ML17329A028
| ML17329A028 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/16/1991 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17329A027 | List: |
| References | |
| 50-315-91-10, 50-316-91-10, NUDOCS 9105290156 | |
| Download: ML17329A028 (26) | |
See also: IR 05000315/1991010
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports
No. 50-315/91010(DRP);
50-316/91010(DRP)
Dockets
No. 50-315;
50-316
.
Licensee:
Company
1 Riverside Plaza
Columbus,
OH
43216
Licenses
No. DPR-58;
Facility Name:
Donald C.
Cook Nuclear
Power Plant, Units
1 and
2
Inspection At:
Donald C.
Cook Site,
Bridgman, Michigan
Inspection
Conducted:
March 20 through April 30,.1991
Inspectors:
J.
A. Isom
D.
G. Passehl
~
~
Approved By:
orge sen,
ie
Projects Section
2A
S
CPl
a
e
Ins ection
Summar
Ins ection from March 20 throu
h
A ril 30
1991
(Re orts
No. 50-315/91010(DRP);
o.
-
1
Areas Ins ecte
outine unannounced
inspection
by the resident
inspectors
o
plant operations;
maintenance/surveillance;
engineering
and technical
,support; radiological controls; actions
on previously identified items; safety
assessment
and quality verification; and,
NRC Region III requests.
Management
meetings
were held at the site between
NRC and licensee
representatives
on
April 2 and 17,
1991.
Results:
Of the
seven
areas
inspected,
no violations or deviations
were
~s enti7ied in six areas.
One violation was identified (inadequate
post-maintenance
testing - Paragraph
3.a) in the maintenance/surveillance
area.
The inspection identified
a weakness
in the post-maintenace
test in the
maintenance
area
and
a weakness
in the operator's
knowledge of the operation
of the liquid in-line rad monitor system
(RS-1000).
There were
no notable
weaknesses
identified in any of the other areas
reviewed.
~P1
0
During this reporting period, both Unit
1 and
2 operated essentially
at
100 percent
power with no major operational
problems.
On April 19,
1991,
Unit
1 entered
a short duration outage to repair the Unit 1 main transformer
and to perform other maintenance activities.
9105290156
910516
ADOCK 05000315
Q
Maintenance
and Surveillance:
I
The inspector
s review of the surveillance
and maintenance activities during
this reporting period found that most maintenance
and surveillance activities
were performed satisfactorily.
One problem was identified with improper
reassembly
and inadequate
post-maintenance
testing
on the charging
system
Appendix
R cross-tie isolation valve.
1.
Persons
Contacted
DETAILS
'a ~
Mana ement Meetin
- A ri 1
2
1991
American Electric Power/Indiana
Michi an Electric
E.
T.
P.
A.
J.
K.
B.
R.
J.
L.
J.
E. Fitzpatrick, Vice President,
Nuclear Operations,
AEPSC
0. Argenta, Assistant
Vice President,
Nuclear Engineering,
AEPSC
A. Barrett, Director, guality Assurance,
AEPSC
A. Blind, Plant Manager
E. Rutkowski, Assistant Plant Manager,
Technical
Support
R. Baker, Assistant Plant, Manager,
Production
A. Svensson,
Executive Staff Assistant
F. Kroeger, Division Manager, Electrical Systems,
AEPSC
A. Kobyra, Group Manager,
Nuclear Design,
AEPSC
H. Vanginhoven, Supervisor,
Site Design
B. Kingseed,
Senior Engineer,
Nuclear Safety
and Licensing,
AEPSC
R. A. Green,
Engineer,
Nuclear Safety
and Licensing,
AEPSC
NRC
Re ulator
Commission
(NRC)
A.
C;
H.
J.
M.
H.
J.
T.
E.
D.
W.
B.
J.
J.
A.
A.
B.
A.
G.
R.
G.
D.
Davis, Regiona'l Administrator, Region III
Paperiello,
Deputy Regional'dministrator,
Region III
Miller, Director, Division of Reactor Safety,
Region III
Zwolinski, Assistant Director for Region Reactors,
Ring, Chief, Engineering
Branch,
DRS, Region III
Clayton, Chief, Branch 2, Division of Reactor Projects,
RIII
Isom, Senior Resident
Inspector
Colburn, Licensing Project Manager,
Schweibinz,
Senior Project Engineer,
DRP, Region III
Passehl,
Resident
Inspector
Pegg, Intern,
b.
Mana ement Meetinq - A ril 17
1991
Ameri can
E 1 ectri c Power/Indi ana
Michi an Electr ic
D.
T.
S.
A.
L.
K.
J.
R.
H.
0.
J.
A.
S.
R.
E.
A.
Williams, Jr., Senior Executive Vice President,
AEPSC
Argenta, Assistant
Vice President,
Nuclear Engineering,
AEPSC
Brewer, Manager,
Nuclear Safety
and Licensing,
AEPSC
Blind, Plant YIanager
Gibson, Assistant Plant Manager-Projects
Baker, Assistant Plant Manager-Production
Rutkowski, Assistant Plant Manager-Technical
Support
Green,
Engineer,
Nuclear safety
and Licensing,
AEPSC
Nuc'lear
Re ulator
Commission
(NRC)
-K. M. Carr,
Chairman
A. L. Vietti-Cook, Chairman's
Technical Assistant
'.
J. Paperiello,
Deputy Regional Administrator, Region III
J.
A. Isom, Senior
Resident
Inspector
D. G. Passehl,
Resident
Inspector
E.
E. Hayden, Public Affairs staff
c.
Routine Ins ection
- A. A. Blind, Plant Manager
J.
E. Rutkowski, Assistant Plant Manager - Technical
Support
- L. S. Gibson, Assistant Plant Manager - Projects
- K. R. Baker, Assistant Plant Manager - Production
- B. A. Svensson,
Executive Staff Assistant
- J. R.
Sampson,
Operations
Superintendent
P.
F. Carteaux,
Safety
and Assessment
Superintendent
T. P.
Bei lman, Maintenance
Superintendent
- T. K. Postlewait,
Design
Changes
Superintendent
- L. J. Matthias, Administrative Superintendent
J. T. Mojcik, Technical Superintendent
- Physical
Sciences
- M. L. Horvath, guality Assurance
Supervisor
D. C. 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
May 3,
1991.
2.
0 erational Safet
Verification (71707
71710
42700)
Routine faci.lity operating activities were observed
as
conducted
ir, the
plant and from the main control rooms.
Plant startup,
steady
power
operation,
plant shutdown,
and system(s)
lineup and operation
were observed.
The performance of licensed
Reactor Operators
ard Senior Reactor Operators,
and of Auxiliary Equipment Operators
was
observed
and evaluated
including procedure
use
and adherence,
records
and
logs, cohmunications,
and the degree
of professionalism of control
room
activities.
The Plant Manager, Assistant Plant Manager-Production,
and the
Operations
Superintendent
were we'l-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,
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 emergency 'systems,
radiation monitoring systems
and nuclear reactor protection
systems,
as
applicable.
Unit 1 began
the inspection period at 100 percent
power and operated
routinely until. April 19,
1991,
when
a planned
19 to 27 day outage
began to repair or replace, if necessary,
the main transformer
due
to elevated
levels of combustible
gas.
The outage
was also planned
to repair,a body-to-bonnet
leak on Chemical
and
Volume Control
System valve 1-CS-536.
The main transformer
was in the restoration
phase following repair at the
end of this inspection period.
Other
major activities that were accomplished
included replacement of'he
East Essential
Service
Water Pump,'aterial
condition upgrades
of
the Emergency Diesel Generator
CD, replacement
of the West
Centrifugal Charging
Pump Lubricating Oil Pump,
balance of the
No.
13 Reactor
Coolant
Pump,
and replacement
of the Emergency Boration
Flowpath to Charging
Header Suction valve 1-gMO-410.
The outage
appeared
to be well managed
and all of the scheduled activities were
completed
as intended.
The inspector
accompanied
licensee
personnel
on the containment
closeout tour and noted minor external boric acid
leakage
on
some valves.
The licensee
evaluated
and wrote job orders
to address
these.
The outage
was slightly ahead of schedule at
the close of the inspection period, with the unit in NODE-3 and with
startup testing
in progress.
b.
Unit 2 operated routinely at
100 percent
power throughout the
inspection period.
There were
no significant power reductions
throughout the period.
No violations, deviations,
unresolved or open items. were identified.
3.
Maintenance/Surveillance
(62703)
(42700)
(61726)
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
wa's performed
as applicable.
The inspector also reviewed Technical Specification 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 0
The inspector's
review of a corrective maintenance activity documented
on Job Order A49131 for valve 1-CS-536 (Unit 1 Chemical
and
Volume
Control System
(CVCS) to Unit 2
CVCS discharge
header),
and his
discussion with the licensee's
maintenance staff on the adequacy
of
the subsequent
post-maintenance
test,
found that because
inadequate
post-maintenanc'e
testing
was performed
on I-CS-536, significant
body-to-bonnet
leakage
was not identified, which placed both units in
a 60 day Limiting Condition for Oper ation
(LCO).
The
LCO was
scheduled
to expire
on April 28,
1991.
Valve 1-CS-536 is a'four inch Conval
Clampseal
valve and is required
to be manually cycled during
a fire as postulated
in 10 CFR 50
Appendix
R, to support the shutdown functions of Unit 2.
During the
1990 Unit 1 refueling outage,
valve 1-'CS-536
was found to be leaking
past its seat.
Consequently,
the valve was disassembled
and the valve
disc and seat
were repaired.
The inspector's
discussion with the
licensee
maintenance staff indicated that during reassembly
of the
valve, the "timing .shim"
may have
been
cocked in such
a way as to
prevent
an adequate
body-to-bonnet'ealing
surface.
The inadequate
sealing of the body-to-bonnet
was not found during post-maintenance
testing of the valve in December of 1990,
because
the specified
post-maintenance
test for leak inspection
was
done with the valve in
the closed position.
Because of valve design
and the source of the
hydrostatic test
medium used,
the pressure
which would have identified
a leaking body-to-bonnet joint was isolated from this region of the
valve with the valve closed.
Although another test
was performed
which cycled the valve to verify its position indicator on the reach
rod,
when this test
was performed,
there were
no requirements
to have
the valve pressurized,
nor was it pressurized
because
of other
unrelated
circumstances.
As
a result,
no pressure
was applied to the
valve when it was cycled and therefore
leakage
from the valve
body-to-bonnet
area
was not detected.
However,
on February
27,
1991, during cycling of opposite Unit 2
crosstie
valve 2-CS-536 after
a packing adjustment,
a significant
body-to-bonnet
leak was identified on 1-CS-536
(see
NRC Inspection
Report 50-315/91004(DRP);
50-316/91004(DRP) ).
When 2-CS-536
was
cycled, full discharge
pressure
from the Unit 2 charging
was
applied to the body-to-bonnet
region of 1-CS-536,
which was not
adequately
sealed,
and subsequently
leaked.
Because
of this leak,
the licensee
conservatively
declared
valve 1-CS-536
The
problem placed Unit 2 in a 60 day Limiting Condition For,Operation
(LCO), expiring on April 28,
1991.
Although the licensee initially intended to repair valve 1-CS-536 at
power and submitted
a Temporary Waiver of Compliance
Request to the
NRC to avoid
a shutdown of Unit 1, this request
was retracted.
The
licensee
chose to repair the valve during the planned Unit 1 outage
in which
r epairs to the main transformer
were planned.
The repair t'o
1-CS-536
was completed with the unit in
t~ODE 5, during the beginning
of the outage.
The inspector's
review of the job order and interviews with the
wor kers during the repair of I-CS-536 found that the work was
.performed satisfactorily.
The only problem experienced
by the
licensee
was that the replacement
valve's bonnet
and yoke assembly
had threads that'ould not properly engage
the threads
on the existing
body,
so the bonnet
and yoke assembly of the old valve were re-used.
The licensee
had anticipated this contingency.
The maintenance staff
did use the stem assembly
and packing cartridges
from the
new valve.
A small
amount of lapping
was also performed
on the seat
in the body
of the "old",valve due to slight scoring.
The reassembly
was
completed
and proper post-maintenance
testing
was satisfactorily
performed.
Valve 1-CS-536
was returned to OPERABLE status
on
April 21,
1991.
The inspector
noted that unlike the December
1990 test,
the
post-maintenance
test for the repair of 1-CS-536
completed
on
April 21,
1991 included
an
ASNE Code
YT-2 examination.
The VT-2 test
consisted of a visual inspection for external
leakage,
under normal
operating
pressure,
with the valve in the open position.
The
inspector
noted the results of the VT-2 examination indicated zero
external
leakage.
Also, the inspector
noted acceptable
post-maintenance
test results for internal leak by and valve cycling.
.
10 CFR 50, Appendix B, Criterion XI, as
implemented
by the
D. C.Cook
Updated Quality Assurance
Program Description, Section
1.17.11
(Test
Control), requires that post-maintenance
test prerequisites
be
specified in test procedures
and in the post-maintenance
tests that
are performed in accordance
with-established
programs to demonstrate
that structures,
systems,
and
components will perform satisfactori ly
in service.
The failure in December. of 1990, to establish
the
necessary
post-maintenance
test prerequisite
to pressurize
the
body-to-bonnet
region
and verify Code pressure
boundary integrity,
is an apparent violation of 10CFR50 Appendix B, Criterion XI,
(Violation 315/91010-01).
The inspector
reviewed
a licensee
work activity documented
on Job
Order A57382, associated
with the Unit, 1 Emergency Boration Flowpath
Valve 1-QNO-410.
The valve tripped
on thermal overload during
a
weekly surveillance test to check the emergency
boration flowpath
for blockage.
During the test,
the valve had failed to indicate the
full open position,
and Naintenance
Department
personnel
found upon
investigation that the valve disc
had
jammed into the seat.
The
cause of the problem was
a too high torque switch setting.
The
licensee
is still investigating whether the torque switch was
mispositioned
or had drifted from the proper setting.
Motor operated
globe valve I-QNO-410 controls the flow of fluid from
the boric acid transfer
pumps to the emergency
boration line.
The
valve is operated
to initiate emergency boration flow directly to
the suction of the charging
pumps.
J li
0
The inspector
reviewed the procedure
- 12 NHP 5021.001.009,
"Disassembly,
Inspection,
Repair and Reassembly
of Velan Manual
and
Motor Operated
Gate Valves" (rev.3), which was used to work the
valve.
The procedure
was used for disassembly
and reassembly
of the
valve only, and was found to be proper ly documented.
However the
inspector
noted that the procedure
was written for work associated
with a gate valve,
and I-(NO-410 is a globe 'valve.
The inspector
questioned
whether
a more appropriate
procedure
to use would have
been **12 NHP 5021.001.052,
"Inspection
and Repair of Hand and Motor
Operated
Velan Globe Valves.."
The licensee replied that procedure
- 052 is used for work associated
with bonnetless
valves,
and that the
database
the plant uses to prepare
such jobs specified that procedure
.009 be used.
Procedure
.009
was
used only to disassemble
and
reassemble
the valve and
was adequate for those
purposes.
However,
it also appears
the licensee
does not have
an adequate
procedure
to
address
inspection
and repair of globe valves with bonnets
like
1-(NO-410.
The licensee replied that procedure
.009 would be
modified to address
Ye'1an globe valves.
The modifications would
apply only to the section of the procedure that addresses
the plug
and seats
of the valve.
Upon disassembly
the valve was determined to
be irrepairable,
and
a spare
valve was unavailable
from the licensee's
stock.
A search
was begun for a suitable
replacement
valve, which
was finally obtained, through Westinghouse.
A modification package
was prepared
as the licensee
was unable to procure
an exact
replacement.
The upstream
and downstream piping was modified to
allow the valve stem to sit vertically.
Some pipe supports
were
also re-configured.
A post-modification hydrostatic test and,valve
stroke for Inservice Testing were performed
and the results
were
satisfactory.
The post-maintenance
tests for leakage
and valve
position indication were performed with satisfactory results.
The
inspector
reviewed the Operations
Department surveillance
procedures
for the Boration Flowpaths,
which included
a functional test of
l-gN0-410.. The results of the surveillances
were satisfactory,
and
all acceptance
criteria were met.
The inspector
observed
corrective maintenance
on valve 2-lNO-220
(3-way selector
va1ve for No.
stop
valve) and reviewed Job Order B21616, which was written to document
the activity.
The maintenance activity involved
a repack of the
valve because
of excessive
packing
leakage.
Valve 2-NNO-220 is used
for testing
the two pneumatically-operated
dump valves associated
with no.
main steam stop valve
(NSSV).
The
review found that the corrective
maintenance
was performed
satisfactorily.
Post-maintenance
testing for leak inspection
and
valve stroke
was also performed satisfactorily
and all acceptance
criteria were met.
The
NSSV was returned to OPERABLE status within
the time frame allowed by the Technical Specification Limiting
Condition for Operation
(T/S LCO).
The licensee
decided to work the valve as part of the attempt to
reduce
the large backlog of'pen job orders,
roughly half of which
were written to address
leaking valves.
The Maintenance
Department is
in the process of forming a "valve improvement
team" to address
valve
problems.
The packing
'leak was not of a magnitude that would have
caused
inadvertant
closure of the NSSV, nor did it appear to have
any other noticeable
negative affects
on the
NSSV.
The licensee
made
a voluntary four hour T/S
LCO entry to repair the
valve, because
one of'he
MSSV dump valves
had to be isolated to do
the work.
The valve was repaired
and tested satisfactorily within a
period of about three hours.
The other
dump valve could have lifted
and closed the
NSSV upon receipt of the appropriate actuation
signal, but the valve was
assumed
not to function when required
because
of single-failure consideratsons.
The inspector
observed corrective maintenance
on components
associated
with the Unit
1 East Motor-Driven Auxiliary Feedwater
Pump
(EMDAFP).
Job Orders
(JOs)
A3507 and A53054 were written to
document the activity and were also reviewed.
The work involved a
repack of ENDAFP discharge
valve 1-FW-130
(JO A3507) and repair of
an oil leak on the
pump inboard bearing
(JO A53242).
The observations
and reviews found the work was performed satisfactorily within the
time constraints
allowed by the Technical Specification Limiting
Condition for Operation
(T/S LCO).
Post - maintenance
testing
was
also performed satisfactorily
and all acceptance
criteria were met.
The
pump was
INOPERABLE for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />
29 minutes,
which was within the
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> T/S
LCO Action Statement.
The packing leak on I-FR-130 was noted to be approximately 100'drops
per minute with the
pump running and was discovered
during
a run of
the
ENDAFP during emergency
diesel
generator
load sequence
testing
in October
1990.
The problem was not addressed
during the outage
because it was not identified until the work package
"window" on the
EMDAFP had been essentially
closed.
Thereafter
the problem was not
significant enough,
according
to the licensee,
to warrant removal of
the
pump during plant operation
unless
other jobs
needed
to be
performed.
The packing leak represented
an insignificant amount of
water inventory withheld from the steam generators.
The inspector
noted
no problems with the work and noted that the job order was
properly documented.
The post-maintenance
test consisted of a leak
inspection
and stroke
check of the valve,
and the results
were
satisfactory.
Additionally, no leaks were noted during the mohthly
surveillance
run that was performed after the work and prior to the
pump's
OPERABILITY declaration.
The magnitude of the 'oil leak on the inboard
pump bearing
was
slight, according to the licensee,
as evidenced
by the oi'l drops
found below the be'aring
on the
pump skid.
This problem was
discovered
by an operator while making tours of the plant in
January,
1991.
This work item 'also
was not significant enough to
warrant
removal of the
pump from service during plant operation,
and
was worked with the repack job described
above to minimize the
amount of time the
pump was
removed from service.
Operators
monitor
the oil level in the bearing via
a sight glass
on
a, shiftly basis.
No instances
of unacceptable
oil 'level were noted during tours
by the
plant operators.
A large oil leak would cause
problems if left
One
unchecked
and could stall the
pump.
The repair work involved slight
adjustment to a "slinger ring", which rides
on the
pump shaft with a
close tolerance
to the face of the bearing housing,
and serves
to
redirect
any escaping oil back into the bearing
housing
sump.
An oil
level adjustment
mechanism
was also set because
the oil level in the
bearing
sump was slightly high,
and
may have contributed to the leak
problem.
The post-maintenance
test consisted of a leak. check with
the
pump in operation,
and again
no problems
were noted.
The inspector
reviewed the surveillance test
documentation for the
Et1DAFP that was performed just after the maintenance
work described
above.
This scheduled
monthly test
was also performed to verify
OPERABILITY of the
EMDAFP in accordance
with the Technical
Specifications,
which included verification of the correct position
of all valves in the flowpath.
The inspector
found the surveillance
procedure,
- I-OHP 4030.STP.OI7E,
Rev.5,
"East Motor Driven Auxiliary
System Test", to be complete
and noted
no problems.
The
procedure
instructions
were clear
and all data
was properly documented.
All acceptance
cr iteria were met.
violation, and
no deviations,
unresolved or open
items were identified.
4.
En ineerin
and Technical
Su
ort (37701
37828)
The inspector monitored engineering
and technical
support activities at
the site and,
on occasion,
as provided 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.
The inspector
reviewed the results of the licensee's
evaluation of
degradation
found with the incore flux thimble tubes during eddy
current examinations
performed during the
1990 refueling outages.
The results
confirmed the licensee's
suspicion of flow induced
vibration as root cause.
The flow induced vibration was believed to
have occurred at the lower core plate area
where the vibrations
would be most prominent.
The Unit
1 tube wear was not as
pronounced
as that found in the Unit 2 tubes,
which the licensee
believed
was
probably
due to the different flow characteristics
of the two units.
The licensee
plans to perform
some type of corrective action during
the
1992 refueling outages,
.in an attempt to reduce
the wear rate.
Several
technologies
are presently being investigated.
The licensee
is tending toward application of a wear resistant
coating to the
surface of the tubes,
to improve the lifetime of the tubes while
minimizing the risk of increasing
the vibrations.
The Unit 2 inspections
were performed in the
Summer
and Fall of 1990,
and resulted
in the replacement
of. 10 tubes
and the reposition
20
of 19 tubes.
The Unit 1 inspections
were performed in the Fall of
1990,
and resulted
in the reposition of 29 tubes.
The licensee
made
various submittals to
NRC at the time describing. the eddy current
examinations
and results.
The licensee,
accompanied
by
representatives
from Westinghouse,
made
a presentation
to
NRC at the
Headquarters
office on ApriI'l, 1991 to summarize
the results of
the root cause investigation.
To support the root cause
ihvestigation,
two of the degraded
Unit 2 flux tubes
were shipped to
a hot cell facility for examination.
Additionally, the inspector
noted that
on March 12,
1991, four
isolation valves
on the Unit 2 flux mapping
system were closed
as
a
proactive
means to reduce
the possible
damage to the flux mapping
system should those
tubes experience
a leak.
Three of the four
thimbles that were isolated
(C-7, A-9, and K-2) corresponded
to the
tubes that exhibited the most degradation.
The remaining thimble
(B-13) was isolated
due to its inaccessibility,
which was discovered
during containment
closeout activities during the last refueling
outage.
The isolation of the four tubes is not significant from
a'echnical
Specifications
(T/S) standpoint.
The T/S requires
75 percent of the tubes (or 44 total) be
OPERABLE; there are currently
54
OPERABLE tubes
remaining.
Following cleaning
and testing of the system,
the licensee
found
they were unable to run
a detector
through thimble B-13 to the top
of the core.
The licensee
believed the blockage
was related to the
leak in thimble C-7 that was identified on brune
18,
1990.
The steam
formed in C-7 at the time of the leak may have
caused
some slight
drainage of oil from the associated
ten path gear box, which may
have left an oil residue
in the B-13 tube that the cleaning
process
did not remove.
The licensee
stated that in the event that one of
the thimbles (except
B-13) be
n'ceded for a rod position determination,
the isolation valve could be re-opened for the
map and then isolated.
The thimbles were to remain isolated .at all other times.
The inspector
reviewed the program and the results of the licensee's
zebra
mussel control-strategy.
The program was reviewed
because
treatment
procedures
using the molluscicide "Clam-'trol" had begun
this inspection period for the control of the mussels
in the Service
Water
and Fire Protection
Systems.
The licensee
repo'rted
good
results with the Clam-trol treatments,
based
on mortality rates of
about
95 to 100 percent
in the nonessential
(NESW) and
essential
(ESW) systems
in both units.
Treatments
to
the Fire Protection
System were judged to be
100 percent effective.
The licensee
obtained
some suspect
data while treating
a part of the
Unit 1
NESW and the Unit 2
ESW system
because
of flow adjustment
problems
through the sample points,
and in these
cases
results
were.
conservatively
estimated
to be roughly 80 percent,
which was still
judged acceptable.
The acceptance
criteria for mussel mortalities
has
not been rigorously established,
and will become
more refined
as
the"
licensee
gains
more experience
in doing these
treatments.
11
The treatment
was timed for the present
period in order to assure
"clean" Service Water and Fire Protection
Systems,
in preparation
for a May 1991 chlorine treatment,
which will be performed for scale
and algae control as the lake water temperature
rises.
The chlorine
treatment also prevents
settlement of veligers (free swimming zebra
mussel
larvae), but it does not kill existing adult mussels.
The
licensee's
basic strategy for the zebra
mussel
control is'
two par t
program that includes
a plan to eradicate existing populations
within the plant's
raw water systems,
and
a control program to
.
either ki 11 or hinder settlement of veligers, juveniles,
and adult
mussels within the systems.
In order to monitor the
treatment'esults,
the licensee
connected
"bioboxes" to the treated
systems
at
various
sample points.
The bioboxes
were then
seeded with zebra
mussels for an acclimation period prior to the Clam-trol treatment,
and afterwards
monitored for extermination.
Because
the licensee
has
not yet detected
any significant numbers of zebra
mussels
in their
water systems,
the mussels for seeding
the bioboxes
had to be obtained
elsewhere,
in this case
Lake Erie. 'rogram upgrades
are still being
investigated
which would provide for more accurate
assessments
of
mussel
population density
and distribution.
,No violations, deviations,
unresolved
or open
items were identified.
5.
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.
a ~
The inspector
reviewed
a March 8,
1991 event
when
a sampled but
unmonitored liquid release
occurred.
The problem involved
a release
of the contents of the No.
4 Monitor Tank, which is part of the l!aste
Disposal
System.
In accordance
with the licensee's
procedures,
the
tank was isolated
and properly sampled for release;
however,
the
in-line monitor (RRS-1000)
apparently
"locked-up" in a 'way that
valve 12-RRV-285 (Radioactive Liquid Waste Disposal to Discharge
Tunnels Shutoff) should
have received
a closure signal which would
have isolated
and terminated
the liquid discharge.
The event
apparently
resulted
in a violation of Technical Specification 3.3.3.9.
The inspector
noted that although the release
was well below the
10 CFR20 Maximum Permissible
Concentration
(MPC) limits, there
was
a
lack of operator
knowledge about the system.
Because
the system is
complex, the licensee
took appropriate
steps
to lessen
the burden
on
operators
to help avoid future mistakes.
The Technical Specification required,
in part, that with an
INOPERABLE in-line monitor, at least
two independent
samples
be
analyzed for radionuclide
makeup
and concentration prior to release.
The licensee
believed the monitor was
OPERABLE during the release,
and discovered just as the release
was terminated that the monitor
in fact was
The licensee
reported
the event to the
NRC
in Licensee
Event Report
12
The licensee's
analysis of the sample
showed that the Maximum
Permissible
Concentration
(MPC) value released
was about 3.70E-4,
which was below the
lOCFR20 limit of 1.00
MPC.
The primary cause of
the event
was attributed to
a crushed detector
cable associated
with
RRS-1000.
The licensee
was unable to determine
how or when the cable
was crushed.
A secondary
cause of the event
was operator failure to
recognize
the inoperability condition of the monitor.
The problem occurred
when Operations
personnel
began
the four hour
liquid waste discharge.
About one half hour into the discharge,
operator s received
an "external failure" status
alarm, which
automatically terminates
the release,
and is entered
when sample
flow is out of the normal range.
It is usually indicative of sample
flow adjustment
problems.
In accordance
with the procedure
- 12-ONP 4021.006.004,
"Transferring Distillate From Monitor Tank",
the release
was re-started
and sample flow was re-adjusted.
About one
half hour later, the release
automatically terminated
again because
of
a flow adjustment
problem.
The RRS-1000 monitor then
made several
status
changes
between
"external failure" and "hi fai 1".
The hi fail
alarm should
have provided
a trip signal to the discharge
isolation
valve (RRV-285), and should not have allowed restart of the release.
An operator monitoring the release
erroneously
reasoned
the hi failure
alarm was invalid because
the detector
response
appeared
normal
and
below the high alarm setpoint.
The licensee later determined
the
hi fail alarm was valid, as evidenced
by the monitor values given on
the printout that were obtained at the conclusion of the discharge.-
To prevent recurrence,
the release
procedure
was upgraded
and would
require additional
channel
checks during the release
that would help
confirm abnormal conditions
and ensure
proper operation of the monitor.
A requirement
was also
added that operators
would terminate release
upon receipt of ~an
alarm, including
a trend alarm.
A preventive
maintenance
program was also developed for the monitor.
The crushed
detector
cable
was replaced
and the circuit boards
were removed,
inspected,
and reinstalled.
No problems
were noted that required
replacement
of the circuit boards.
This matter will be reviewed further during followup on the
referenced
Licensee
Event Report.
On April 2, 1991,
two maintenance
instructors
were exploring the
plant scrapyard for items that could be incorporated
into their
program
as training aids.
They discovered
Pump
Seal insert that appeared
to have
been installed at one time.
The
men took the insert into the Training Building where
a Radiation
Protection Instructor surveyed it and found
a small
amount of fixed
contamination.
The plant radiation protection staff was notified of
the incident and
an investigation
commenced.
The seal insert
was confiscated
and personnel
cordoned off the area
of the scrapyard
where the piece
was found.
An extensive
survey of
the Training Building was conducted
and
no radiation or contamination
levels greater
than background
were found.
Seven additional
items
with small
amounts of fixed contamination
were found in the
same
area
13
of the scrapyard
as the insert.
No removable
contamination
was
detected.
Numerous soil samples
were obtained
from the scrapyard
and
no activity greater
than background
was detected.
Well water sample
documentation
was researched
and
no activity above background
was
noted.
The contaminated
items
have
been
removed from the scrapyard
and were taken to the Auxiliary Building.
The affected area of the
scrapyard
was surveyed
and
no further contamination
was found.
The investigation determined that the. contaminated
items were removed
from the Auxiliary Building in the mid to late 1970's.
The plant's
release criteria for radioactive material
were not as conservative
then
as they. are
now.
The requirement
now is that
no material
can
be released if there is any detectable
radioactivity present.
According to the licensee,
this incident presented
no exposure
hazard
to plant employees
or the general public.
No removable
contamination.
was detected
and all soil and water sample
data indicated
no activity
above background.
A full description of the event
was given to
NRC
Region III Radiation Specialists for followup action.
No violations, deviations,
unresolved
or open items were identified.
6.
Actions on Previousl
Identified Items. (92701
92702)
The inspector
reviewed the following six inspection findings from the
NRC
Emergency
Operating
Procedure
(EOP) Inspection
Team.
The
EOP inspection
was conducted
from July 5-15,
1988.
The review of the licensee's
response
to these findings from the
EOP inspection
involved direct observation,
discussion with licensee
personnel
and review of records.
a ~
b.
(CLOSED)
EOP Inspection Finding 316/88017-01:
The
EOP inspection
team found through in-plant and control
room walkthroughs of the
emergency
and abnormal
procedures
listed in Appendix
A of the report
that instrumentation
and control labeling
on the control board
and
" the nomenclature
used in the procedures
were inconsistent.
The
discrepancies
determined
by the inspection
team to be significant
were identified in Appendix
C of the
EOP report.
The
EOP inspection
team
recommended
that the licensee
review and resolve not only those
discrepancies
identified in Appendix C, but also pe'rform
a
procedure/control'board
labeling review and evaluate all discrepancies.
The inspector's
discussion
with the Operations
department staff
found that all discrepancies
identified in Appendix
C of the report
were corrected.
Additionally, procedure/control
board labeling
review was completed
in Nay and June
1991 for Unit I and Unit 2
respectively,
and all significant labeling discrepancies
identified
from this review were corrected.
The inspector also performed
an
independent
check of roughly 20 percent of the deficiencies
identified in Appendix
C and noted that these deficiencies
had been
incorporated
into the licensee's
EOPs.
(CLOSED)
EOP inspection finding 316/88017-02:
The
EOP team
identified numerous
recommendations
to the licensee's
EOPs in
Appendix
B of the report.
The Appendix
B contained
some
20 pages of
14
P
I
~
technical
and writer's guide comments,
observations
and suggestions
for EOP improvements
made by the
EOP inspection
team.
Although the
majority of the
comments
were not regulatory requirements,
the
,
licensee
agreed
to evaluate
the
comments
and take appropriate
corrective action.
The inspector's
review of the licensee's
response
and discussion
with the operations staff found that
a majority of the technical
and
human factor discrepancies
outlined in Appendix
B of the
inspection report were corrected.
Those discrepancies
which were not
adopted for incorporation
as
recommended
by the
EOP inspection
were
documented
in Attachment
B of the
"NRC
EOP Audit Close Out Report."
The inspector's
review of Attachment
B of the licensee's
"NRC
Audit Close
Out Report" found that the licensee's justification for
not incorporating these
discrepancies
appeared
to be reasonable.
Additionally, the inspector
performed
an audit of approximately
10 percent of the procedures
identified in Appendix
B of the
report
and found that these
recommendations
had been
incorporated into
the licensee's
EOPs.
c ~
t
(CLOSED)
EOP inspection finding 316/88017-03:
The
EOP inspection
team identified two procedures
which were determined
to be inadequate.
"Reactor Shutdown from Hot Standby
Panel
due to Control
Room
Inaccessibility" procedure,
2-0HP-4023.001.011,
Rev. 2, contained
insufficient direction in that the majority of the procedure
appeared
to be an inventory of the instrumentation
and controls available'to
the operator at the hot standby panel.
Little guidance
was provided
on the control of the unit following a reactor trip when evacuation
of the control
room is,required.
Additionally, although discussions
with the licensee
indicated that this procedure
was to be implemented
in conjunction with existing plant procedures,
no reference
was
made
to the existing normal,
abnormal or emergency
procedures
within the
hot standby
procedure.
The second
inadequate
procedure,
"Loss of Control Air,"
2-0HP-4023.001.006,
Rev. I did not identify the instrumentation that
would be inoperative following a loss of control air.
The inspector
performed
a limited review of procedure
"Emergency
2-0HP-4023.001.011,
Rev. 3, Oct.
10.
1989.
The
procedure
appeared
to be adequate
and provided adequate
guidance
on
steps
required to place the Unit in a hot standby condition from the
hot standby
panel
in the event the evacuation of the control
room
became
necessary.
The inspector also performed
a limited review of procedure
"Loss of
Control Air," 2-0HP-4023.001.006,
Rev.
2, Apr. 17,
1989,
and found
that it listed the expected
responses
of various instruments/valves
to
a complete
loss of control air,
as well as the expected
response
of essential
valves in the plant due to
a complete
loss of control
air.
15
4
II
(CLOSED)
EOP inspection finding 316/88017-04:
The
EOP ins~ection
team
found out-of-date Attachments
"A" and,"B" used in ECA-O.O,
'Loss of All
-AC Power" and FR-Z.1,
"Response
to High, Containment Pressure."
The
Attachments
are
used to verify that the applicable valves'close
on
either
Phase
"A" or Phase
"B" containment isolation signals.
They
were apparently
not revised
when Attachments
"A" and "B" of E-O,
"Reactor Trip or Safety Injection", procedure
were revised to correct
several
errors
in the listing of valves.
Because
Attachments
"A" and
"B" to ECA-O.O and FR-Z.l were not revised at the time that procedure
E-0 was revised,
these
two attachments
contained
both missing
and
erroneous
information.
Additionally, Phase
"A" isolation valve
2-GCR-314
was not labeled
on the safety injection/accumulator
panel
as
a Phase
"A" isolation valve nor was it included
on Attachment "A",
Rev.
0 or 1.
The inspector
reviewed Attachments
"A" and "B" to ECA-O.O and FR-Z.I
and found that these
attachments
now contain the current listing of
the va1ves
under the proper 'attachments.
However, the inspector
noted
a minor discrepancy with the valve description of 2-ECR-32
which was identified as
"LMR CNTMT air SMPL to RMS/PASS" in
Attachment
B of procedure
E-O,
ECA-O.O and FR-Z. 1.
The valve
description
should read
"LWR CNTMT air SMPL to ERS-2300."
The
licensee.
'issued
a request to correct this deficiency.
Additionally, the inspector
noted through direct observation
in the
control
room that valve 2-GCR-314 is
now labeled
as
a Phase
"A"
isolation valve and it is included
as
a Phase
"A" isolation valve in
Attachment "A" to procedure
E-O,
ECA 0.0 and
FR-Z. I.
(CLOSED)
EOP inspection finding 316/88017-05:
The
EOP inspection
team was concerned with the controls for review and revision of
the
EOPs which existed at the time of the inspection.
The
EOP team
found that prior to final approval
and implementation of the
EOPs,
neither
gA nor other management
control groups
performed
an adequate
detailed technical
review.
Consequently,
the
EOP team
recommended
that the licensee:
(1)
Conduct wa1kthroughs of the procedure
in the control
room and
in the plant.
(2)
Conduct
a verification of technical specification requirements.
(3)
Conduct
a evaluation of the review and revision process
as it
applies to EOPs.
The inspector
was informed by the Operations
department staff that
100,percent
wa'Ikdown on the
EOPS
was completed
in about June of 1989
for both Units and all discrepancies
identified were corrected.
Also, the inspector
was informed that they
had conducted
verification of Technical Specifications
requirements utilizing two
different individuals for the purpose of performing
an independent
check to ensure
containment isolation valves
have
been
included in
the procedures.
Additionally, the licensee
has
issued
procedure
"Emergency Operating
Procedure
(EOP) Maintenance,"
Rev. 0,
16
'
March 31,
1989, which details the administrative requirements
with respect
to detailed verification/validation procedure,
processing
and prioritization comments.
f.
(OPEN)
EOP inspection finding 316/88017-06:
EOP inspection
team
identified a large
number of EOP procedure
comments
(well over
a
hundred
items of various kinds)
had been
accumulated for which the
final action
had not been taken.
The
EOP team viewed the failure to
make timely and thorough revisions to
EOPs concerning certain
known
deficiencies to be
a significant weakness.
, The inspector's
review found that currently there are about
40
comments
which require resolution.
These
comments
were found to be
prioritized into three categories:
"Priority Level
One
(1) - Immediate Action", "Priority Level Two (2) - Expedited Action",
and "Priority Level Three.(3) - Procedure
revision".
Comments
which
were classified
as requiring "Immediate Action" were incorporated within
one work week; those classified
as "Expedited Action" were corrected
within one month;
and those classified
as "Procedure revision" were
incorporated
during the next scheduled
revision.
The inspector
found
one priority 2 comment from May 1989 with no response
due date.
The
licensee
indicated the item would be re-evaluated
for a possible
higher priority, and that
a response
from the licensee's
corporate
office was requested.
Until the
comment is resolved this item wi 11
remain open.
No violations, deviations,'unresolved
or
open
items were identified.
7.
Safet
Assessment/gualit
Verification (37701
38702
40704
92720)
The ef'fectiveness
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.
No violations, deviations,
unresolved or open
items were identified.
8.
Re ion III Re uests
(92705)
The inspector acted
upon
a March 8,
1991
memorandum
from
Nr. Hubert J. Hiller, Director, Division of Reactor Projects
(DRP), to
NRC
Region III Branch Chiefs regarding
recombiners.
The memorandum
17
requested
information on hydrogen
recombiners
installed in Region III
plants
because
of parts dedication
concerns that were identified at
another
U.S. utility.
Attached to the
memorandum
was
a questionnaire
which was completed
and -forwarded to the Region III Technical Support
Staff for compilation and evaluation.
The emphasis
was
on recombiners
stored remotely from the plant site, which would be connected
external to
the containment at need.
The D.
C.
Cook plant has its hydrogen
recombiners
permanently 'installed inside each
containment.
No violations, deviations,
unresolved or open items were identified.
9.
Mana ement Meetin
.(30702)
a ~
A management
meeting,
attended
as -indicated in paragraph l.a, was
conducted at the D.C.
Cook site
on April 2, 1991.
The purpose of the
meeting
was to discuss
various topics of interest,
and to tour the
plant.
The meeting
began with a discussion
related to the
10CFR50 Appendix
R
NRC inspection,
including pre-1984
candor issues,
as were described
in various submittals
by the licensee
to NRC.
The Regional
Administrator was satisfied with the resolution of the candor
issues
and that subject is considered
closed
(EA-82-139).
'b.
Among the other topics presented
by the licensee
staff,. were:
(1)
Engineering/Technical
Support organization
and function as
related to Corporate,
System Engineering,
and Site Design
Perspectives
(2)
Maintenance
Program status
A management
meeting; attended
as indicated in paragraph
1.b,
was
conducted at the D.C.
Cook site
on April 17,
1991.
The purpose. of
the meeting
was to discuss
licensee
performance
and initiatives,
and
to tour the plant.
Among the topics presented
by the licensee staff were:
(1)
Current Unit
1 and Unit 2 status.
(2)
Licensee
performance
indicators for years
1988,
1989,
1990,
and
the following subjects:
Equipment availability
Unplanned
auto
Fue 1
r e liab i 1 ity
(3)
Licensee Strengths:
People
Security
Emergency
Preparedness
18
(4)
Licensee
Challenges:
Eng/Tech Support
Maintenance
10.
Mana ement Interview (30702)
The inspectors
met with licensee
representatives
(denoted
in Paragraph
1)
on May 3,
1991 to discuss
the scope
and findings of the inspection.
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.
19-