ML17328A531
| ML17328A531 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 12/06/1989 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A529 | List: |
| References | |
| REF-GTECI-093, REF-GTECI-NI, TASK-093, TASK-93, TASK-OR 50-315-89-29, 50-316-89-29, GL-88-03, GL-88-3, NUDOCS 9001100070 | |
| Download: ML17328A531 (34) | |
See also: IR 05000315/1989029
Text
e
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports
No. 50-315/89029(DRP);
50-316/89029(DRP)
Docket Nos. 50-315;
50-316
Licensee:
Company
I Riverside Plaza
Columbus,
OH
43216
Licenses
No. DPR-58;
Facility Name:
Donald C. Cook Nuclear Power Plant, Units I and
2
Inspection At:
Donald C.
Cook Site,
Bridgman, Michigan
Inspection Conducted:
October
4 through
November 16,
1989
Inspectors:
B. L. Jorgensen
E.
R. Schweibinz
R. A. Paul
D. G. Passehl
Approved By:
B. L. Burgess,
Chief
Projects Section
2A
a
e
Ins ection
Summar
Ins ection
on October
4 thru November
16
1989
(Re ort No. 50-315/89029(DRP);
0 ~
Areas
Ins ecte
Routine unannounced
inspection
by Regional
and resident
inspectors
o
actions
on previously identified items; plant operations;
radiological controls; maintenance; -surveillance; security; safety assessment/
quality verification; engineering
and technical
support; reportable
events;
Bulletins, Notices
and
Gener ic Letters; Allegations; and,
NRC Region III
requests.
In addition,
on November 16, 1989,
a Management
Meeting was
conducted
in NRC Region III, to discuss
operations
and management
issues
and
a second
meeting
was conducted
regarding
licensed operator training.
The
'following Safety Issues
Management
System
(SIHS) items were reviewed, with the
indicated results:
(Open) Generic Safety Issue
GSI 93 and Generic Letter
GL-88-03 concerning
steam binding of auxiliary feedwater
pumps.
Results:
Of the
13 areas
inspected,
no violations or deviations were identified
~sn
areas.
One violation was identified (Level iv - operation
in MODE
1 with
neither
ECCS subsystem
OPERABLE - Paragraph
10.g) in the remaining area.
The inspection disclosed
weaknesses
in the licensee's
control of work activities,
~
~
~
~
~
~
~
~
to ensure
such activities are confined to a single safety "Train."
This is
reflected in the Notice of Violation and was the focus of the November 16, 1989,
Management
Meeting.
900ll00070
891206
ADOCK 05000315
Q
DETAILS
1.
Persons
Contacted
a.
Ins ection:
October
4 - November
16
1989
"A. Blind, Plant Manager
"J.
Rutkowski, Assistant Plant Manager,
Technical
Support
L. Gibson, Assistant Plant Manager,
Projects
"K. Baker, Assistant Plant Manager,
Production
B. Svensson,
Executive Staff Assistant
J.
Sampson,
Operations
Superintendent
E. Horse,
gC/NDE General
Supervisor
T. Beilman, Maintenance
Superintendent
"J. Droste, Technical
Superintendent,
Engineering
T. Postlewait,
Design Changes,
Superintendent
L. Matthias, Administrative Superintendent
J. Wojci k, Technical
Superintendent,
Physical
Sciences
H. Horvath, equality Assurance
Supervisor
D.
Loope, Radiation Protection Supervisor
The inspector also contacted
a number of other licensee
and contract
employees
and informally interviewed operations,
maintenance,
and
technical
personnel.
"Denotes
some of the personnel
attending the Management
Interview on
November 17,
1989.
b.
Mana ement Meetin
- November
16
1989
Licensee
H.
P. Alexich, Vice President,
Nuclear Operations
A. A. Blind, Plant Manager
P.
A. Barrett, Director of equality Assurance
S. J.
Brewer, Nuclear Safety
and Licensing
K.
R. Baker, Assistant Plant Manager,
Production
NRC
H. J.
Clausen,
Deputy Director, Division of Reactor
Projects
W.
L. Axelson, Chief, Projects
Branch
2
B.
L. Burgess,
Chief, Projects
Section
2A
B.
L. Jorgensen,
Senior Resident
Inspector
E.
R. Schweibinz,
Project Engineer
2.
Actions on Previousl
Identified Items
92701)
As a result of a special
safety inspection
conducted
by an
NRC
Augmented Inspection
Team (AIT) documented
in NRC Inspection
Reports
No. 50-315/89025(DRSS);
No. 50-316/89025(DRSS),
and concerning
the
0
Qi
Unit 2 reactor trip of August 14, 1989, the licensee
responded
to the
four issues identified in Paragraph
9 of the inspection report by a
letter
(AEP:NRC: 1090J)
dated October 25,
1989.
Item 9.a:
The failure mode of the silicon controlled rectifier (SCR 209)
was confirmed as
random.
1
Item 9.b:
The loads supplied
by all CRIDs have or will have electrical
independence
such that
a failure of a single
CRID will not cause
a loss
of all channels
of some parameter
(such
as
wide range
level indication) monitored in the control
room.
Item 9.c:
Engineering guidelines
are in place
and
a procedure will be
issued for testing
GRID Inverters prior to switching from the alter nate
to normal
power supplies.
The preventive
maintenance
procedure
in effect
for the
CRID Inverter will be expanded
to include the Static Transfer
Switch.
,
Item 9. d:
Finally, training was upgraded
on operation of the
Mitigating system actuation circuitry) system.
The inspector
had
no further questions
on these matters.
They are
considered
closed.
No violations, deviations,
unresolved
or
open items were identified.
0 erational
Safet
Verification
71707
71710
42700)
Routine facility operating activities were observed
as conducted in the
plant and from the main control
rooms.
Plant startup,
steady
power
operation,
plant shutdown,
and system(s)
lineup and operation were
observed
as applicable.
The performance of licensed
Reactor Operators
and Senior Reactor Operators,
and of auxiliary equipment operators
was
observed
and evaluated
including procedure
use
and adherence,
records'and
logs,
communications,
shift/duty turnover,
and the degree of
professionalism
of control
room activities.
The Plant Manager, Assistant
Plant Manager-Production,
and the Operations
Superintendent
were well-
informed on the overall status
of the plant,
made frequent visits to the
control
rooms,
.and regularly toured the plant.
Evaluation; corrective action,
and response
to off-normal conditions or
events, if any, were examined.
This included compliance with any
reporting requirements.
Observations
of the control
room monitors, indicators,
and recorders
were
made to verify the operability of emerge'ncy
systems,
radiation monitoring
systems
and nuclear reactor protection systems,
as applicable.
Reviews
of surveillance,
equipment condition,
and tagout logs were conducted.
Proper return to service of selected
components
was verified.
Both Unit 1 and Unit 2 were. in continuous routine power operation
throughout the inspection period.
Operation
was at full rated power
with a few brief exceptions of reduced
power operations
to permit
- inspection or maintenance
of the main feed pumps.
On October 12, 1989,
a non-licensed, auxiliary equipment operator
(AEO) assigned
to the Unit 1 turbine building tour was discovered to
have logged activities (area inspections)
which were not performed.
A pattern of increasing
nonperformance
over the preceding
week was
identified via cross-checks
between tour logsheets
and computerized
access
records.
The individual was discharged effective October 16,
1989.
An audit of required tour performance
by numerous other AEO's
identified occasional
discrepancies
but no chronic problems.
The
licensee
enhanced
monitoring of the area
and evaluated
programmatic
changes
to clarify how tours are to be performed
and logged.
Minimum shift crew requirements
were not violated.
However, the
inspector identified that the
AEO described
above failed to make
some checks
committed to in the licensee's
response
to Generic Letter 88-03 (e.g.,
see
Paragraph
11).
The licensee's
procedure
(OHI-4013, "Operators:
Authorities and
Responsibilities" ) for shift operations
and duties,
however,
was
violated.
Since adherence
to this procedure
is
a requirement of
Technical Specification 6.8. l.a, through reference
to Regulatory
Guide 1.33,
Appendix
A - 1972, failure to perform the specified
area tours is considered
a violation of the referenced
Technical
Specification.
This violation was identified and corrected
by the licensee.
It was
not highly safety significant, nor was it repetitive of previous
violations.
In accordance
with normal practice
as established
in
the
NRC Enforcement Policy (10 CFR2, Appendix C) no Notice of
Violation is being issued
on this matter.
Some additional
NRC
reviews to verify corrective actions
and associated
issues
is
anticipated.
On NovemberlO,
1989, the licensee
determined that
a previously
identified problem, which was undergoing
an engineering
and safety
evaluation,
represented
a condition outside the plant design basis
and was reportable.
Required notifications were made.
The problem is described further in Paragraph 6.f of this inspection
report and involved a licensee
Inservice Test (IST) of the Unit 2
Turbine Driven Auxiliary Feedpump.
Twelve hour operating shift schedule
has
been developed.
The Target
date to have this in effect is January
1, 1990.
The inspector
was
provided with a draft rotation schedule
encompassing
a 15-week cycle
of 8-hour training shifts and 12-hour operating shifts.
Overtime
backup
was considered
in the schedule.
The inspector discussed
the
need to consider
two issues
in implementing the revised rotation.
First, administrative control of overtime will need to be considered
and, if necessary,
changes
made in the methods for assuring
compliance to applicable limitations.
Second,
commitments
and
schedules
which currently specify three-times-per-day
activities
will need review and appropriate
adjustments.
The licensee
is developing
a computerized
"clearance
permit" database
system,
which the inspector
reviewed.
The ultimate goal is to
produce
an automatic
system,
providing the user with an extensive
detailed
summary of individual components
and systems.
The database
will supply the information necessary
to tag out entire systems,
subsystems,
or components.
It will have the capability to
cross-check for other clearances
written on equipment with a
pre-existing clearance.
A control
room team
has investigated all control switches in both
units'ontrol
rooms, verifying the switches against existing plant
data,
drawings,
and other information applicable to the particular
control.
Computer generated
"standards"
have
been sent to each shift crew for
a quality assurance
check.
Once this is completed the approved
Clearances will be officially accepted
as standards
in the computer
database.
12
OHP 4021.019.001
"Operation of the Essential
Service Mater
(ESW)
System."
The inspector
performed
a walkdown of a section of the
system
as described
in Data/Signoff Sheet 5.2,
"ESW,
Loop
1M Normal
Valve Lineup."
Prior to the walkdown, the change
sheets
associated
with the procedure
were reviewed to assure
proper inclusion into
selected
portions of the procedure.
Approximately 50 valves were.
inspected; all were found correctly positioned.
Some minor discrepancies
were noted between the valve number
as
stated
on the data sheet
and the valve number printed on the'ag
attached to the valve.
For example,
1-WPI-712-VllW on the data
sheet
corresponded
to 1-MPI-712-Vl on the valve's tag.
This and
other differences
were given to the appropriate
onsite group for
followup.
Other observations
unrelated to the
ESW system were identified
during the walkdown and also relayed to plant supervisory staff.
One involved damage to a 1/2 inch line connected
to 1-CPI-450-V1
(component cooling water to miscellaneous
pressure
indicator).
The line appeared
to have
been
stepped
on; it was bent
down and
flattened at a fitting joint.
Also,
on the platform grating below
the valve,
a lock and chain were lying unattached
to any piece of
equipment.
One final observation
relayed to the plant staff was
a loose,
ceiling-mount, adjustable
ring hanger for a length of pipe just
upsteam of the Turbine
Room Sump'verflow discharge line, located
in the screen
wash
pump room.
One violation (not cited)
and
no deviations,
unresolved or open items
were identified.
Radiolo ical Controls
71707)
During routine tours of radiologically controlled plant facilities or
areas,
the inspector
observed
occupational
radiation safety practices
by the radiation protection staff and other workers.
Effluent releases
were routinely checked,
including examination of on-line
recorder traces
and proper operation of automatic monitoring equipment.
Independent
surveys
were performed in various radiologically controlled
areas.
On November ll, 1989, the
an Emergency Notification
an at-power purge of Unit
discovered
which the duty
substantial
potential for
material.
On that basis,
licensee
reported,
then subsequently
withdrew,
System
(ENS) notification.
During setup for
2 containment,
a procedure deficiency was
Shift Supervisor decided might cause
loss of control of the release
of radioactive
the
ENS notification was
made.
The problem involved a "note" in data/alignment
Sheet
No.
3 of the purge
procedure,
which stated certain
subsequent
steps
were "not applicable" in
MODEs 1 through 4.
This was in error.
The referenced
steps
involved
verification of operability of radiation monitor Trains
A and B, and
placing the monitor output circuits in "Normal".
Failing these actions,
purge would not isolate
on containment
high radiation
as designed.
The licensee
had not purged in MODEs 1-4 in several
years.
An alternate
procedure for containment pressure relief, using different lines,
was
verified as correctly aligning the radiation monitoring system.
Upon
further evaluation of the subject procedures
the licensee
determined that
the identified discrepancy
alone
(as stated in 10 CFR 50.72 for
notification) would not have
caused
uncontrolled release
of radioactive
material.
Two other statements
in the
same procedure directly contradict
the erroneous
statement,
and the frequent operation"of the pressure
relief system
has
made operators familiar with the necessary
realignment
of the radiation monitoring system.
On these
bases,
the
ENS notification
was withdrawn later the
same
day.
The procedure errors,
which occur red during a March 1989 revision, were
corrected.
The inspector verified the correction
and that
no use
was
ever made of the procedure with the error present.
The inspector also
re'viewed the system
and the licensee's
evaluation
and agreed with the
licensee's
assessment.
This review included verification that,
even
had
the error been
implemented,
containment
purge isolation from safety
injection and from high containment
pressure
would both have
been
unaffected.
No violations, deviations,
unresolved
or open
items were identified.
5.
Maintenance
(62703
42700)
Maintenance activities in the plant were routinely inspected,
including
both corrective maintenance
(repairs)
and preventive maintenance.
Mechanical, electrical,
and instrument
and control group maintenance
activities were included as available.
The focus of the inspection
was to assure
the maintenance activities
reviewed were conducted
in accordance
with approved
procedures,
regulatory guides
and industry
codes
or standards
and in conformance with
Technical Specifications.
The following items were considered
during
this review:
the Limiting Conditions for Operation
were met while
components
or systems
were
removed from service;
approvals
were obtained
prior to initiating the work; activities were accomplished
using approved
procedures;
and post maintenance
testing
was performed
as applicable.
The following activities were inspected:
a ~
b.
Job Order No. A011391, "Disconnect annunciator
drop 69 on panel
122,
titled, Individual Hotwell or Miscellaneous
Drain Tank or Feed
Pump
Turbine Condenser
Conductivity High.'econnect
when notified by
Design
Change Coordinator."
The activity was performed
as part of
the ongoing effort to attain
a "black board" status
in the control
room.
The system is currently under
a design
change
(RFC - "Request
for Change" ) which has not yet been
closed out.
The annunciator
was disconnected
because
of recur ring problems with
the detector
and the cation bed, which would result in frequent
alarms
in the control room.
The associated
alarm response
procedure
lists
no automatic actions
and requires
the Chemical
Lab to
investigate.
The system initiated numerous false alarms which led
to its disconnect.
The annunciator will be disabled until it is
made to function properly.
Any increase
in secondary
conductivity
would be seen
in the steam generator
blowdown samples,
which are
monitored
on
a shiftly basis.
Gob Order No. A002121,
"Repack 1-IMO-204 with Chesterton
Packing;
weld leakoff line."
The work was performed
on the valve (spray
additive tank outlet) using procedure
- 12 MHP-SP-130, "Installation
Procedure for A.,W. Chesterton
Nuclear Valve Sealing System."
The
inspector
saw no problems with the work being performed.
It was
noted,
however, that the procedure
was inconsist'ent
as regarded
dimensions;
sometimes
they were provided,
sometimes
not.
One
example pertained
to stuffing box data.
Stem outer diameter
and box
C.
d.
e.
g.
inner diameter were simply listed as 0.750
and 1.250 respectively,
without stipulating units (e. g. inches,
centimeters).
Job Order No. A012011, "Investigate
and repair valve 1-FRV-256
(Unit 1 turbine-driven auxiliary feedwater
pump test line isolation
valve); valve leaks
by when closed."
This activity utilized
Procedure
""12 MHP 5021. 001. 012,
"Hammel
Dahl V-500 Series
Globe and
Angle Valves."
The valve disc was ground to remove surface cutting
and was
lapped
and blued to its seat.
Job Order No.
B010940, "Fabricate
and erect security enclosure for
Unit 2 "N Train" battery
and associated
switch gear."
Job Order
No.
B001217,
"Repair control air line hanger/support
where
damaged
above tray 2A1C6."
Job Order No.
A011251, "Fabricate
and install security cage for
Unit 1 panel
and charger."
The work was being performed
as directed
by a Request
For Change
(RFC 12-3019) to upgrade
the
"N train"
batteries
and support equipment.
Two procedures
were being followed
for the job, one of which (""12 MHP 5021.001.006)
provided instructions
for the fabrication and erection of structural steel,
and the other
("~12
MHP 5021.001.003)
provided instructions for anchor bolt
installation.
Review of these
items identified one minor problem;
wall mounted anchors
had to be installed
one inch lower than
originally intended
due to a surveying error.
This discrepancy
was
properly documented
and approved in an attachment to the relevant
procedure
noted above.
Job Order
No.
B003162, "Inspect
and measure orifice No. 2-FFX-253
Unit 2 Turbine Driven Auxiliary Feedpump test line orifice."
The
subject
Job Order was written in response
to the condition discussed
in Paragraph 6.f of this report.
The bolts installed at the orifice flange (2-FFX-253) were found
smaller in diameter than stated
on the associated
isometric drawing
(3/4 inch versus
7/8 inch),
and the flexitallic gaskets
were sized
for 1500 lbs.
versus
900 lbs.
Both the bolts and gaskets
were
replaced with those of the correct size.
The other Auxiliary
Feedpump orifices were checked,
and another
case
involving.
undersized
studs
was found in the Unit 2 East Motor Driven Auxiliary
Feedpump
Room.
Those studs
were also immediately replaced with the
correct size.
Separate
corrective action documents
were initiated
on each discrepancy,
to ensure root cause
and significance
evaluations
are performed.
Depending
on the findings of those
evaluations,
further inspection followup may occur.
No violations, deviations,
unresolved
or
open items were identified.
6.
Survei
1 1 ance
61726
42700)
The inspector
reviewed Technical Specifications
required surveillance
testing
as described
below and verified that testing
was performed in
accordance
with adequate
procedures,
that test instrumentation
was
calibrated,
that Limiting Conditions for Operation
were met, that removal
and restoration of the affected
components
were properly accomplished,
that test results
conformed with Technical Specifications
and procedure
requirements
and were reviewed
by personnel
other than the individual
directing the test,
and that deficiencies identified during the testing
were properly reviewed
and resolved
by appropriate
management
personnel.
The following activities were inspected:
a.
~"1 IHP 4030
STP. 100.001,
"Response
Time Testing of the Reactor
Protection
System Sensors."
The inspector
observed
various portions
of this multifaceted test,
including the Reactor Coolant
RTDs and
selected
Foxboro pressure/flow transmitters.
The testing was
conducted
by a contractor using plant-approved
(but contractor-
developed)
procedures
and with all electrical
connections,
switching,
and disconnections
by assigned plant Instrument
and
Control staff.
b.
C.
d.
e.
""2 IHP 4030
STP. 122,
2 and 4 Mismatch Protection
Set II Surveillance Test (Monthly)."
The inspector
noted plant
equality Control
was present for this test to independently
assess
test performance
and results.
""2 IHP 4030
STP. 134, "Reactor Coolant
Pump
No.
3 Underfrequency,
Bus
2A Surveillance Test (Monthly)."
""12 THP 6010
RAD. 1602, "Liquid Process
Monitor Detector Calibration."
The inspector witnessed part of the calibration process
for the Unit 2
East essential
(instrument
R-20) and did not
observe
a problem.
~"12 THP 6030
IMP. 012, "Radiation Monitoring System Calibration-
Air/Liquid/Gas."
Discussions
with the technicians
performing this
test
on process
monitor R-19 in Unit 2 (Steam Generator
Blowdown
Sampler)
revealed
a defective circuit card
had earlier
been
identified and replaced.
The inspector questioned
the whereabouts
of the associated
repair Job Order, which was not present,
and was
referred to the
18C office.
A Job Order was verified to exist
(No. 000253)
documenting the repair and accounting for traceability
of the
new part.
""2 OHP 4030 STP.017T,
"Turbine Driven Auxiliary Feedwater Test."
The subject test was performed during an
NRC review (ref.
NRC
Inspection
Report
No. 50-315/89028(DRS);
No. 50-316/89028(DRS)
of
the licensee's
pump In-Service testing (IST) program.
During the
test,
the
NRC auditor noted that the process
flow instruments
(2-FFS-258
and 2-FFS-260)
read
550
gpm while the pressure
differential across
the 3-inch test line orifice (2-FFX-253) equated
to 700
gpm.
The flow instruments
associated
with both the process
orifice and test orifice were checked
and found to be in calibration
and the instrument lines were verified to be free of blockage.
The
test
was rerun and the discrepancy still existed.
At that point it
was determined that the dimensions listed for one of the orifices
could be incorrect.
The test line orifice was disconnected
and measured
and found to be
correct.
The process orifice could not be disconnected
because
of
location, but based
on calculations, it is believed this orifice is
larger than design.
The associat'ed
"flow retention" switches
were
therefore reset to a lower setpoint,
proportionate to the observed
flow mismatch,
The significance (root cause
and potential
consequences)
of this
problem remained
under investigation with NRC Region III at the
conclusion of this inspection,
but are expected to be discussed
in
the Inspection
Report referenced
above.
""1 OHP 4030
STP. 017T, "Turbine Driven Auxiliary Feedwater
Systems
Test."
This test
was conducted for the purpose of restoring the
system to service following maintenance
on the associated
test valve
1-FRV-256 (ref.
Paragraph
5.c above)
and
as
a routine monthly test.
During the test,
the inspector
observed test
TG-097, which is
used to measure test flow (measure differential pressure
across
an
orifice in the test line) was quite erratic
and
had
a small leak out
the low-pressure
vent.
This raised
a question
about instrument
accuracy which was relayed to the test engineering
group onsite.
They determined that the test should
be rerun (initial data
showed
unexpectedly
high pump delta-P) with the test
pulse-dampened
and the vent not leaking.
The test then produced satisfactory
results.
Problem Report
(PR)89-887,
"2 MRV-210 main steam
stop valve for
No.
Unit 2 failed initial valve cycle time."
The problem involved a slow stroke time (5.45-seconds
versus
the
Technical Specification 5.00-second limit) for the subject valve,
using its "Train B" dump valve.
The valve met the 5-second
stroke
time limit (2.52-seconds)
when tested with its "Train A" dump valve.
The event'was initially classified
as
a Condition Report, but was
.
later upgraded
when the licensee
was asked to review the event
against
NRC reportabi lity requirements.
An investigation against
"Licensee
Event Report (LER)
system,"
and
and
Supplement
1, both of which
elaborated
on the
LER rule,
was performed.
The investigation
found
the event to be nonreportable,
since
2-MRV-210 met the full
requirements
of the Technical Specification
ACTION statement
and
since there
was
no evidence to believe the valve was inoperable
prior to the surveillance test.
10
Condensation
accumulation
in the piping associated
with the "Train
B" dump valve is believed to be the cause of the problem.
Formation
of a "water slug" could impede
steam flow and.thus
the closure time
of 2-MRV-210.
The licensee
intends to inspect the valve's internals
during the next outage of sufficient duration to determine if the
drain tube configuration associated
with the valve is in any way
damaged
or clogged.
No violations, deviations,
unresolved
or open items were. identified.
7.
Securit
71707)
Routine facility security measures,
including control of access for
vehicles,
packages
and personnel,
were observed.
Performance
of
dedicated
physical security equipment
was verified during inspections
in
various plant areas.
The activities of the professional
security force
in maintaining facility security protection were occasionally
examined or
reviewed,
and interviews were occasionally
conducted with security force
members.
On November 1, 1989, the inspector
was notified that licensee
equality
Assurance
had found an onsite contractor
(who provided background
investigative services
for personnel
who are granted
unescorted
access
to the plant) could not demonstrate validity of all of the information
provided in some individual screening
reports.
The finding was referred
to
NRC Region III Security personnel
for follow up.
No violations, deviations,
unresolved or open items were identified.
8.
Safet
Assessment/ ualit
Verification
37701
38702
40704
92720)
The effectiveness
of management
controls, verification and oversight
activities, in the conduct of jobs observed
during this inspection,
was evaluated.
The inspector frequently attended
management
and supervisory meetings
involving plant status
and plans
and focusing
on proper co-ordination
among Departments.
The results of licensee auditing and corrective action programs
were
routinely monitored by attendance
at Problem Assessment
Group
(PAG)
meetings
and by review of Condition Reports,
Problem Reports,
Radiological Deficiency Reports,
and security incident reports.
As
applicable,
corrective action program documents
were forwarded to
NRC
Region III technical specialists
for information and possible
followup
evaluation.
a.
The inspector
reviewed safety valve testing using the Trevitest
method,
pursuant to a question
from NRC Region III.
The concern
related to the performance of an appropriate
review to determine
whether testing via this method would result in an "unreviewed
11
safety question"
as defined in 10 CFR 50.59.
Specifically, if
the testing should
be permitted or performed in plant
MODEs not
originally envisioned,
does there exist
a safety evaluation
under
10 CFR 50. 59 to substantiate
its acceptability?
Safety valve testing via the Trevitest method
as performed at
D.C.
Cook plant is limited to secondary
system valves.
This testing
is governed
by procedure
""12 MHP 4030 STP.008,
which permits testing
in MODEs 1,
2 and 3.
This procedure
was approved at Plant Nuclear
Safety
Review Committee
(PNSRC) meeting
No.
2273
on June
15, 1989,
at which time
PNSRC decided
a 50.59 unreviewed safety question
determination
was not required.
Further investigation
showed that
the current procedure
was decended
from an earlier version
numbered
"~12
MHP SP. 126.
The earlier procedure
was subjected to a
10 CFR 50.59 safety evaluation
dated
June 22, 1987, which the
inspector
reviewed.
The safety evaluation
was imprecise with respect to carefully
covering all aspects
of 10
CFR
.50.59.
For example,
the Trevitest
method
does not increase either the frequency of testing or the
probability a given valve will fail to reclose
during any specific
test,
but the safety evaluation
does not explicitly address
any
potential for changing the probability of occurrence of an analyzed
event.
On the other hand,
the potentials for changing the nature or
magnitude of analyzed
events
were more explicitly evaluated.
Further,
the adaptability of the method to other than "during
scheduled
outages"
(original
FSAR, Section 10.2.4)
was recognized,
was determined to be bounded
by the
MODE 3 case,
and the
FSAR was
updated to read "prior to or during plant outages."
The safety evaluation relied upon certain procedural
prerequisites
or limitations.
For instance,
no seismic evaluation
was
deemed
necessary
due to procedure restrictions limiting testing to one
valve at a time and requiring the consideration of the valve in test
was "inoperable."
Test equipment is prohibited from being powered
off a safety related
(Class 1E),bus.
The inspector
concluded that the licensee's
determination,
while not
as explicit as desired in all details,
was correct - performing the
test pursuant to the procedure
as approved
does not constitute
a
.10 CFR 50.59 unreviewed safety question.
The above information was conveyed to the Region III requester.
Some
good technical findings by the licensee's
equality Assurance
(gA) organization resulted in the issuance
of Problem Reports
(PR).
Three worth noting are
PR 89-1177,
PR 89-1222,
and
PR 89-1184.
Problem Report 89-1177
documents
a finding that
some flow
instruments
used for the Inservice Testing
Pump Program
have
a full
scale
range greater
than that specified
by ASME XI (3.65 vs. 3.0
times reference
or less).
C.
Problem Report 89-122 discusses
a finding where elements of a
Technical Specification defined "reactor trip response
time" were
not incorporated into the associated
response
time procedure.
Specifically, gripper c'oil voltage decay time had been deleted.
Lastly, Problem Report 89-1184 describes
a technically inaccurate
change to a Maintenance
Department procedure.
The change
added
instructions for replacing
a Shunt Trip Attachment
(STA) which were
identical to those for replacing
an Under Voltage Trip Attachment
(UVTA).
These pieces of equipment differ and require separate
sets
of instructions for replacement.
The licensee
announced
an onsite reorganization
plan, effective
November 1, 1989, which is intended to produce
an improved emphasis
on maintenance,
and on project management
and support.
Significant
elements of the reorganization
include assembly of a
new Projects
division, from various existing departments,
headed
by an Assistant
Plant Manager.
The Projects division will be responsible for design
changes,
scheduling of major or long lead-time projects
and outages,
and construction
and contractor
management.
The Administration
division will no longer
be headed
by an Assistant Plant Manager,
but
some of its elements will be reporting directly to the Plant Manager;
this includes the independent
Safety
and Assessment
Department.
The
Production
and Technical
Support divisions will remain, with some
lesser internal restructuring,
and will be headed
by Assistant Plant
Managers.
A number of personnel
reassignments
or rotations occurred
within thes'e
groups,
the most significant being promotion of the
former Operations
Department Superintendent
to Assistant Plant
Manager-Production.
The reorganization
was discussed
at the
Management
Meeting on November 16,
1989 (Paragraph
14).
A review of
select personnel
qualifications
was incomplete at the conclusion of
the inspection.
The results of this review will be included in a
future report.
No violations, deviations,
unresolved
or open items were identified.
9.
En ineerin
and Technical
Su
ort
37701
41701
93701
The inspector monitored engineering
and technical
support activities at
the site and,
on occasion,
as pr'ovided to the site from the corporate
office.
The purpose of this monitoring was to assess
the adequacy of
these functions in contributing properly to other functions
such
as
operations,
maintenance,
testing, training, fire protection
and
configuration management.
ao
Unit 2 emergency
diesel
generator
2CD failed to load during a test
run on September
18,
1989.
The test
was being performed,
in part,
to verify proper instal'lation of design
change
No.
RFC-DC-12-2864,
which will provide "slow speed" start capability to all four onsite
diesels.
As part of the design,
the field flash to the generator
exciter rotor is disabled
and excitation depends
on residual
magnetism in the rotor.
This proved inadequate
during the subject
test - a condition apparently
not forseen during original design
and
13
not detected
in previous testing.
Some previous testing did not
include observing generator
performance
as
opposed to diesel
engine
performance;
some testing apparently
occurred with the original
rotor starting position coincidently aligned
such that excitation
was adequate,
and the generator
loaded successfully.
The problem was documented
on Problem Report 89-1041,
the "slow
speed" circuits were all disabled,
and
a redesign is under
evaluation.
The diesel
emergency
functions were not adversely
affected
by this design oversight.
Problem Report 89-1194, written on October 26, 1989,
documented
discovery of the fact that Unit 2
MODE 4 and
5 shutdown boron curves
in the Technical
Data Book (Figure 4.5) lacked appropriate
safety
margin for postulated
boron dilution accidents
while on residual
heat removal.
As an immediate,
interim corrective action,
instructions
were issued to add 300
gpm to the concentration
determed
from the referenced
Figure,
should
MODE 4 or 5 operation
occur before
new curves could be generated.
No such
shutdown
was
actually necessary;
new, correct curves
have
been produced
and
distributed.
This problem
had apparently existed since
March 1989,
when the
'curves
were generated
by evaluation of vendor (Advanced Nuclear
Fuels) data through corporate
and site nuclear engineering.
The
Unit was subsequently
in MODEs 4 and
5 during a.scheduled
outage
June 10-24,
1989,
The significance of the error and its implications considering
the actual
June
1989 outage
were still under evaluation at the
conclusion of the inspection.
Further inspection will occur if
the matter proves important.
Plant Control
Room Simulator Evaluation
On October
10 through 12,
a special
evaluation
was conducted
utilizing the D.C.
Cook Unit 2 control
room simulator.
A team of
NRC personnel
- consisting of the Senior Resident Inspector
and
Resident
Inspectors
assigned
to both
D. C.
Cook and to Palisades
(the backup site)
and of the responsible
NRC Region III Section
Chief and the
NRR Licensing Project Manager - performed this
evaluation.
The following procedures
were exercised
on the simulator:
(1)
""2 OHP 4021.001.011,
"Determination of Critical Conditions
Donald
C.
Cook Nuclear Plant"
(2)
""2 OHP 4021.001.002,
"Reactor Start-UP"
(3)
""2 OHP 4021.001.006,
"Power Escalation"
(4)
""2 OHP 4022.053.001,
"Decreasing or Loss of Condenser
Vacuum"
(5)
""2 OHP 4022.013.006,
"Tripping of Protection
Set Bistables"
(6)
02
OHP 4023. E-O, "Reactor Trip or Safety Injection"
(7)
02
OHP 4023.ES-O. 1, "Reactor Trip Response"
(8)
02
OHP 4023.E-1,
"Loss of Secondary
or Reactor Coolant"
(9)
02
OHP 4023,ES-1. 1, "SI Termination"
(10) 02
OHP 4023.E-2,
"Faulted
Steam Generator Isolation"
(ll) 02
OHP 4023.ECA-3. 1,
"SGTR M/Loss of Reactor Coolant-
Subcooled
Recover Desired"
(12) 02
OHP 4023.FR-S. 1, "Response
to Nuclear Power Generation/ATWS"
(13)
02
OHP 4023.FR-H. 1, "Response
to Loss of Secondary
Heat Sink"
The team noted that procedure
E-0 had been recently revised to eliminate
a potential
problem with handling
a loss-of-coolant accident concurrent
with complete loss of auxiliary feedwater.
Reordering the "exit" step
on
failure of auxiliary feedwater, still within the owner's
group
emer gency
response
procedure guidelines,
now assures
all the critical verifications
contained only in E-0 will be performed before the procedure is exited.
This revision resolves
a concern
NRC had raised in an earlier inspection.
Two potential
weaknesses
were identified in existing procedures.
First,
procedure
FR-S. 1 on
ATWS did not contain
an early instruction to close
the main steam
stop valves
as
an aid to conserving
inventory.
Consequently,
substantial
inventory was (perhaps
unnecessarily)
lost.
Second,
procedure
FR-H. 1 on loss of secondary
heat sink had
no
early instruction (concurrent with commencement
of pressurizer
"feed and
bleed" ) regarding installation of "jumpers"
on phase
A isolation functions.
Phase
A is an inevitable result of "feed and bleed"
and results in loss
of the "bleed" function via isolation of operating air to the pressurizer
power operated relief valve.
It seemed
the procedure
could and should
prevent this, rather than respond to it after it occurs.
The above potential procedure
weaknesses
were conveyed to the procedure
group responsible for emergency
operating procedures
for their
consideration
and appropriate corrective action.
During one scenario
involving complete failure/loss of the condensate
storage
tank (CST) the simulator instructors indicated auxiliary
feedwater alignment to its alternate
supply (essential
should not include opening the supply valves.
Since these
are not
automatic valves,
they would have to be opened
by operator action from
the control
room in case of some additional
emergency requiring auxiliary
15
The inspectors
questioned
the implicit position that closed
the valves;
non-automatic
valves
can
make for an
OPERABLE flowpath,
and
were concerned that plant operator training includes this implication.
Other instruction concerns
related to the use of non-EOP criteria as
a
basis for rendering
(unneeded)
emergency
equipment inoperable during an
emergency.
Examples
were:
shutdown of an unloaded
emergency diesel
rather than letting it idle unloaded for more than five minutes
(an
operating/surveillance
guideline)
and; placing
a recirculating
LPSI pump
in "pull-to-lock" so that pump/water temperatures
would not gradually
build up,
Neither action
seemed critical to equipment protection,
so
securing
and defeating automatic
emer gency response
functions
seemed
unnecessary,
perhaps
even ill-advised.
The above instruction concerns
were conveyed to and discussed
with
appropriate
licensee staff for their consideration
and, if appropriate,
corrective action.
Overall, the inspection
team found the procedures
effective.
They were
generally clear
and straightforward
enough to permit successful
implementation
by knowledgeable
(but not specifically Cook-trained)
individuals.
The symptom-based
Functional
Restoration
Guides were
similarly exercised
in part
(02-OHP 4023.F-O. 1 through F-0.6) with no
significant deficiencies
noted.
No violations, deviations,
unresolved
or open items were identified.
10.
Re ortable
Events
92700
92720)
The inspector
reviewed the following Licensee
Event Reports
(LERs)
by means of direct observation,
discussions
with licensee
personnel,
and review of records.
The review addressed
compliance to reporting
requirements
and,
as applicable, that immediate corrective action
and appropriate
action to prevent recurrence
had been accomplished.
Closed)
Licensee
Event
Re ort LER 315/87007:
missed event-initiated
surveys
1
ance
sump eff uent radio oglca
sampling)
due to
unrecognized
disabling of automatic
sampler.
An incomplete
instrument calibration activity disabled the turbine
sump automatic
sample compositer
(by simulating
a no-flow signal)
when the test
equipment
was left connected at the end of the work day.
discharges
were very intermittent,
so the lack of sample
accumulation in the compositer receiver
was not readily apparent.
Mhen the problem'was
recognized
the next day,
an approximate
16-hour
interval
had elapsed,
which exceeded
the eight hours specified for
alternate
manual
sampling
and analysis.
To prevent recurrence,
instr ument group super visors
and work planners
were informed of the affect of the activity, and the recorder being
calibrated
was labeled with a sign warning of its connection with the
compositer.
16
Radiation monitors
on lines upstream of the
sump were checked; all
were operable
and showed
no unusual radioactivity over the period in
question.
(Closed)
Licensee
Event
Re ort
LER 315/89003:
Unit 1 reactor trip on
March 18, 1989, while shutting
down.
The unit tripped from about
10 percent
power when the high flux trip signal
from intermediate
range nuclear
instrument
channel
N-35 auto-unblocked
before it
cleared
and reset.
The reset
should occur first, normally at around
12. 5 percent.
This is because
reset is nominally calibrated to an
electric current equal to half the trip setpoint current (at or
below 25 percent).
In this case,
the trip setpoint
was conservatively
set
due to rounding
down calculated current values,
then the reset
setpoint (half the trip setpoint)
was also
rounded
down to the next
whole number.
The combined conservatisms
resulted in the reset
setpoint being below 10 percent nuclear
power on one channel.
When
the block cleared at 10 percent,
the trip followed immediately.
To prevent recurrence,
procedures
were changed to ensure
the reset
setpoint, while still conservative, will be set
above the auto-
unblock= setpoint.
An inspection of like instrument channels
in
Unit 2 disclosed
one with the
same type overlap problem, which was
corrected.
The plant responded
normally upon trip actuation, with no system or
equipment
problems
noted.
(Closed
Licensee
Event
Re ort
LER 315/89004:
containment isolation
va ve Type
test resu ts disclosed
leakage
above 0.60L
.
The
original
LER was submitted with some testing
and followlp actions
still incomplete.
LER Supplement
1 dated August 31, 1989, included
complete information on test results.
Further,
as discussed
in
Inspection
Report
No. 50-315/89018(DRP);
No. 50-316/89018(DRP)
(Paragraph
the Supplement
includes
a discussion of the circumstances
surrounding
a repair to valves
ICM-250 and ICM-251 which were
performed without first obtaining "as-found" leak rates.
The repair
to valves
ICM-250 and -251 was to replace
stem packing.
The valve
internals
were not repaired.
Hased
on very low as-left seat
leakage
(which should closely approximate
as-found in the absence
of internal
maintenance)
these
valves would not have
added significantly to the
as-found total.
The final total leak rate
(maximum pathway method)
was 3.08L
,
primarily due to just three valves.
All three valves were e5ch in
line with other valves having very low leak rates.
All three were
repaired or replaced.
None had
a significant failure history among
six previous
cases
of Type
C test results totaling above 0.60L
for
Unit l.
Determining as-found
leakage to be above 0.60L
is not a violation
of regulatory requirements
in the subject case,
because
the
significant contributors
appeared
to result from random component
degradation.
Failure to determine
as-found
leakage prior to
performing maintenance,
however, is contrary to licensee
procedures
17
and,
by reference
through Regulatory Guide 1.33 Appendix A, is
contrary to Technical Specifications.
Further,
such actions
are
contrary to 10CFR50 Appendix J
as applied to this valve design.
The violation was identified, reported
and corrected
by the licensee.
It resulted
from personnel
error by maintenance
personnel,
who
failed to follow procedure
controls correctly.
The procedures
properly cautioned that leak testing must precede
maintenance
because
of a similar occurrence
some
2 1/2 years earlier,
when such
precautions
did not exist.
Given the amount of time elapsed
between
the events,
the 1989 problem is- not considered repetitive or
programmatic.
Further, it lacks safety significance
because
the
work was external
to the valve seats
and would not have affected the
leak rate materially.
(Closed
Licensee
Event
Re ort
LER 315/89005:
containment
iso ation va ve for component
coo ing water
(CCW) system.
Valve
1-CCM-458
(CCW supply to reactor coolant
pump coolers) failed to
close during testing
on March 30,
1989.
The unit was in a refueling
shutdown at the time,
so there
was
no immediate significance to the
failure.
Internal
damage
was found in the valve operator
upon
disassembly.
An "interim" LER was submitted
when the root cause
and
safety evaluations
were not able to be completed within 30 days.
The
estimated
submission
date for the final
LER was June
9, 1989.
On
that date,
the licensee
submitted
a letter withdrawing the
LER,
because
the event
was determined
not to be subject to mandatory
reporting requirements,
and not to be
a safety hazard or an unreviewed
safety question.
(Closed)
Licensee
Event
Re ort
LER 315/89006:
ECCS flow balance
out-of-speci
icatson.
Routine mandatory f ow balance testing,
conducted
during the 1989 refueling outage
as per Technical Specification 4.5. 2, found-total safety injection flow from the
North SI pump to be slightly in excess
(644
gpm vs.
640 gpm) of the
allowable upper limit.
Adjustments
were
made to system flow control
valves to restore
the flow within the specified
range.
The
deviation apparently resulted
from small
normal
system fluctuations
combined with instrument uncertainties.
An evaluation of the
magnitude of the discrepancy
showed it was not safety significant.
In fact, the licensee
concluded the currently prescribed
acceptance
range for SI flow is much more restrictive than necessary
to meet
safety requirements
with comfortable margins.
A broadening of the
acceptance
range
has
been requested
and is under evaluation
by NRC.
(Closed
Licensee
Event
Re ort
LER 315/89008:
deficient monthly
calibration checks.
his condition app ie
to both D.C.
Cook
units.
'
generic Westinghouse letter dated
December
1,
1988 and
entitled "Calibratioh of AFD Instrumentation"
addressed
how various
aspects
of excore-indicated
axial flux difference
(AFD) should
be
compared
as part- of monthly surveillance.
One such aspect
involves
comparing the excore-indicated
value to the value input to the
F
(Delta I) penalty function generator.
A review of licensee
procedures
against the Westinghouse clarification found this particular
'omparison
involving the penalty function generator
was being
done
as part of routine quarterly testing rather than monthly.
The described
comparison
was transferred
to a monthly test
procedure.
The reason for the original choice of quarterly vs.
monthly could not be determined.
A review of historic data found
the input to the penalty generator
had been quite stable,
requiring
only infrequent (and minor) adjustment.
Omission of two thirds of
the comparisons
had therefore
not constituted
a significant safety
hazar d.
The licensee's
omission of the described testing was,
however,
a
violation of Technical Specification requirements
at 3.3. 1. 1 to
perform testing stipulated in Table 4.3-1.
The inspector took
specific note, in reviewing this matter, of the fact that five
"Previous Similar Events" are listed in this
LER.
A further review
determined
the "similarity" to involve the fact that instrument
surveillance
procedures,
to accomplish testing governed
by Technical
Specification Tables,
contained
discrepancies
such that complete
literal compliance with the Specification
was not achieved.
Three
of the five previous "similar" events,
in fact, occurred in
close chronology during 1986; special
licensee
reviews for this
purpose
were conducted to address
a generic
concern
about the
technical quality of instrument test procedures
to implement "Table"
requirements.
A variety of causes,
a variety of instruments,
and
a
variety of discrepancy
types
(scope,
frequency; technical
consistency)
were involved in these
events.
LER 315/89008 did not involve the
same instruments,
the
same root cause
or consequences,
or the
same
technical
nature
as these
previous events,
so it was determined
not
to demonstrate
a repetitive problem.
(Closed)
Licensee
Event
Re ort 315/89012:
ECCS components
s)multaneously
inopera
e sn
oth trains.
With the "A" Train
safety injection pump inoperable for ongoing maintenance,
a
surveillance test
was authorized
and performed
on "B" Train
rendering it (including the associated
safety injection pump)
simultaneously
The test authorization resulted
from
errors
on the part of the Shift and Unit Supervisors
(both Senior
Reactor Operator licensed)
who did=not recognize
the unacceptability
of the specific test in the existing circumstances.
The test
procedure
was deficient in not highlighting the need to assure all
opposite-train
equipment
was
Also, the maintenance
scheduling
process
did not specifically coordinate with the testing
schedule;
the test occurred
second,
but it was scheduled first.
Though not addressed
explicitly in the
LER, simultaneous
inoperability of equipment in both
ECCS trains placed the unit
in Technical Specification 3.0.3.
This Specification requires
initiation of action within one hour to place the unit in an
acceptable
condition.
Because
the dual inoperability was not
recognized,
no such action was initiated.
Instead,
one train was
routinely restored to OPERABLE status
upon test completion, which
occurred after 68 minutes.
Failure to comply with an "action" requirement of Technical Specification 3.0.3 is considered
a violation of the Specification
(Violati on 315/89029-01) .
A violation of a Technical Specification "action" requirement is a
potentially significant enforcement matter.
An NRC Enforcement
Board was convened
on October 25, 1989, to consider this event.
The
Board concluded that this specific example
lacked any substantial
safety significance,
and it was adjudged to be
a Level IV violation.
In consideration
of the causes
of the event,
however,
along with the
occurrence
of a somewhat similar event
a few weeks earlier (ref.
Inspection
Report 50-315/89026(DRP);
50-316/89026(DRP)
Paragraph
3.6)
the Board recommended
a Management
Meeting be scheduled
between
NRC and licensee
representatives
to discuss
these
and other timely
matters.
The Management
Meeting is addressed
further in Paragraph
14.
below.
(0 en
Licensee
Event
Re ort
LER 316/88003:
RPS instrument
to erances
repeate
y vso ate
.
e orsgsnal
LER has
been
supplemented
four times,
most recently
on September ll, 1989.
The licensee
has concluded
the observed
instrument "drift" has
remained within safe limits, although outside current Technical
Specification tolerances,
and that
no more stable devices
are
currently available
as replacements.
Thus,
a request to relax
the Technical Specification tolerances
was submitted
on November 29,
1988.
A technical
review of this
LER was conducted within NRC
Region III which derived several
questions
concerning matters
not
explicitly stated in the
LER.
The inspector relayed these
questions
to the licensee
and plans to review this matter further upon receipt
of the requested
additional
information.
Closed
Licensee
Event
Re ort LER 316/88009:
containment integrity
requirements
urging core
a teratsons
not met.
This report describes
conditions applicable to both D.C.
Cook units.
At D.C.
Cook,
lower containment
atmospheric
radiation is sampled (essentially
continuously) for iodine and particulate concentrations
by drawing
a sample out of containment
through particulate filters and iodine
cartridges.
The filters and cartridges
require regular change out.
While they are being changed,
an open pathway
can exist from the
containment
atmosphere
to the auxiliary building, unless
the sample
inlet line is isolated.
Such
an open pathway is not permissible
during reactor core alteration (i.e. fuel handling) yet the changeout
procedure
did not require isolating the pathway for a changeout
made
during such periods.
Such events
(open pathway while handling fuel)
have almost certainly occurred repeatedly,
each lasting
up to a few
minutes,
during the past history of the two units.
A requirement of
each unit's Technical Specifications,
to suspend
integrity is not maintained,
has thus very likely been repeatedly
violated.
Applicable procedures
were revised to prevent
a recurrence.
(Closed
Licensee
Event
Re ort
LER 316/88010:
containment
purge in
service with snopera
e contro
room radlatlon alarm annunciation.
The subject alarm annunciation is required
by Technical
20
Specifications
whenever the purge is in service.
In the subject
event,
the reactor
and containment
were both completely void of
nuclear fuel (during a prolonged outage to replace
the steam
generators)
and purge
was in service.
Due to a misunderstanding
of
language
in an administrative guideline,
the radiation monitoring
system control terminal
was then removed from service for a design
change.
The individual authorizing this action (licensed
SRO)
understood
the guideline to indicate the Specification could be
satisfied
by recording local readings,
which is incorrect.
The
error was recognized
and corrected
about
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> later,
and the
guideline
was clarified to prevent
a recurrence.
Radiation monitor
system safety functions (to isolate purge
on high radiation) were
always
(Closed
Licensee
Event
Re ort
LER 316/88011:
unexpected
actuation
of engineered
sa ety feature
Phase
B Iso ation) during testing.
A
new circuit time-response
test
was being conducted with the unit
shutdown
and defueled.
Part of the test utilized logic test
switches
on the
SSPS test panel to initiate main steam isolation
valve closure.
This was the only actuation
expected.
Mhen the
switch was used,
however,
containment isolation
Phase
B also
actuated.
A subsequent
review of the details of the test circuit
showed this should
have
been expected;
the circuit worked as
designed.
Post actuation
response
of all in-service
Phase
B equipment
was
correct.
To prevent recurrence,
the test procedure
was revised
to incorporate
the subject portion into another section which
intentionally verifies the
Phase
B time response,
and
an alternate
means
was developed for actuating
steam isolation valve circuits
only.
(Closed)
Licensee
Event
Re ort
LER 316/89003:
reactor vessel
level
>ndscatson
system
calsbrat>on
shrift due to air leakage into
capillary tubing during mid-cycle outages.
This problem was
discovered
during a refueling outage
when a routine required
calibration
was performed.
Evidence
suggested
the system
had
become
inaccurate
during some previous mid-cycle outage,
when the reactor
was depressurized
so that air could leak into the tubing.
The design
accuracy specification of plus/minus one-percent
was exceeded
by all
three transmitters
on both trains, with a worst case of "drift" in
excess
of 40 percent
on one "A" Train transmitter.
The precise
time
the problem developed
could not be identified.
The system
was
made leak-tight by seal-welding the steel
dust cap
over the high-point*fill valve stem and seal.
The transmitters
were
then recalibrated
and restored to OPERABLE for unit operation.
An evaluation of the significance of the operators
receiving
erroneous
level indication was conducted.
The only likely incorrect
action identified was to vent the reactor vessel
post-accident
to
~21
remove voids and increase
indicated vessel
level.
This would result
in decreased
indicated level,
however,
and the
RYLIS error would
become evident.
Since it is likely the
RYLIS was out-of-calibration during periods
of required
system operability, the effective Technical
Specification
was violated.
(Closed)
Licensee
Event
Re ort
LER 316/89012:
incomplete monthly
channe
checks.
When Unit
echnical Specifications
were revised
by Amendment
No.
95 to add channel
check requirements for
containment water level instruments,
the licensee's
implementing
procedures
were not likewise revised.
As a consequence,
the
specified channel
checks
were not performed for four months.
The Amendment occurred in late 1987, but did not become effective
until a post-refueling unit startup in March 1989.
In the meantime,
a combination of errors occurred which resulted in the procedures
remaining
unchanged.
First,
no departmental
action request
was
initiated due to an oversight.
Subsequently,
the duplicative
corporate action item tracking system item was overlooked, .perhaps
due in part to an over-reliance
on the departmental
tracking list.
Qhen the error was discovered
in June,
1989,
a channel
check found
all the instruments
The governing procedure
was revised
and the required channel
checks
have subsequently
been routinely
performed.
The
NRC Enforcement Policy (10 CFR'2 Appendix C) describes
condition for
which violations of requirements will not normally be subject to a Notice
of Violation.
These include .that the violation be identified, reported
(if required)
and corrected
by the licensee,
that it be a Severity
Level IV or V (lesser safety significance)
and that it be neither
repetitive nor otherwise indicative of licensee failure to correct
a
known problem.
Among the items discussed
above,
Items c, f, i, j, 1,
and
m concern licensee-identified violations which are
deemed to meet
these criteria and for which no Notice of Violation is being issued.
One violation was identified in this area which will be the subject of a
Notice.
Six potential violations (not cited)
and
no deviations,
open or
unresolved
items were noted in this area.
ll.
NRC
Com liance Bulletins
Notices
and Generic Letters
92703
The inspector
reviewed the
NRC communications listed below and verified
that:
the licensee
has received the correspondence;
the correspondence
was reviewed
by appropriate
management
representatives;
a written
response
was submitted if required;
and, pl'ant-specific actions
were
taken
as described
in the licensee's
response.
(Open) Generic Letter 88-03:
Resolution of Generic Safety Issue
93,
Steam Binding of Auxiliary Feedwater
Pumps.
The inspector
reviewed
-the licensees
response
to GL 88-03 dated
May 31,
1988 and the below
22
referenced
procedures.
The response
indicates that the Operations
Department is required
by Procedure
OHP 4030.001.001
"Routine Plant
Inspection Outside of Control
Room" to perform a shiftly (every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />)
check on the auxiliary feedwater
(AFM) lines to verify the
AFW line
temperature
is ambient.
Review of this procedure
by the inspector
identified that the above
checks
were not requirements
but were
guidelines.
The guidelines to perform the checks
are part of the
procedure
in Attachments
No.
1 and
No.
2.
The procedure
states
"Although
these
do not represent
specific requirements,
be aware that the operator
should develop
a habit or pattern to routinely check those
items
on the
guidelines."
When this was communicated to the licensee
they agreed
to modify the procedure to make the
AFW line temperature
checks'
requirement.
In addition,
Procedures
OHP 4021.056 '02 "Operation of the
Auxiliary Feed
Pumps During Plant Startup
and Shutdown",
and surveillance
test Procedures
OHP 4030.STP.017T
and
OHP 4030.STP.017R
for the turbine
driven and motor driven auxiliary feedwater
pumps require checking the
AFW line temperature
30 minutes
and
90 minutes after stopping
an
pump.
Procedure
OHP 4022.056.001
"Steam Binding in Auxiliary Feed
Pumps"
provides guidance for recognizing
steam binding and for restoring the
pump to operable
status if steam binding were to occur.
The Hay 31,
1988 response
also committed to reference
the Generic Letter
in the above procedures
in the next biennial
review to assure that
procedures will be maintained.
Review of how the licensee
implements
changes
to procedures
because
of commitments disclosed
some weaknesses
in
their system.
Procedures
1-OHP 4030.STP.017T
and
1-OHP 4030.STP.017R
were
revised for their biennial review on June
10,
1988 and June
30,
1988 and
neither included the reference
to GL 88-03.
These
were realatively close
to the
May 31,
1988 commitment date
and it can
be understood
how the
reference
would not be included.
However,
Procedure
1-OHP 4021.056.002
was issued
as Revision 9, incorporating biennial review,
on February
21,
1989, eight and one half months after the commitment date
and did not
include the reference
to GL 88-03.
It was found the the licensee
took
six months to place the change letter for each of the procedures
in the
file so it would be reviewed during the next biennial review.
This
change letter
was dated
November 30,
1988 and was put in the file after
the biennial
review for the above
Procedure
(1-0HP,4021.056.002)
was
started.
It appears
that once
a biennial
review is started
the change
file is not reviewed during the revision process
even if that process
takes three months.
The fact that the reference to Generic Letter 88-03 was not included
in the above procedures
in a timely manner
and that
AFW line temperature
checks
were guidelines
instead of requirements
may have contributed to
the licensee's
inability to recognize
the lack of tour performance
in
the Auxiliary Feed
Pump
Rooms
by the auxiliary equipment operator
(AEO)
(see
Paragraph
3.b).
Additionally, the
AEO did not check the
AFP
discharge
lines to see if they were at ambient
room temperature.
Thus,
the licensee
did not fully meet their commitment as defined in their
May 31,
1988 response
This item will remain
open pending additional
NRC investigation of the auxiliary operators
performance with regard to fulfillingthe above
commitments.
23
'P
No violations, deviations,
unresolved
or open items were identified.
Alle ations
92705)
(Closed) Allegation
(AMS No. RIII-89-A-0075):
An anonymous allegation
was received in the
NRC resident office on May 28,
1989.
It alleged that
a current trend at the station is to assign junior Radiation Protection
Technicians
(RPTs) to job coverage
for work formerly done
by experienced
RPTs,
and that the junior RPTs
do not perform as well as senior
RPTs in
that they give no direction or recommendations
regarding minimization of
contamination
and radiation exposure.
The alleger referred to current
work on the reactor
head
and cited an instance
where
a junior technician
was in the wrong place
when two contaminations
and
a 150 mr exposure
occurred.
In review of the allegation,
the inspector contacted
the Radiation
Protection
Manager
(RPM),
a plant health physicist,
the contractor site
manager
and training coordinator,
four licensee
RPTs, three of whom were
previously contractor
RPTs during previous refueling outages,
and two
mechanical
maintainance
workers with combined experience of about
24 years at the station.
The inspector also reviewed radiation
protection training and personnel
qualification records,
and radiation
protection logs.
The inspector's
review focused
on work performed
by
junior technicians
currently and during the previous
outage.
Discussion:
The current station
(house
and contractor )
RPT staff consists
of about
60 senior
and
17 junior.technicians.
During the two outages
which
overlapped
in winter/spring 1989,~the total
number of RPTs consisted
of about
110 seniors
and
65 juniors compared to about
80 seniors
and
15 juniors used during the spring 1988 refueling outage.
According to
the licensee,
the increase
in the ratio of juniors to seniors
was
due
to contract senior
manpower shortages
in early 1989.
It is licensee
practice that junior RPTs perform all radiation protection functions
under the direction of a senior
RPT and/or
a Job Coverage
Coordinator
(JCC).
According to the
RPTs interviewed these functions included
performing direct and indirect pre-job and routine surveys,
counting air
samples
and smears,
personal
and material control at control access
points,
personnel
frisking, providing guidance in removal of protective
clothing,
and general
assistance
to a senior
RPT or JCC.
The licensee
allows direct job coverage of
RWP work to be performed by junior RPTs
only under controlled conditions.
Only one of the
RPTs interviewed
indicated performance of senior
This was
stated to have
been performed
under controlled conditions during the
last outage.
All of the
RPTs inter viewed stated that as junior RPTs it
was not their function to make recommendations/suggestions
concerning
radiological controls unless
authorized.
They stated that during outage
activities the junior RPTs did control access
points to check personal
dosimetry,
perform frisks if necessary,
and provide guidance in
minimizing personal
exposure
and contamination.
However, questions
0
involving workers
SRD readings
or existing radiological conditions in
a work area
were normally directed to a senior
RPT or JCC.
Neither of
the maintanance
workers recalled
seeing
any instances
where junior RPTs
were performing senior jobs,
nor could they recall other workers
expressing
concern
about this matter.
With regard to the alleged event involving anonymous individuals with
personal
contamination,
and
an
SRD reading of 150
NR, occurring when
a
junior RPT was at a control point to provide assistance,
the inspector
was unable to identify any such occurrences.
The inspector
reviewed training lesson plans, training and test records
and personnel
qualification check sheets for the
RPTs interviewed.
The
record
showed that the junior RPTs received
formal training by the
licensee:
General
Employee Training (GET) and
RCT Training.
Contract
junior RCTs receive
GET and Procedure training,
and additional training
by the contractor.
Based
on this review and discussions
with the
contractor training coordinator it appears
the training is sufficient
and commensurate
with junior RPTs assigned
duties.
The allegation
was not substantiated.
Although it appeared
there were
more junior RPTs
used in 1989 compared to the previous year,
the
inspector could not find any evidence to indicate there
was
a trend to
assign junior
RPTs to jobs formerly assigned
to senior
RPTs,
nor could he
establish that junior RCTs did not have the qualifications to perform
their assigned
duties.
Also, the inspector could not determine if one of
the junior RPTs
was in the wrong place
when two contamination
events
and
a 150
mr reading occurred
on a worker's
SRD.
No violations, deviations,
unresolved
or open items were identified.
Re ion III Re uests
(92705)
Based
on a report from another licensee with a similar design to
D.C.
Cook plant, that the
FSAR was incorrect in stating
blowdown would isolate
on initiation of auxiliary feedwater,
the
inspector
was requested
to determine
how steam generator
blowdown would
be handled in conjunction with auxiliary feedwater initiation at
D.C.
Cook.
By review of design documentation
and discussions
with plant personnel,
the inspector determined that manual initiation of auxiliary feedwater
does not affect steam generator
blowdown.
All automatic auxiliary
feedwater initiations,
on the other hand,
are
accompanied
by steam
generator
blowdown isolation.
This is because
the auto-start logic
processes
the start signals
lo-lo level, main feed
trip loss of load,
SIS) via the "feedwater conservation circuit."
This circuit has
a separate
output to isolate
blowdown.
-FSAR Figure 7.2-1 does
not detail the above logic, but neither
does it
incorrectly claim a blowdown isolation which does
not exist.
25
The above information was conveyed to the requesting party in NRC
Region III.
No violations, deviations,
unresolved or open items were identified.
Mana ement Meetin
(30702
A Management
Meeting (attended
as indicated in Paragraph
1.b above)
was
conducted
on November 16, 1989, for the purpose of discussing
recent
operating events
and plant management/staff
changes.
The licensee
provided information and assessments
regarding the concerns
raised
by
the
NRC staff and was responsive
to associated
questions.
The focus
of the meeting
was generally
on plant status
knowledge
and control of
plant activities and configuration.
Failures to exercise
adequate
control,
as exemplified by the violation identified in this report
(Paragraph
10.g) were specifically discussed.
Licensed
0 erator Trainin
Meetin
An NRC concern
was raised
due to a high failure rate during the conduct
of operator licensing simulator examinations at
D. C.
Cook.
A follow-up
NRC inspection
was also conducted to help clarify the root cause for the
high simulator failure rate in July.
The inspection results
indicated
that the training program exhibited
some possible
weaknesses
that
collectively contributed to the failures.
These
included weakness
in
the program evaluation
methods,
inconsistency with the
NRC exam method,
weakness
in the
SRO control board training and ineffective program
feedback
mechanisms.
16.
In response
to the
NRC concerns
and findings the licensee
agreed with the
basic issues
but took exception to the numbers
and types of malfunctions
and events
used in NRC simulator
exams
as being inappropriate
and
unrealistic or of low probability.
The region responded
to the licensee
concerns
by inviting facility
training representatives
to the region to discuss
exam strategy.
During
the meeting held on November 16, 1989,
members of the region staff and
the facility training staff exchanged
viewpoints
and methods for
, establishing
simulator event sequences.
At the conclusion the facility
representatives
and region staff had reached
a clearer understanding
of
each others expectations.
Mana ement Interview
30703
The inspectors
met with licensee
representatives
(denoted in Paragraph l.a)
on November 17, 1989, to discuss
the scope
and findings of the inspection
as described
in these Details.
In addition, the inspector also discussed
the likely informational content of the inspection report with regard to
documents
or processes
reviewed by the inspector during the inspection.
The licensee
did not identify any such documents/processes
as proprietary.
The following items were specifically discussed:
a.
the licensee-identified violation of auxiliary operator shift tour
procedures
(Paragraph
3.b);
b.
the potentially significant discovery of erroneous
setpoints for
Unit 2 turbine-driven auxiliary feedwater
flow retention actuation
(Paragraph 6.f);
C.
d.
various observations
involving emergency
procedures
and training
which arose
from utilization/evaluation of the control
room
simulator (Paragraph 9.c); and,
the licensee-identified violation involving concurrent inoperability
of elements
of both independent
safety trains
(Paragraph
10.g)
and
the associated
Management
Meeting (Paragraph
14).
27