Grid Stra
s - Unit 2
On April 3,
1996, while performing
100 percent
in-mast sipping
and visual
examinations
during the removal of the fuel, refueling personnel
identified
that three grid straps
on the fuel assembly
in core location P-'ll were
damaged.
Two of three non-structural
grid straps
had
one entire face removed
and one of the seven structural grid straps
had
a narrow section
(about the
width of two fuel pins)
removed.
No significant damage to the fuel cladding
occurred.
Prior to resuming fuel movement the licensee:
~
Performed
an assessment
of this event.
4
Performed
an examination of the fuel
and searching for the grid straps
that were missing.
P
e
Removed the grid strap piece that was sticking out of the fuel cell that
was in the upender.
Based
on inspection of the damaged
fuel assembly
and interviews of refueling
personnel,
the licensee
determined that the grid damage to the fuel assembly
in core location
P-11 occurred during the removal of the fuel assembly
at core
location R-ll.
Core location R-ll was in the first row of assemblies
removed,
and therefore
was restricted
on three sides during removal.
Two sides
were
adjacent to the core baffle,
and one side
was adjacent to the assembly in
location P-ll.
To ensure that stress
was reduced
on the remaining assemblies
to be removed,
the licensee
revised the unloading pattern.
The
new unloading
pattern would be incorporated
into future outages.
As Unit 2 fuel was thinner
than Unit I fuel, the problems with Unit 2 fuel bowing was more acute.
The
new unloading pattern
was only applicable to Unit 2.
The licensee
did not plan on reusing the once burned
assembly that was the
most damaged.
The other assembly
received minor damaged,
but had already
been
used for three cycles
and was not schedule'd
to be re-used.
The licensee
accounted for all pieces of the grid strap prior to initiating a re-load of
the reactor vessel.
The
NRC observations
of fuel handling activities both before
and after
identification of the
damaged
assembly did not identify any significant
problems.
The licensee's
corrective actions for the damaged grid straps
was
considered
to be excellent.
1.4.2 Forei
n Material Exclusion
Durin
Fuel Handlin
0 erations
The licensee's
control, identification,
and removal of foreign material
in the
'reas
around the fuel handling operations
was excellent,
and
much improved
over previous inspection findings (IR 315/316-95010(DRP).
During
a previous inspection
(IR 315/316-95010(DRP),
the inspectors
had
identified numerous
examples of poor
FHE control around the fuel handling
areas
(e.g.
spent fuel pool, reactor vessel,
refueling cavity, etc).
Based
on
these
examples
the licensee initiated improvements
but,
had not completed all
the corrective actions.
During this inspection period,
the inspectors
observed excellent
FHE control in the containment.
Tight control
was being
maintained over the introduction of materials within the
FHE control
zones
and
regular inspections
and cleanups
were being performed.
In addition to the
FHE controls
around fuel handling areas,
general
containment cleanliness
and housekeeping
were also excellent.
Licensee
management
made regular tours of containment
and the fuel handling areas
and
prompt action
was taken to correct
any identified discrepancies.
Marked
improvement
has
been
noted plant wide in
FHE controls.
1.4.3
S ent Fuel
Pool Radiation Monitors
During a tour of the spent fuel pool
(SFP)
area
and the containment during
fuel handling operations
the
NRC determined
the licensee
had portable
radiation monitors inside containment
but did not have
an operable portable
monitor in the
SFP area.,
The licensee
normally had
a portable radiation
monitor in the
SFP area,
but due to maintenance
the monitor was removed to
replace
the one inside containment.
UFSAR section
14.2. 1. 1 states,
in part, during fuel handling operations:
"In
addition to the area radiation monitor located
on the bridge over the spent
fuel pit, portable radiation monitors capable of emitting audible alarms
are
located in the area during fuel handling operations."
UFSAR section
14.2. 1.2
states,
in part:
"In addition to the area radiation monitors located in the
upper
and lower containment
volumes,
portable monitors capable of sounding
audible alarms
are located in the fuel handling area."
The licensee
did not have
any procedural
requirements
to place portable
radiation monitors inside of containment
and around the
SFP during fuel
handling operations.
This was apparently
due to
a lack of knowledge of the
UFSAR commitment.
Due to good radiological practices
the licensee
made it a
practice of having portable radiation monitors inside containment
but it was
not proceduralized
or occurring in reference
to this commitment.
I'
An additional contributor to the licensee's
failure to identify this
commitment
was the failure to have the commitment in other
UFSAR sections.
For example the commitment
was not contained
in section 9.4,
spent fuel pool,
section 9.7 refueling, nor chapter ll radiation monitoring.
The licensee
committed to revise the procedures
to include the requirement
to have portable
radiation monitors in place prior to fuel movement.
The licensee failed to implement
a commitment in the
However,
since
other monitors were in the area
and operable 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 50-316/96004-05.
Following NRC inspector questioning,
the licensee
began
an assessment
of the
UFSAR requirements
and the area radiation monitors.
The licensee
believed
that the existing radiation monitor on the North wall of the
SFP combined with
the portable monitor located
on the
SFP bridge were adequate
to meet'he
commitment.
However, the licensee
performed
a safety evaluation
and
change
request to use only the portable monitor on the bridge during refueling
operations.
This was completed prior to beginning core re-loading.
1.4.4 Dual Train Outa
e
During a routine review of control
room paperwork,
the
NRC determined
the
licensee
was planning
on performing
a dual train essential
(ESW)
and component cooling water
(CCW) water outage during the Unit 2 refueling
outage.
Due to TS considerations
the licensee's
only work window would occur
while the core
was entirely off-loaded to the
SFP.
However, since
one train
of SFP cooling depended,
upon Unit 2 for power and cooling water, this would
result in only one train of cooling being available to cool the
SFP.
On January
3,
1996,- the licensee
had determined that the practice of having
dual train
ESW and
CCW outages
during
a full core off-load exceeded
the
licensing basis
and that the
UFSAR contained errors which needed
to be
corrected.
Condition report 96-0002
was written as required
by procedure
and
immediate follow-up begun.
The licensee
determined that
as the design basis
would not be exceeded,
the
dual train
ESW/CCW outage
planned for the Unit 2 refueling outage could be
performed provided it was properly approved
through the
10 CFR 50.59 process.
A safety review, engineering
assessment,
and calculation were performed to
verify no unreviewed safety question existed during the plann'ed
dual train
outage.
Subsequently,
due to a change
in the scope of the
ESW outage,
the dual train
ESW outage did not occur.
The licensee
also
was able to isolate the
system for maintenance
work in a manner which resulted
in the need to perform
a dual train
CCW outage to be eliminated.
Unfortunately due to
a
communications error there
was still about
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in which neither train of
CCW was available to cool Unit 2's
SFP cooling train.
A separate
CR was
written to address
the communications failure.
10
The licensee
planned to update
the
UFSAR during the next annual
update
(June,
1996) to resolve the discrepancies
identified in January
1996.
1.5
Closure of LERs - Both Units
Closed
LER 50-315 95003: - Reactor trip due to turbine trip on loss of
vacuum.
This event
was discussed
in Inspection
Report 50-315;316/95009
and
a
violation was issued
(95009-01).
No new issues
were revealed
by the
LER.
Closed
LERs 50-315
95004
50-315
95005
and 50-316
94009: - Loss of 4-loop
injection,
unexpected auxiliary feedwater
pump start,
and engineered
safety
feature ventilation inoperability during surveillance.
These
events
were
reported
based
on discussion
in Inspection
Report 50-315;316/95009
and the
issuance
of a violation (95009-02).
No new issues
were revealed
by the
LERs.
Closed
L
R 50-315 95011: - West centrifugal charging
pump inoperable for six
months
due to personnel
error during relay calibration.
This event
was
discussed
in Inspection
Report 50-315/95014
and escalated
enforcement
action
taken
(95014-Ola).
No new issues
were revealed
by the
LER.
Closed
LER 50-315 96001:
New fuel vault criticality monitor.
This event
was discussed
in Inspection
Report 50-315;316/96002
and
a violation was issued
(96002-01).
No new issues
were revealed
by the
LER.
Closed
LER 50-316
94008
95004: - Reactor trip caused
by turbine trip on hi
moisture separator
reheater level.
These
events
were discussed
in Inspection
Report 50-315;316/95010.
No new issues
were revealed
by the
LER.
Closed
LER 50-316 95005:
Reactor trip from trip of both control rod drive
motor generator
sets
due to mis-adjusted
voltage regulators.
This event
was
discussed
in Inspection
Report 50-315;316/95010
and
a non-cited violation was
issued.
No new issues
were revealed
by the
LER.
Closed
LER 50-316 95006:
Reactor trip on manual
actuation of trip breaker
control switch.
This event
was discussed
in Inspection
Report 50-
315;316/95010
and
a non-cited violation was issued.
No new issues
were
revealed
by the
LER.
2.0
NAINTENANCE AND SURVEILLANCE
NRC Inspection
Procedures
62703,
61726,
and
92902 were used to perform
an
inspection of maintenance
and testing activities.
2. 1
Maintenance
and Surveillance Testin
Activities
The
NRC observed
routine preventive
and corrective maintenance
and
surveillance activities to ascertain
that these
were conducted
in accordance
with approved
procedures,
regulatory guides,
industry codes or standards,
and
in conformance with Technical Specifications
(TS).
The specific maintenance
activities observed/reviewed
are, listed below:
11
002619501
4
004073607
+
001358105
+
004142907
4
003969203
Repack
RHR valve 2-RH-121W
Lift and inspect Unit 2 upper internals
Perform test
on Unit 2 AB Battery
Repair ice 'condenser
bed
Disassemble
and repair pressurizer
power
operated relief valve 2-NRV-163
+
02-OHP 4021.001.003
02-EHP.4030.STP.211
1-0HP.4030.STP.027AB
The specific surveillance activities observed/reviewed
are listed below:
+
02-EHP.4030.STP.211
Ice Condenser
Surveillance
+
1-0HP.4030.STP.027AB
Diesel
Generator
Slow Start
+
02-0HP4030.STP.026
Auxiliary Power Transfer Test Surveillance
Procedure
Power Reduction
Ice Condenser
Surveillance
Diesel
Generator
Slow Start
2.2
H draulic Fluid
S ill Inside Containment
While On Line - Unit 2
On March 8,
1996, during an initial check out of the
new containment jib
crane,
the crane
was inadvertently rotated into an obstruction
and caused
a
suction
hose to the hydraulic
pump to fail.
Approximately 10 gallons of
hydraulic fluid were spilled in containment while Unit 2 was operating.
The
spilled fluid was immediately cleaned
up and
was
performed
and determined that the operability of the
ECCS recirculation
system
was not compromised.
The licensee
repaired
the failed hydraulic hose,
corrected
the interference
and resumed
the check out of the jib crane.
On March 21,
1996,
another spill occurred
when the casing of the hydraulic
pump cracked
and about
8 gallons of fluid leaked into containment.
The
spilled fluid was cleaned
up and the licensee
had the
same operability
concluhions.
The cause of the cracked casing
was stresses
introduced during
the initial failure of the hose.
The
pump was replaced
and the operability
checks of the jib crane continued.
While neither spill caused
equipment to
become
there were missed opportunities to improve performance
in
the installation of equipment while the unit was at power.
The missed
opportunities
consisted of:
Workers paying more attention to possible
interferences
during initial
rotational
checks of new equipment.
The need to perform thorough checkouts of equipment following events
where equipment is inadvertently
damaged.
While the licensee's
immediate actions of cleaning the spilled fluid were
sufficient for the short term, the long term assessment
failed to address
the
RCS chemistry effects.
The initial cleanup consisted
only of wiping the oil
up with rags
and
no chemical
cleaning
was performed.
Subsequently,
while
flooding the reactor cavity for refueling activities personnel
reported
a
small oil sheen
on the water.
On April 16,
1996, with the unit de-fueled
licensee
personnel
initiated
a
CR to document that the initial evaluation did
12
not consider the effect of the oil mixing with the reactor cavity water
and
thus mixing with the nuclear fuel.
The licensee
made the evaluation
a
restraint for entry into Mode 5.
3,0
ENGINEERING
NRC Inspection
Procedures
37550
and
37551 were used. to perform
an onsite
inspection of the engineering
functions.
3. 1
Trackin
of Ice Condenser
8
ass
Paths-
Both Units
The inspectors
had previously identified small instrumentation
openings
in
Unit 1,
between
the upper
and lower containment.
The licensee
stated
since
the openings
were small
and few in number,
the design basis for ice condenser
bypass
was still met.
During a recent tour of upper
and lower containment,
the inspectors
had
more questions
regarding ice condenser
bypass for some
between
upper
and lower containment.
The inspectors
were
informed by the system engineer that the ice condenser
bypass
design basis
was
a 50 ft'.
The inspectors
determined that the design basis
was only 5
ft'ased
on the present
bypass
paths identified between
upper
and lower
containment,
approximately
44 percent of the allowable
5 ft2 ice condenser
bypass
was being used.
The inspector
were concerned
that there
was
no
tracking mechanism to ensure that the design basis for ice condenser
bypass
was met
and that the system engineer did not know the allowable design basis
for ice condenser
bypass.
3.2
Secondar
Side Transients
Unit
1
The air operated
condensate
booster
pump
(CBP) minimum control flow valve
(emergency leak off or
ELO valve)
was designed
to automatically
open
on low
flow to protect the
pump and to close automatically
on higher flow.
The
discharge line of the
was 20" in diameter with the
ELO line being
a 10"
line.
When the
ELO valve opens,
the diverted flow goes to the main condenser.
The use of a 10"
ELO line with a 20"
pump discharge line results
in large
system pressure
and flow perturbations
when the
ELO valves
open or close.
In
an effort to reduce the perturbations,
the operators
modified the procedure to
place the
ELO valves in the open position,
the designed
position during
a
reactor star tup,
and then removing control
power
so the
ELO valve remains
open
during power operations.
This reduced
the number of unexpected
opening
and
closing of the
ELO valve and system perturbations
during plant operations.
On March 19,
1996, with Unit
1 at 30 percent
power in preparation to close the
ELO valve, the breaker for the control
power was closed to the south
ELO
valve in accordance
with the startup
procedure.
However,
when power was
restored
there
was dual position indication for the
ELO valve. Shortly
afterwards
excessive
vibration was felt in the control
room and various
condensate
heater,
and condenser
level alarms flashed in and out due to high
and low indicated level.
Control
power was immediately removed
from the
valve.
Local inspection revealed that the air supply line to the valve had
partially broken off causing
the
ELO valve to rapidly oscillate
and
subsequently
resulted in the air supply completely failing.
Apparently, the
air line had
been loose
and
when power was restored
to the valve the slight
13
opening motion caused
the line to fail.
The piping around the south
CBP was
inspected for damage
and
a condition report was initiated.
One week later on March 27,
1996, with Unit
1 at full power,
another
ELO
valve transient
occurred.
A fitting on the air supply to the middle
ELO
valve developed
a large leak resulting in the valve going from the closed
position to 50 percent
open.
The manual isolation valve was shut, air was
isolated to the
ELO valve and the valve was failed closed.
When the
ELO valve
went
50 percent
open
some flow from the condensate
system
was diverted to the
condenser
and resulted in:
~
An automatic start of the South
~
An automatic start of the East Turbine Auxiliary Cooling Water
Pump
~
A drop in the main feed
pump differential pressure
low
e
High and low level alarms in the three hotwells
1
The operator workaround concerning
the
ELO was not recognized
by the licensee
as
an operator workaround.
This was similar to the licensee's
failure to
recognize the operator workaround discussed
in paragraph
1.2 above.
4.0
PLANT SUPPORT.
NRC Inspection
Procedures
82701, TI 2515/131,
83750,
84750,
82701 were used to
perform an inspection of Plant Support activities.
Announced inspections of
the Emergency
Preparedness,
Radiological Protection,
Chemistry
and Security
were performed
by region based specialists.
4. 1
Radiolo ical Protection
and Chemistr
RP&C
Controls
4. 1. 1 Refuelin
Outa
e Radiolo ical Controls
Unit 2
and
As Low As Reasonabl
Achievable
Pro ram
The inspectors
reviewed work activities
and planning to ascertain
the
effectiveness
of the
ALARA program for this outage.
Included in this
assessment
was
a review of selected
work packages,
ALARA reviews, pre-job
briefings, planning
and scheduling,
and the following jobs in progress:
refueling activities
scaffolding installation
shielding installation
The inspectors
also conducted
tours of the containment,
auxiliary and turbine
buildings
and
had discussions
with workers to determine their understanding
of
job requirements
and dose rates.
e
The Unit 2 outage
dose
goal
was set at about
140 person-rem
(1.4 sievert
(Sv)).
Through day
29 of the outage,
the station
dose
was approximately
135
person-rem
(1.35 Sv) which was about
30 rem (0.30 Sv)
above the projected
dose
14
for that period.
Contributing to the higher dose
was about
10 person-rem
(0. 10 Sv) expended
on additional
work scope
(work not originally scheduled).
An additional
10 person-rem
(0. 10 Sv)
was due to work performed
on valves
and
components with dose rates that were higher than those
found during the
previous Unit 2 outage,
and which were used to make the initial dose
projections.
The licensee
was evaluating the cause of the unexpected
higher
dose rates on'hese
components.
Host of the remaining dose
was attributable
to problems with planning and/or preparation for work, such
as the reactor
vessel
internals lift.
The early boration initiative removed
about
600 curies of cobalt-58 from the
system
and appeared
effective in reducing containment
area
dose rates.
General
area
dose rates
were only slightly higher
than those
found during the
previous Unit 2 outage.
ALARA initiatives included continued
improvement in
scaffolding planning
and scheduling
(a factor of two dose reduction over three
years),
mock up training,
improved tool controls,
and considerable
use of
shielding.
The projected
non-outage
dose for 1996
(32 rem (0.32 Sv)
was twice that
received
in 1995 due in part to scheduled
on-line maintenance
and
modifications.
Although some minor problems
were noted with work planning, radiological
controls in the Unit 2 refueling outage
were generally well implemented
and
there
appeared
to be good radiological
work practices.
Source
term reduction
and shielding efforts continued to be successful
in reducing radiation
exposure,
and
ALARA planning for the large exposure
jobs was generally
thorough.
The dose
expended
to date,
although higher than estimated,
was
reasonable
considering
the added
work scope
and higher than expected
dose
rates.
4. 1.2 Tour of Unit 2 Containment
and Station Auxiliar Buildin
The inspectors
toured various work areas
in the plant
and observed
work in
progress.
Interviews of workers
and radiation protection technicians
were
conducted to determine if the workers were knowledgeable of the radiological
conditions in the work area.
During a tour of the Unit 2 upper containment
the inspectors
and the station
Radiation Protection
Hanager
(RPH) identified one person lying down in a low
dose
area,
other workers leaning
on
a hand rail in an area
posted
" Do Not
Linger," and several
other workers
who appeared
to be loitering.
Dose rates
in these
areas
ranged
from about I to 3 mrem/hr and the
RPH instructed
those
workers
who were not currently performing
a task to move to
a lower dose
area.
During
a tour of the refuel floor, the inspectors
noted that
a portable
ventilation hose taking suction from the hot maintenance
shop
was routed with
about
a
180 degree
bend,
thus creating the potential for reducing the design
air flow.
This matter
was discussed
with the
RPH who had the situation
15
l
0
corrected.
A worker was also identified sitting on
a potentially contaminated
lathe in the hot shop.
After discussing this with the floor RP technician,
the worker was requested
to move.
The tours of the radiologically controlled areas
generally demonstrated
good
radiological
housekeeping
and worker
RP practices,
but raised
a question
concerning
about how'ell persons
who appeared
to be loitering in the upper
containment
were challenged
by
RP and first line supervisors.
The inspectors
observations
were discussed
with the
RPH and plant manager
who indicated these
observations
would be addressed.
4.1.3 Control
and Review of Water Chemistr
The inspectors
reviewed the licensee's
plant water chemistry over the last
12
months,
including the sample collection
and the evaluation/trending
of
chemical
impurities in plant water systems.
Overall, primary and secondary
water quality were well maintained.
The
licensee
implemented
aggressive
goals
(contained
in chemistry procedures)
for
(SG)
and condensate
chemistry impurities.
With the exception
of condensate
oxygen concentrations,
secondary
water chemistry
was maintained
within the licensee's
goals.
Oxygen inleakage resulted
in several
periods of
operation at condensate
oxygen concentrations
of 5-7 ppb, which is above the
licensee's
goal of 2-5 ppb.
The licensee
was
aware of this problem and
indicated corrective actions
were being taken to address this problem.
The inspectors
observed that the concentrations
of chloride
and sulfate
increased
at times
when the opposite unit was undergoing startup
and shutdown.
During startup evolutions,
the chemistry staff indicated that the reverse
osmosis
(RO) makeup water purification system
had
a output capacity that could
not adequately
meet
demands for both units.
The licensee
plans to upgrade
the
RO system to increase
capacity in 1996.
Although chemistry technician
(CT) knowledge
was found to be very good,
the
inspectors
noted
some weaknesses
in the
CTs knowledge of chemistry action
levels
and in the ability to identify data exceeding
those limits.
Prior to
a
chemistry supervisory review, the inspectors
noted that
a CT,
preparing
a
chemistry data
sheet for April 1,
1996, failed to properly indicate
an out of
specification Unit
The inspectors
discussed
this with a different
CT who was not familiar with the meaning of
the licensee's
different limits (i.e. goals, limit, and action levels).
Subsequently,
the licensee
corrected
the data sheet
and obtained
an additional
sample.
The licensee
indicated that this performance did not meet management
expectations
and that these
weaknesses
would be addressed.
Contaminants
in plant water systems
were generally controlled at or, below the
licensee's
aggressive
goals.
The periodically elevated
chemistry contaminants
were attributable to oxygen inleakage
into the condensate
system
and the
limited capacity of the
RO system,
Some weaknesses
in CT performance, were
observed,
which was inconsistent with management's
expectations.
16
4. 1.4
Im lementation
o
the Radiolo ical Environmental Honitorin
Pro
ram
REHP
On April 3,
an inspector
accompanied
a licensee
representative
during
REHP air
and drinking water sample collection.
The inspectors
also interviewed the
REHP staff regarding other sampling activities
and reviewed the
REHP data for
1994
and
1995.
The
REHP sample collection
and analyses
were conducted
in accordance
with the
ODCH.
All omissions
were noted in the reports.
The inspector reviewed recent
data for groundwater tritium originating from the Absorption
Pond,
and
no
adverse
trends
were evident.
Other than groundwater tritium, the
REHP data
for 1994
and
1995 indicated
no radiological
impact to the environment
from
plant operations.
All air samplers
were operational
and within calibration.
The observed
sampling activities were good.
However,
the inspector
noted that the
collector had
some difficulty removing the air filter from the sample
head,
and also that the air sample collection procedure
did not provide any guidance
for the removal of the air particulate filter.
Improper air filter removal
can
have
an effect
on sample integrity.
The licensee
indicated that both the
procedure
and practice
would be reviewed to ensure 'that air filter removal
wa's
proper
and consistent
among the collection staff.
Overall, the
REHP was effectively implemented.
4.1.5 Post Accident
Sam lin
S stem
During this inspection,
inspectors
reviewed weaknesses
in PASS activities that
were identified during the integrated
performance
assessment
(IPAP) documented
in NRC Inspection
Report Nos. 50-315/316-96003,
Section 5.2.
This review,
using procedure
12 THP 6020 PAS.016,
"Post Accident Sampling guality
Assurance,"
revision 2, included assessing
the operability and quality control
(gC) program for PASS.
The inspectors
also observed
a chemistry technician
(CT) obtaining
a
PASS sample.
The inspectors
had identified, during the
IPAP, that the below listed
comparisons
between
the
PASS analyses
and routine analyses
did not satisfy the
licensee's criteria and were not performed at the frequency required
by
procedure
12 THP 6020 PAS.016.
Based
on the inspectors
findings during the
IPAP, the licensee
had issued conditioh reports
(CRs) for. these discrepancies.
~
On August 22,
1995, monthly .boron comparisons
did not meet the
licensee's
acceptance criteria.
Honthly pH, oxygen,
and gas
chromatograph
(GC) samples
were not completed in August 1995.
On
September
5,
1995, the system log book noted that samples
were not
obtained
as the system
was out of service, yet returned to service the
same day.
~
On September
28-29,
1995,
monthly comparisons
for the
GC,
pH,
and
nuclide activity did not meet the licensee's
acceptance
criteria.
A
17
monthly boron comparison
was not completed
in September
1995.
The
system log book indicated that resampling
was not completed
because
of
lack of time.
~
On October 2, '1995,
the monthly comparison for pH did not meet the
licensee's
acceptance criteria.
Honthly comparisons
for the
GC, boron,
and nuclide activity were not performed in October
1995.
samples
for November
and December
1995 monthly comparisons
were discarded prior to analysis.
No resampling
was performed.
Technical Specification (TS) 6.8 requires
a program for post accident
sampling
be implemented
which includes
procedures
to ensure
the capability to analyze
reactor coolant samples.
Procedure
12
THP 6020 PAS.016,
which ensures
proper
PASS system
and instrument functioning for analyzing reactor coolant
samples,
required monthly comparisons
between routine grab samples
and the
PASS system
for the
pH monitor,
oxygen monitor,
GC,
and boron.
The failure to
perform monthly comparisons
as described
above is
an example of a violation of
TS 6.8 (Violation Nos. 50-315/316-96004-02a).
The failure to take corrective
actions for comparisons
outside of the acceptance
criteria,
as required
by
procedure
12
THP 6020 PAS.016, is another
example of a violation of TS 6.8
(Violation Nos. 50-315/316-96004-02b).
Once identified by the inspectors
during the
IPAP, the licensee
performed
some
immediate corrective actions including the counseling of the chemistry
supervisor responsible for the program.
The acting chemistry superintendent
informed the inspectors that the supervisor
was
unaware of the procedural
requirements
and relied
on the experience of the
CT performing the analyses.
The licensee
had also performed several
isotopic comparisons
to calculate
the
system dilution factor, which had not been
performed since October
1,
1993.
The results of those
analyses
indicated
a dilution of about
800 versus
the
1000 the licensee
had
been using.
Additionally, the inspector reviewed the
licensee's
February
1996 comparisons,
which were complete with followup action
taken for analyses
not meeting
acceptance
criteria.
On April 3 and 4, the inspectors
observed
a
CT calibrating the online
pH meter
and collecting of a diluted liquid sample,
respectively.
A tritium analysis
of the diluted liquid sample was.in
good agreement
with a routine grab sample.
Although the
CT had the applicable
procedures
in hand,
the
CT encountered
a
number of problems.
During the liquid sampling,
an inspector identified to
him that
he had inadvertently started
the sample drain
pump instead of
actuating
a system valve.
Additionally, he performed
some steps
out of
sequence
and
had to return to various parts of the procedure
to complete the
process.
As identified in the
IPAP,
weaknesses
were observed
in licensee
oversight of
the
PASS program that resulted
in two examples of a violation concerning
adherence
to procedure
12 THP 6020 PAS.016.
Additionally, the inspectors
identified
a
CT that
had difficulty operating
the
PASS in accordance
with
chemistry procedures.
18
0
4. 1.6 Chemistr
Laborator
ualit
Control
C
The inspectors
observed
laboratory activities,
reviewed pertinent
gC records,
and interviewed laboratory
and guality Assurance
(gA) personnel
regarding
laboratory
gC.
The analytical
areas
reviewed included radiochemistry,
non-
radiochemistry,
and on-line instrumentation.
The implementation of the radiochemistry
gC was good.
The
gC records for
Lower Limit of Detection
(LLD) indicated that the
gamma isotopic analysis
system
was capable of achieving satisfactory
LLDs.
In addition,
the
laboratory demonstrated
excellent radioanalytical capabilities
as evidenced
by
100 percent
agreement
with the vendor cross-check
program in 1995.
However,
the
1996 control charts for all the counting instruments
indicated the
existence of minor trends
and biases,
as defined in Procedure
12
THP 6020
ADM.001, "guality Control," Rev.
0.
The implementation of the non-radiochemistry
gC was adequate.
The inspectors
noted that the laboratory
was well equipped
and the licensee
had established
a
computer-based
system
(CDMS) to track the
gC performance of the instruments.
However, the lab staff recording of gC data into the
CDMS was inconsistent.
Another
gC data inconsistency
pertained to the use of performance
check data
from analyses
that were considered
non-regulatory.
In these
instances,
the
performance
check data
was
used only if the data point indicated
a problem
with the instrument,
but not if the data point was acceptable.
Therefore,
the
inclusion of these
data points in the
gC program was not uniform.
The inspectors
reviewed
gC data for the past six months for chloride
and
sulphate
analysis
on the ion chromatographs
and noted
a number of biases
and
trends
which were not evaluated
and recorded
as required
by Sections
6.2.4
through 6.2.7 of 12
THM 6020 ADM.001, "guality Control,
Rev.
0.
~
Chloride performance
checks
on instrument
I04 indicated
two biases
and
one trend from October
1995 to April 1996.
~
Chloride performance
checks
on instrument
I06 indicated
two biases
and
one trend from October
1995 to April 1996.
~
Sulphate
performance
checks
on instruments
I04 and
I06 indicated
one
and
two biases,
respectively,
from October
1995 to April 1996.
The lack of procedural
adherence
in the evaluation
and documentation of this
gC information is
an example of a violation of TS 6.8, which requires,
in
part, that procedures
be implemented
as
recommended
in Regulatory
Guide 1.33,
Appendix A (Violation Nos. 50-315/316-96004-02c).
The
gC for online instrumentation
was good.
The licensee
conducted
performance
checks 'in accordance
with gC procedures.
However, there
was
an
inconsistency
in the procedural definition of acceptance
criteria for the
gC
data.
Attachment
3 of Procedure
12 THP 6020 ADM.003, "Online Instrument
guality Control,"
Rev 1, indicates that the acceptance
criteria for hydrazine
is +/- 15 percent for "As Found"
and +/- 10 percent for "As Left."
The
19
inspectors
noted that hydrazine
gC data
on January
26,
1996 exceeded
these
criteria,
and there
was
no indication of corrective action,
as stated
in
Section 6.3.4.
The licensee
indicated that the procedure
required corrective
action only for regulatory parameters
and that this procedure
would be
reviewed to clarify the use of acceptance
criteria for non-regulatory
parameter
analyses.
Laboratory
gC was good, with the exception of procedural
adherence
and
supervisory review of gC data.
An example of a procedural
adherence
violation
was identified regarding the review of control charts.
In addition,
inconsistencies
were identified concerning
the application of the
gC program,
which may decrease
the overall effectiveness
of the program.
4. 1.7* Review of Chemistr
Self Assessments
and
ualit
Assurance
Audits
During the inspection,
the inspectors
reviewed chemistry guality Assurance
(gA) activities.
The chemistry staff, with assistance
from a gA auditor,
performed self-assessments
of selected
chemistry program elements
during the
past six months.
For the elements
reviewed,
the self-assessments
had
sufficient depth
and contained
several
good observations
concerning procedural
guidance
problems,
data review deficiencies,
and instrument issues.
Corrective actions to address
the observations
were developed
and implemented.
However,
as discussed
in the
IPAP inspection,
the self-assessments
were not
effective in ensuring the
1993
and
1994 self-identified problems with
chemistry sampling
and
gC were resolved.
4.2
0 erational
Status of the
Emer enc
Pre aredness
Pro
ram
4.2.1 Actual
E er enc
Plan Activations
An Unusual
Event was declared
at 11: 15 a.m.
on Nay 5,
1995 when
a review of
past inservice inspection
examinations
determined that the ultrasonic
examination
procedure
used to inspect Reactor Coolant
System branch connection
welds was inadequate
to meet welding code requirements.
As such,
the
requirements
of Technical Specification (TS) 4.0.5
had not been
met for
emergency
core cooling systems,
and
a reactor
shutdown
was required per TS 3.0.3.
The Unusual
Event was terminated
at 1: 10 p.m. the
same date
when
an
indicated the reactor
shutdown
was overly
conservative
and other means
were available to resolve the nonconformance.
An Unusual
Event was declared
at 1:00 a.m.
on August 20,
1995,
due to an
explosion in the phase
2 main transformer output bushing.
The transformer
was energized
but not providing power when the explosion occurred.
The
Unusual
Event was terminated
at 1:50 a.m.
on the
same date.
An Unusual
Event was declared
and terminated
at 11:55 a.m.
on August 22,
1995,
due to
a fire on the auxiliary building roof.
The fire, caused
by
roofing
repairs,
was extinguished within eight minutes.
The Unusual
Event was
terminated at the
same time as it was declared,
as the fire was extinguished
by that time.
20
Records
reviewed indicated that classification
and notifications had
been
made
properly and in
a timely manner.
Documentation for the events
were complete,
and technically correct.
A formalized procedure did not exist for
standardized
review, critique,
and tracking of corrective actions related to
actual
emergency
plan activations.
4.2.2
mer
e
c
P
a
nd
Im lementi
rocedures
The licensee
had submitted
a revision to the
Emergency Action Level
(EAL)
scheme
devised
by the Nuclear Management
and Resources
Council
(NUHARC).
This
submittal
was under review by the
NRC at the time of this inspection.
When
approved,
procedure
and training changes will be needed
to implement the
new
EALs.
The inspector reviewed
a representative
sample of Emergency
Plan
Implementing
Procedures.
No problems
were identified.
4.2.3
Emer enc
Res
onse Facilities
E ui ment
Instrumentation
and
Su
lies
Tours were conducted
through the Technical
Support Center
(TSC), Operations
Support Area
(OSA),
and
Emergency Operations Facility (EOF).
Each facility
was well maintained
and in an excellent operational
state of readiness.
Current copies of the Emergency
Plan,
Emergency
Plan
Implementing Procedures
and appropriate
forms were present
in each facility.
The field monitoring
team van was inspected,
as well
as field monitoring kits intended to be
utilized for field teams.
All inspected
items were in good material
condition.
A building has
been
purchased
in the town of Buchanon,
Michigan, to house
the
EOF and Joint Public Information Center (JPIC),
as well as individuals from
the Columbus,
Ohio, corporate office.
Inspection of the building indicated it
has
adequate
room for both functions.
Layout of both facilities was yet to
be determined.
Documents
reviewed indicated that emergency
equipment inventories
and
maintenance
were very good, with timely corrective actions
taken where
deficiencies
were identified.
No problems or concerns
were identified.
4.2.4 Or anization
and
Mana ement Control
The overall organization
and management
control of the
EP function was largely
unchanged
from the last inspection,
except that the
EP staff now reported to
the Site Vice President.
The possibility was discussed
that one of the corporate staff would join the
plant
EP staff.
This would consolidate
EP functions in one location
and aid
with the current
EP workload (relocation of the
EOF,
revisions
and training, routine program maintenance, drills, exercises,
Severe
Accident Management
implementation).
21
4.2.6 ~Trainin
Records indicated that drills and exercises
were formally critiqued, training
had
been provided
on formal critiques,
and significant critique items were
appropriately selected for corrective action.
Printouts
from the training tracking systems
were compared with
"Emergency
Call List," with no problems identified.
The
EP staff had proactively
recognized that
some personnel
with emergency
response
positions would be
leaving the organization,
identified their positions
on a'imely basis,
and
were in the process of selecting
and training replacements.
The results of interviews with two key emergency
response
persons
were
generally good.
Very good knowledge of emergency responsibilities
and
activities were generally evident during these
interviews.
The inspectors
interviewed
an individual assigned
as Technical
Support Center
Director (TSCD) that
had initial training and participated
in three drills.
During the training the
TSCD had not been required to perform offsite
communication related to classification
changes
and Protective Action
Recommendations
(PARs) during
TSC drills.
The inclusion of objectives in
periodic
TSC drills to develop
and perform offsite communications relating to
PARs will be tracked
as
an Inspection
Followup Item 315/316/96003-04.
Review of EP training records
and documentation
revealed that excellent
training appeared
to be provided to emergency
response
personnel.
A sample of
lesson
plans
was reviewed.
No concerns
were identified.
4.2.6 audits
The inspector
reviewed Nuclear Safety
and Design Review Committee Audit No.
220,
"Emergency Plan," dated April 6,
1995.
The audit resulted
in four
Condition Reports,
ten recommendations
and four Points of Information.
The
audit concluded that the
"Cook Plant
Emergency
Plan is being effectively
carried out," and noted
many positive program qualities.
Also reviewed
was Plant Performance
Assurance Audit No. (A-96-02,
"Emergency
Planning
and Preparedness
(PHI-2080)," dated
Harch 20,
1996 performed during
January
15 - Harch 7, 1996.
This audit was performed
by five individuals and
concluded that adequate
controls were established
to effectively implement the
program.
Two recommendations
and three points of information were associated
with the audit.
The audit was complete
and well detailed.
The
1996 audit was weak in the area of assessment
of the interface with
offsite authorities,
(the
1995 audit was very detailed
in this area)
but noted
that
a subsequent
surveillance
would be conducted
in this area.
The
1995
and
1996 audits of the
EP program satisfied the requirements
of 10 CFR 50.54(t) with respect
to scope.
Records
also indicated that the
EP staff
fulfilled the requirement
to make relevant
1995 audit results available to
State
and county officials in 1995.
22
4.2. 7
Commun cati o s
2515
131
The Emergency
Plan,
section
12.3.7
"Emergency Communications,"
section
12.3.7.2," Off-Site Communications,"
described
the various communications
systems
available for offsite communications.
These
included:
1. microwave system
2. V.H.F. radio system
3. telephone lines
The following telephone
systems
were discussed
with licensee
personnel:
1. Fiber optic line to Benton"Harbor via microwave link
2. Fiber optic line to Fort Wayne
3. Fiber optic line to the training center
4. Fiber optic line to Columbus
5. Fiber optic line to
GTE
Fiber optic lines were described
as buried in some areas,
but came to the
surface
and shared
a
common manhole
system.
All lines
came into
a
common
room
located
on the second floor of the lakeside office building,
an inside
room
without windows.
A router was available which would switch calls to operable
lines in case of individual line failures.
Battery backups for fiber optic
lines
had
an
assumed
capacity for 4-5 hour operation.
Three chargers
maintained
the battery system.
A low-frequency radio transmitter with an 8-hour uninterruptable
power system
(UPS) (including diesel
backup)
was utilized by Security personnel.
Equipment
for this system
was located at the
595 foot elevation,
in the underground
security equipment
room.
System
antennas
were
on the turbine building roof
'nd
a
UHF radio was
used to communicate with the Berrien County Sheriff,
utilizing the
same
UPS.
Control point consoles for this system include the
Central
Alarm Station,
Secondary
Alarm Station,
and Control
Room.
An offsite repeater
system
was present
at the microwave tower,
equipped with
propane
powered generator
backup power.
Control points for this system were
located at the
OSA and
EOF.
The
EOF microwave link could control the repeater
and function like a mobile unit.
Seven
company cellular telephones
were
available,
assigned
to management
and on-call personnel.
Discussion
indicated that there
was
no formalized procedure for actions to
take in the event of a major communications failure.
However,
a comprehensive
package of information, "E-Plan Communications,"
had
been developed to aid in
evaluating/restoring
communications
in case of major damage to the microwave
tower or
PBX room.
Line drawings of the various
systems
were included in the
package.
This documentation
package,
prepared
due to findings in a previous
drill or exercise,
described
which systems
would remain after various failures
(microwave tower or
PBX switchroom).
Procedure
PHP 2081
EPP.207,
"Barring of PBX," provides for actions to modify
the plant Private Automated
Branch
Exchange
(PBX) to eliminate direct
communications
between
selected
plant and all offsite telephones.
The
23
Administrative Coordinator is responsible for implementing this procedure,
which directs telecommunications
personnel
or the Security Director to bar the
PBX.
Barred telephones
cannot initiate outgoing calls, limiting
communications
to those
needed
in an emergency.
The overall status of the emergency
preparedness
(EP) program was very good.
Response facilities were in an excellent state of operational
readiness.
The
1995
and
1996 Audits of the
EP program were very good,
and satisfied the
requirements
of 10 CFR 50.54(t).
The
1996 evaluation of the interface with
offsite authorities
was pending surveillance
completion.
A concern
was
identified relative to Technical
Support Center drill objectives.
Emergency
communications capability was reviewed.
No UFSAR deviations
were identified.
4.3
~Secerit
NRC Inspection
Procedure
81700
was
used to perform an inspection of plant
support activities.
The licensee's
testing,
maintenance,
and compensatory
measures
programs
were well conducted,
ensuring
the reliability of physical
protected related
equipment
and security related devices.
4.3. 1 General
Overview
The licensee
employed
compensatory
measures
in accordance
with approved
security plan commitments
when equipment failed or its performance
was
impaired.
Those licensee
personnel
responsible for maintaining security
systems
demonstrated
pride and ownership.
Significant decreases
in the number
of security equipment
and personnel
error
safeguards
loggable events
were
noted during the first quarter of 1996.
The licensee
properly installed
and
effectively implemented
a hand geometry protected
area
access
control
system.
Improvement
was noted in the efforts to reduce the number of vital area
tailgating incidents.
The licensee
declared
the physical
installation of the vehicle bar rier system
upgrades
required
by 10 CFR 73.55
(C)(7) for protection against malevolent
use of vehicles at nuclear
power
plants
on February
23,
1996
4.3.2 Biometrics
Hand Geometr
S stem
On December
18,
1995,
the licensee
implemented
a biometrics
hand geometry
access
control
system at the entrance
to the protected
area.
By letter dated
December
15,
1995, the
NRC granted
the licensee
an exemption to
badging requirements
relating to the issuance,
storage
and retrieval of
picture badges for individuals who have
been granted
unescorted
access
to the
protected
area;
Specifically, the exemption allowed individuals to keep their
picture badge in their possession
when departing the site.
The
NRC observed
that the
new system functioned well.
5.0
Follow-u
on Previousl
0 ened
Items
A review of the following previously opened
inspection
items
was performed
using Inspection
Procedure
92901.
0
l
4
I
V
'l
'll
0 en
Ins ection Followu
Item No.
315 94019-02: Training modules for key
incident response
personnel
did not contain information relative to the
NRC
Incident Response
Program nor that of the Department of Energy.
A training
session
had
been
conducted
on this information, but the training module
had
not had this material
included.
This item will remain open.
Closed
Ins ection Followu
Item No. 50-315 94019-01:
Procedure
12
THP 6010
RPP.009
(Rev.8),"Emergency
Equipment Inventory" provided for monthly
inventories
but specific numbers of supplies or other equipment
were not
provided for inventory purposes.
Minimum quantities of supplies or equipment
had
been
added to the inventories.
This item is closed.
0 en
Ins ection Followu
Item Nos.
50-315 95007-02
50-316 95007-02:
During
the
1995 Exercise there
was confusion over the initial protective action
recommendation
(PAR).
Verbal communication erroneously
referenced
a
PAR of
sheltering.
The
EOF manager called the State
and clarified the issue,
but
confusion over the
PAR continued for some time.
verbal
communication of
Protective Action Recommendations
to the State of Michigan.
This also
occurred during
a drill.
A consultant
was commissioned
to review the
communication
process
and
recommend corrective actions
as necessary.
This
item will remain
open.
Closed
Ins ection Followu
Item Nos.
50-315 95007-01
50-315 95007-01:
During the
1995 Exercise,
there
was
no organized or structured debriefing
process for returning inplant response
teams.
A simple form (exhibit
H to
procedure
PMP 2081
EPP.203)
had
been developed
to guide the debriefing
process.
The form had
been utilized in several drills with good results.
This item is closed.
Closed
VIO 50-315 316-95011-01
DRS:
Review licensee corrective actions
addressing
an event in which an access
control clerk incorrectly identified
a
contract
employee
as having been tested
and reported
as negative for chemical
substances.
The clerk failed to properly use information provided to prevent
misidentification.
As
a result of this failure, the contract
employee
worked
with unescorted
access
status
in the plant protected/vital
area
from August
19
through August 22,
1995.
The
NRC verified that the corrective actions listed in the licensee's
dated
November
15,
1995 to the apparent violation.
These actions
appear to be
effective and here
was
no recurrence
of these
events.
This item is closed.
0 en
IFI 50-315 316-95012-03
Review licensee
actions
addressing
inspector concerns
about
an adverse
trend in the number of tailgating
incidents during the second
and third quarters of 1995.,
Heightened
employee
awareness
of the functioning of the
new security card
reader
system
and continued senior
management
attention to this issue
indicated
improvement in this area.
There were three tailgating incidents
recorded during the first quarter of 1996.
Two of the incidents
were related
to ignorance of the functioning of the system
by employees
with infrequent
site access.
The third was related to an employee
who believed that
he had
received authorization into an area.
25
The licensee
thought that similar incidents with the old card reader
system
occurred,
but that the old system
was incapable of identifying such
occurrences.
6.0
Rev'iew of UFSAR Commitments
A recent discovery of a licensee
operating
a facility in a manner contrary to
the Updated Final Safety Analysis Report
(UFSAR) description highlighted the
'need for a special
focused review that compared plant practices,
procedures
and/or parameters
to the
UFSAR description.
While performing the inspections
discussed
in this report,
the
NRC reviewed the applicable portions of the
UFSAR that related to the areas
inspected.
The following inconsistencies
were
noted
between
the wording of the
UFSAR and the plant practices,
procedures,
and/or parameters
observed
by the
NRC.
~
During a tour of the spent fuel pool
(SFP)
and containment
areas,
the
NRC determined
the licensee
had portable radiation monitors inside
containment
but did not have
an operable portable monitor in the
area.
(Section 1.4.2)
(50-315/96004-05)
The licensee
had determined that the practice of having dual trai'n
and
CCW outages
during
a full core off-load exceeded
the licensing basis
and that the
UFSAR contained errors which needed
to be corrected.
(Section 1.4.4)
(50-315/96004-06)
7.0
Heetin
s and Other Activities
The
NRC contacted
various licensee
operations,
maintenance,
engineering,
and
plant support personnel
throughout the inspection period.
Senior personnel
are listed below.
At the conclusion of the inspection
on April 16,
1996, the
NRC met with
licensee
representatives
(denoted
by *) and summarized
the scope
and findings
of the inspection activities.
During this inspection de-briefings
were held
periodically with licensee
management.
Some of the persons listed below were
present for only some of the'e-briefings.
The licensee
did not identify any
of the documents
or processes
reviewed
by the
NRC as proprietary.
- A. Blind, Site Vice President
- J. Sampson,
Plant Manager
- K. Baker, Assistant Plant Manager
- D. Noble, Radiation Protection Superintendent
- T. Postlewait,
Site Engineering
Support Manager
- J. Wiebe, Superintendent,
Plant
Performance
Assurance
- W. Hodge,
Plant Protection Supervisor
- J. Allard, Maintenance
Superintendent
- P. Schoepf,
Plant Engineering
Superintendent
- T. Beilman, Scheduling
Superintendent
- H. Hierau,
STA Supervisor
26
t
'L
0
- D. Londot,
ICS Supervisor
- M. Ackerman,
Licensing Supervisor
- J. St.
Amand, Plant Engineering Supervisor
- R. West, Licensing Coordinator
- R. Ptacek,
Licensing Coordinator
- D. Hafer,
NED Engineering Supervisor
- R. Krieger,
Emergency
Preparedness
Coordinator
- E. Fitzpatrick, Senior Vice-President
Nuclear
27
4l
0