ML17325B386
| ML17325B386 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/01/1990 |
| From: | Dey M, Falevits Z, Giitter J, Hart K, Jablonski F, Mendez R, Passehl D, Paul R, Ramsey C, Tella T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17325B381 | List: |
| References | |
| 50-315-89-31, 50-316-89-31, NUDOCS 9003140288 | |
| Download: ML17325B386 (44) | |
See also: IR 05000315/1989031
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION III
Report
No:
50-315/89031;
50-316/89031
Docket No:
50-315;
50-316
Licensee:
Company
1 Riverside
Plaza
Columbus,
OH 43216
License
No:
Facility Name:
D.
C.
Cook Nuclear Power Station,
Units
1 5 2
Inspection At:
Bridgman,
MI 49106
Inspection
Conduc
d:
December
4 through 8,
Inspectors:
Z.
alevits,
TeaWLeader
7-
w.( gp;p~
~D.
se
and
December
18 through 22,
1989
3-j- 9'o
Date
3- -90
Date
Date
5-j- 4'a
Date
j~ Qo
Date
Date
Contractor:
R.
Paul
~'~8 p
aw8k+
T. Fredette
Date
Date/- 90
Date
Approved By
Maintenance
5 Outage Section
8-/- ~rO
Date
Ins ection
Summar
Ins ection
on December
4 throu
h 8 and
December
18 throu
h 22
1989
Re ort No.
50"315/89031'0 "316/89031
9003140288
90030i
ADOCK 05000315
Q
PNU
in-service testing,
support of maintenance,
and related
management activities.
The inspection
was conducted utilizing Temporary Instruction 2515/97,
the
attached
Maintenance
Inspection Tree,
and selected
portions of Inspection
Modules
62700,
62702,
62704,
62705,
and 92701 to ascertain
whether maintenance
was
effectively accomplished
and assessed
by the licensee.
Results:
Based
on the items inspected
during the time frame that the inspection
was conducted overall performance
in maintenance
was considered
satisfactory.
However,
based
on the deficiencies
noted, significant management
involvement and
improvements
in the maintenance
process
was warranted.
A synopsis
of the overall
implementation of the maintenance
program is provided in Section 3.0 of the
report.
There were four violations: failure to follow procedures,
with seven
examples;
failure to provide adequate
and timely corrective action, with two
examples; failure to adequately
document traceabi lity of materials or components;
and failure to provide adequate
test instrumentation
and testing methodology.
Section
CONTENTS
~pa
e
1.0
2.0
2.1
2.1.1
2.1.2
2.2
2.3
2.3.1
2.3.2
2.3.2.1
2.3.2.2
2.3.2.3
2.3.3
2.3.4
2.3.4.1
2.3.4.2
2.4
2.4.1
2.4.2
2.4.2.1
2.4.2.2
2.4.2.3
2.4.3
2.4.4
2.5
2.6
2.6.1
2.6.2
2.6.3
2.6.4
2.7
2.7.1
2.8
2.8.1
2.8.2
2.9
2.9.1
2.9.2
2.9.2.1
2.9.2.2
2.9.3
3.0
3.1
3.1.1
3.1.2
Maintenance..
~
~
~
~
~
~
~
~
~
~
~
~
~
~
13
~
~
~
~
~
~
~
~
~
~
~
~ 15
~
~
~
~
~
17
19
19
20
20
20
21
21
25
...26
27
formation
28
~ .....29
30
30
31
31
31
~
~
~
~
~ 33
33
34
34
34
34
35
35
35
36
36
36
37
37
~
~
~
~
~
~
~
~
~
~
~
~ 37
Persons
Contacted.
Introduction to the Evaluation
and Assessment
of
Performance
Data
and System Selection
Historic Data.
System Selection.
Description of Maintenance
Philosophy
Observation of Current Plant Conditions
and
Ongoing Work Activities.
Current Material Condition
.
Ongoing Work Activities
Ongoing Electrical Maintenance
Ongoing Mechanical
Maintenance.
Ongoing Instrument
and Control Maintenance
Radiological Controls
Maintenance Facilities, Material Control,
and
Control of Tools and Measuring
Equipment
Facilities.
Material
and Test
Equipment Control
Review and Evaluation of Maintenance
Accomplished
Backlog Assessment
and Evaluation.
Review and Evaluation of Completed Maintenance.
Past Electrical Maintenance
Past Mechanical
Maintenance.
Past Instrument
and Control Maintenance.
Vendor Manual Control
Application of NRC Notices,
Generic
and Vendor In
Letters.
Maintenance
Work Control
Engineering
and Technical
Support of Maintenance.
Corporate
and Site Engineering.
System
Engineers
Performance
Engineering
Equipment Failure Analysis
Maintenance
and Support Personnel
Control.
Training and gualifications
Valve Testing.
MOVATS Testing Program..
SOER 86.03
Check Valve Failures
Review of Licensee's
Assessment
of Maintenance.
Audits and Surveillance
Review of Maintenance
Self-Assessment.
Maintenance Self Assessment
guality Teams..
Effectiveness
of Corrective Action.
Synopsis
Overall Plant Performance
(Direct Measures).
Historic Data.
Plant Walkdowns
3.2
3.2.1
3.2.2
3.2.3
3.3
3.3.1
3.3.2
3.3.3
3.3.4
4.0
Management
Support of Maintnance.
Management
Commitment
and Involvement.
Management
Organization
and Administration.
Technical
Support
Implementation of Maintenance
Work Control
Plant Maintenance
Organization.
Maintenance Facilities,
Equipment
and Material Control
Personnel
Control.
Exit Meeting.
.
37
37
37
38
..
38
38
....
39
.40
.40
Appendix A:
DETAILS
1.0
Princi al Persons
Contacted
American Electric Power Service
Cor oration
D. Williams, Jr., Senior Executive Vice President,
Engineering
and
Construction
- M. Alexich, Vice President,
Nuclear Operations
"T. Argenta, Assistant Vice President,
Nuclear Engineering
and Michi an Electric
Com an
"A. Blind, Plant Manager
T. Bestrom,
General
Supervisor,
Production Control
"S. Brewer,
Manager,
Nuclear Safety
and Licensing
P. Carteaux,
Gneral Supervisor,
Mechanical
and Welding
R. Hunsicker, Electrical Supervisor
- J. Kurgan,
Manager,
Nuclear Operations
and Support
"S. Klementowiscz,
Manager,
Radiological
Support
"F. Pisarsky,
General
Supervisor,
Mechanical
and Welding
U.S. Nuclear
Re viator
Commission
"H. J. Miller, Director, Division of Reactor Safety
"B. Burgess,
Section Chief, Division of Reactor Projects
"M. Caruso,
Acting Chief, Performance
and guality Evaluation,
Nuclear Reactor Regulation
"Z. Falevits,
Team Leader,
Division of Reactor Safety
"J. Giitter, Licensing Project Manager,
Nuclear Reactor Regulation
"F. Jablonski,
Section Chief, Division of Reactor Safety
"B. Jorgensen,
Senior Resident
Inspector
"R. Mendez, Assistant
Team Leader, Division of Reactor Safety
"D. Passehl,
Resident
Inspector
"Denotes those present at the exit on January
18,
1990.
Other licensee
personnel
were contacted
as
a matter, of routine during the
inspection.
2.0
Introduction to the Evaluation
and Assessment
of Maintenance
An announced
NRC team inspection of maintenance
was conducted during normal
plant operations
at the Donald
C.
Cook Nuclear
Power Plant during the period
of December
4-8 and 18-22,
1989.
The inspection
was conducted
to evaluate
the
extent that
a maintenance
program
had
been developed
and
implemented.
Three
major areas
were evaluated:
(1) overall plant performance
as affected
by
maintenance;
(2) management
support of maintenance;
and (3) maintenance
implementation.
This inspection
was based
on the guidance
provided in
NRC
Temporary Instruction 2515/97;
"Maintenance Inspection,"
and Drawing 425767-C,
"Maintenance
Inspection Tree."
The drawing, which is attached
to this report,
was used
as
a visual aid during the exit meeting to depict the results of the
inspection.'cronyms
used in this report are defined in Appendix A.
Results of this inspection
were derived from data obtained
by observation of
current plant conditions
and work in progress,
by review of completed work,
and by evaluation of the licensee's
attempt at self assessment
of maintenance
and correction of weaknesses.
Major areas of interest
included electrical,
mechanical,
instrument
and control
and the support
areas cf radiological
control, engineering,
quality control, training, procurement,
and
operations'roblems
identified by the inspectors
were evaluated for effect on Technical
Specification operability and technical
or managerial
weakness.
2.1
Performance
Data
and
S stem Selection
2.1.1
Historic Data
The inspectors
considered
the latest Systematic
Assessment
of Licensee
Performance
(SALP) report and completed
NRC inspection reports.
Primarily, the
inspectors
were sensitive to technical
and managerial
problems that appeared
to
be maintenance
related.
Results of this review indicated that there were poten-
tial weaknesses
with the preventive maintenance
(PM) program,
motor-operated
valves
(MOVs), parts
and material controls, trending, root cause analysis,
and
engineering
involvement.
The inspectors
reviewed plant operations
history data for 1989, to assess
the
license's
performance
in meeting established
goals.
Results follow:
The non-outage
backlog of corrective maintennace
job orders for both units
was
1772; the goal
was 850.
Forced outage
rate for Unit
1 was
1.64/> and for Unit 2 was
1.57/>,
the goal
was less
than
4/o.
Two unplanned
reactor trips occurred
on Unit
1 and'4
on Unit 2; the goal
was less
than
one per unit.
Two of the six trips were attributed to INC,
two to operational
errors,
and two to equipment failures.
Two engineered
safety features
(ESF) actuations
occurred
on Unit
1 and
one
on Unit 2;
a goal
was not established.
No unplanned
safety
system actuations
occurred;
the goal
was zero.
Thirty-two licensee
event reports
(LERs) were issued;
the goal
was 24.
During 1988 and
1989 through the inspection date,
54
LERs were submitted
with 25 attributed to maintenance/surveillance
problems.
Equivalent availability for Unit
1 was 69.3X and for Unit 2, 74.4%; the
goal for Unit 1 was 705 and for Unit 2, 80K.
Cumulative whole body dose for 1989 for both units was
508 (TLD) man-rem;
the goal
was 487.7
(SRD) man-rem.
Although the goal
was not met, the dose
for 1989 was considerably
below the industry average
of 732 man-rem for a
2 unit site
~
Some goals
had been established
to determine if maintenance
was accompli shed
including
maintenance
backlog
and control
room instrument job orders.
However,
the licensee
had not established
goals for measuring effectiveness
of maintenance
such
as the
number of limiting conditions for operations
due to equipment
problems,
the number of power reductions
due to equipment
problems;
percent of
rework,
and failed surveillances.
2.1.2
S stem Selection
The systems
and components
selected for this inspection
were based
on the
probability risk assessment
(PRA) study furnished to the team by the Reliability
Applications Section of the Office of Nuclear
Reactor Regulation
and review of
LERs, Deviation Reports,
Nuclear Power Reliability Data System
(NPRDS)
and
discussions
with the senior resident
inspector.
The systems
selected
were the
System
(AFW), Emergency Diesel Generators
(EDG), and Station
Air Compressors
(CAS).
2.2
Descri tion of Maintenance
Philoso
h
The inspectors
reviewed plant policy statements,
administrative
procedures,
organization charts,
established
goals,
and documents that described
improvement
programs for the maintenance
process.
Very limited maintenance
improvement
programs
were initiated in the la'st several
years.
An organizational
change
took place at the Donald
C.
Cook site
on November I, 1989,
to enhance
outage
and maintenance
management.
The major affect of the reorganization
was combining
the maintenance
group
and the
IKC group into one maintenance
department.
Some
confusion existed
among the maintenance
personnel,
which was
compounded
because
the organization
and individual responsibilities
had not been
documented.
Inter-
views and discussions
with maintenance
personnel
indicated that authority,
responsibilities,
accountability
and interfacing of the various plant groups
involved in maintenance
was not formalized or clearly defined.
Although in one
department,
each
group maintained
independent
internal instructions
and procedures.
Maintenance policies existed only for the instrument
and controls (I&C) group.
Departmental
goals did not exist for any of the maintenance
groups
and station
goals relative to maintenance
were not aggressively
pursued,
consequently,
most
were not achieved in 1989.
The maintenance
philosophy appeared
to be mainly compliance oriented with little
consideration for an effective proactive process.
Maintenance
was primarily based
on Technical Specification
requirements
and
some vendor manual
recommendations;
however, only 893 of 6800 vendor manuals
had been
reviewed
and approved.
The inspectors
could not determine if the licensee's
maintenance
program was
appropriately
balanced with corrective maintenance
(CM) and preventive mainten-
ance
(PM) because
a formal
PM program
had not been established
and the licensee
did not adopt or track established
industry guidelines for maintaining
a ratio
between
CM and
PM.
The licensee's
predictive maintenance
program was at the
early stages
of implementation in the areas of vibration analysis
and oil sampling.
was in the planning staoes
with implementation
planned for sometime
in 1990.
Formal
procedures. did not exist for the predictive maintenance
programs
and trending of results
was not started.
On the positive side,
the licensee
recently initiated
a reliability centered
maintenance
(RCM) pilot program.
RCM is
a concept that is gaining increased
attention throughout the nuclear industry as
a means to systematically
examine
the basis for PM programs
and establish
a more rational
approach to
PM.
An
overall objective of the
RCM program was to completely evaluate current
practices.
Other
RCM objectives
include:
reduce
the amount of CM; establish
frequencies
based
on historical data
and
sound engineering
judgement; redirect
time directed
PM tasks to condition monitored/diagnostic
type
PM tasks;
evaluate
vendor
recommended
PM tasks;
and optimize plant resources
in implementing
an
effective
PM program.
The licensee
has taken credit for the
RCM program
as
a
means to eventually integrate
the existing
PM practices
into a single
PM program
which is based
on
a well documented
and systematic
approach.
This program is
considered
a strength.
The licensee
included three
systems
in the
RCM pilot program:
and Service Water.
The
RCM program staff consisted
of four
contractors,
three
system engineers
and
an
RCM Project Manager.
The licensee
recently initiated the system engineering
program to support the
RCM project,
however,
formal procedures
to govern the program, responsibilities,
and qualifi-
cations requirements
did not exist.
A systems
engineer
was assigned
to each
system currently being assessed
in the
RCM pilot program.
The licensee
also initiated
a Level III Probali stic Risk Assessment
(PRA) in
response
The licensee
planned to incorporate
results into the
RCM program.
Component
and safety
system important measures
will be compared to
RCM results to ensure that important failure modes
have
been
identified and addressed
and that
a particular safety
system received
the
appropriate
degree of attention.
The
PRA also
has applications
to corrective
maintenance.
Importance
measures
for systems
and components
might be used
as
a basis for pr ioritizing the safety significance
and order of performing
corrective maintenance
job orders.
Implementation of PRA techniques will
provide useful
feedback applicable to the maintenance
program
and was considered
a strength.
The plant manager recently established
a monitoring system to better
manage
and
measure
maintenance
effectiveness.
A matrix was developed that related major
topics to key attributes of the maintenance
area,
including criteria from NRC
and other established
industry maintenance
related documents'n
addition,
findings and observations
of NRC inspections,
SALP reports,
and other assessments
will be compiled into each major topical areas.
Each of the topical
areas will
be assigned
to
a responsible
licensee
individual to develop
an action plan to
improve performance,
to develop
a system for measurement
and monitoring,
and
develop appropriate
reporting criteria.
In addition, goals
and objectives will
be established
for each of the topical areas
to improve performance
at the
Donald
C.
Cook plant.
It was too early to assess
program implementation
and
results;
however,
the program itself was considered
a strength.
2.3
Observations
of Current Plant Conditions
and
On oin
Work Activities
2.3. 1
Current Material Condition
The inspectors
performed general
plant as well as selected
system
and component
walkdowns to assess
the general
and specific material condition of the plant to
verify that job orders
had been initiated for identified equipment
problems,
and to evaluate
housekeeping.
The selected
systems
were identified in Section
2.1.2 of this report.
Walkdowns included
an assessment
of the buildings,
components,
and
systems for
proper identification and tagging, accessibility, fire and security door
integrity, scaffolding, radiological controls,
and any unusual
conditions.
Unusual conditions included but were not limited to water, oil, or other
liquids on the floor or equipment;
indications of leakage
through ceiling, walls
or floors; loose insulation; corrosion;
excessive
noise;
unusual
temperatures;
and abnormal ventilation and lighting.
Both units were in operation
and subject
to operating
pressures,
flows, and temperatures.
Two obvious problems
from the walkdown inspections
were the significant number
water,
o" oi> >eeks
<rom the
AFM and
DG systems,
and the lack of
consistency
in tagging deficiencies
in the plant.
Tagging of deficiencies
was
not specifically required,
which resulted
in a lack of consistency.
As a
result,
many deficiencies
were noted,
but not tagged.
Also, several
tags were
found for which a job order did not exist or the job order was completed,
indicati ng
a weakness
in the link between deficiency .identification and wor k
accomplisnmeni.
A number oi the leaks
had already
been identified by plant
personnel,
were tagged,
and
some utilized a temporary arrangement
to catch
and
redirect the leakage to an appropriate drain.
Specific observations
included:
Identification of components
and equipment
was generally
good and was
located
on or near the equipment.
Color coding by a uniquely colored band
around the identification marking was considered
a strength.
Oil was leaking from some
EDG fuel oil transfer
pump regulator
caps
and
buckets
were placed
under the caps to collect the oil; there were numerous
and excessive oil was leaking through the diesel
mounting
bolts; fuel was leaking through
some of the diesel
in
addition, water
leaks were noted by the
EDG jacket water
pump.
In a
letter dated
September
29,
1989,
"Emergency
DG Reliability Status
Report,"
it was stated that analyses
of the diesel jacket water by the plant
laboratory indicated that there
was
some difficulty maintaining the proper
level of corrosion inhibitor due to leakage
from the jacket water
pump
packing.
The licensee
issued job orders
on December
1,
1989, to resolve
these
problems.
Numerous
packing leaks were observed
coming from the
AFM pumps.
Two of the
six pumps
had excessive
leaks but
a job order
had not been written to
correct the problem, which is discussed
at length in Section 2.3.2.2.
The
team also observed
a large
number of system fluid leaks
and approximately
400 catch basins for controlling those that were contaminated.
The licensee
stated
in the ore-exit
on January
12,
1990, that 207 of the leaking valves
had open job orders for repair,
as well as the numerous
steam
and other
liquid leaks noted by the team in the rest of the plant.
Several
safety valves were observed that were excessively
corroded,
incorrectly fitted, or leaking.
In particular,
safety valve SV-71 of the
Component Cooling Mater System,
located
on the Spent
Fuel Pit Heat Exchanger,
was leaking excessively
and did not have
a job oder tag.
The matter of
safety valves is discussed
at length in Section 2.6.4.
Calibration sticker information was inconsistent
for several
instruments
observed
throughout 'the plant.
Non-safety related
instruments
and
indicators
had calibration stickers that were either marked "N/A", were
illegible or were past
due for calibration.
Some calibration stickers
were
blank.
Additionally, containment control air ring header
pressure
indicator,
1-XPI-185,
was off scale high and was overdue for calibration by ten months.
The inspectors
were informed that calibration sticker information for
balance of plant (BOP)
and non-safety related
instruments
would be eliminated
by the conversion
process
to
a
new Instrument
Data System (IDS). The calibra-
tion stickers
would show reference
to IDS information instead of a calibration
due date.
The conversion
process
to the
new IDS program
was on-going at the
time of the walkdown.
An oil pool existed
on the east
end foundation of the east
main feed
pump
turbine; valve
1-DRY-331 had
a significant body to bonnet leak;
and there
was
a significant amount of oil on the base of plant air compressor
2-0ME-41.
Water
seepage
was observed
coming from the walls below grade level of the
screen
wash
pump room.
Mineral deposits
on the walls indicated that the
water seepage
occurred over
a fairly long period of time.
Corrosion
was
noted
on valve 1-BD-142, which became
apparent
when the lagging
had been
removed for work on an adjacent
valve.
The problem of external
corrosion
occurring beneath
lagging should receive additional attention.
Numerous platforms were observed
throughout the plant with vertical ladders
that provided access.
In many instances,
the safety chains installed at
the top of the ladders
were not in use,
which presented
a personnel
safety
hazard.
Ten temporary structures,
material
storage
cages,
were identified by the
licensee
in the Auxiliary Building that
had been in place approximately
three to six years.
The licensee
could not demonstrate'hat
the structures
were analyzed for seismic
impact
on safety related
equipment.
Based
on the
results of plant walkdowns of the ten areas
of concern,
the licensee deter-
mined that three of the structures
posed
a threat to safety related
equipment
during
a seismic
event,
and were therefore dismantled
and
removed.
The
licensee
determined that
a possible threat existed to safety related or
important to safety equipment at the 609'valuation.
Condition Report
(CR)
12-12-89-2014
was issued to review the conditions for possible
upgrading,
replacement
or removal of the temporary structures.
Nine tags
from equipment in the diesel
generator
room and
a switchgear
room
were selected
by the inspectors
to evaluate
the effectiveness
of the licensee's
deficiency identification program.
Open job orders existed for three of
the tags.
For six of the tags,
the work was completed
or cancelled
and
the job orders
were closed.
However, tags
B016950,
B016832,
BQ12209,
B017240,
029643
and
15119
had not been
removed
as required
by procedure
PMI-2290, "Job Orders",
Revision 8, Section 4.4.8.
This requires that
upon
completion of the physical
work required by the job order,
the individual(s)
responsible
for performing the work shall
ensure that all appropriate
follow-up actions are completed.
Section 4.4.8.3 requires that job order
tags
be removed
and discarded
and the appropriate
box on page
2 of the
job order form shall
be marked.
The inspectors
noted that for sev'eral
of
the job orders this section
had
been
marked but the job order tag was
physically hanging
on the equipment.
Additionally, for job order
15119
the explanation for not discarding
the job order tag was that the tag
could not be located.
However, the inspectors
located this tag during
a
walkdown on the Unit 2 diesel
generator
room.
The licensee
appeared
to
have
an excessive
number of tags
hanging
on equipment,
although job orders
were completed or cancelled.
This failure to follow procedures
is an
example of a violation of 10 CFR 50, Appendix B, Criterion
V (50-315/89031-01A;
50-316/89031-01A).
2.3.2
On oin
Work Activities
The inspectors
observed
routine ongoing work in electrical,
I&C, and mechanical
maintenance
areas.
The inspector s selected
these activities from the plan of
the day listing, work assignments
in individual maintenance
shops,
and through
discussions
with individual foremen.
Where possible,
safety significant
activities were chosen for review.
Since both units were in operation,
the
inspectors
could not observe
many safety related maintenance activities;
most
activities observed
were routine
and surveillance activities.
Maintenance activities were witnessed/observed
to determine if those activities
were performed in accordance
with required administrative
and technical
require-
ments.
Work activities were assessed
in the following areas:
work control
and
planning;
management
presence,
involvement,
and knowledge; quality control
(gC)
presence
and involvement; health physics
(HP) support
and hazards;
procedures
available,
adequate,
and used;
personnel
trained
and qualified; materials avail-
able,
adequate
and used;
meausri ng and test
equipment
(MME) and tools proper,
calibrated," and used;
post maintenance
testing
(PMT) acceptance
criteria,
and
performed
as specified.
2.3.2. 1
On oin
Electrical Maintenance
Electrical maintenance
has only recently
been established
as
a maintenance
function
of IEC.
Previously, electrical
maintenance
was integrated with mechanical
main-
tenance.
Established
electrical
safety related
PM requirements
was limited to
circuit breaker
and motor lubrications, battery maintenance/inspections
and
emergency lighting maintenance.
Formal
PM for pump electric motors,
valve actuator
motors
and G.E.
HFA relays
was not established.
Predictive electrical
maintenance
appeared
to have
been limited to occassional
thermographics
on safety related
components.
PM on
BOP components
was limited to required turbine generator
maintenance.
There was
no established
predictive electrical
maintenance
program
for BOP components.
The inspectors
observed
portions of four routine electrical
maintenance activities
as discussed
below.
In addition, detailed observations
were
made of thermal
overloads installed in various motor control centers
(MCC).
8043635
RFC 2900
RFC 1482
Perform
PM on hyrdrogen
recombiner
2-HRI power supply
Pull cables for radiation monitors
Splice copper to aluminum cables
2THP 6030 IMP.250
Calibrate
4kV ESS bus undervoltage
relays
Based
on the observation
of activities
and review of past maintenance,
the
inspectors
concluded that electrical
maintenance activities in the pertinent
areas
described
in Section 2.3.2 were satisfactorily accomplished
by mainten-
ance personnel.
Concerns
were identified with the narrow scope of electrical
PM program, traceability of cables
and aluminum splice kits, absence
of gC hold
points
and evidence of "peer" inspection,
inadequate
test equipment
and method-
ology for testing undervoltage
relays,
and improper installation of thermal
,overloads
in various
MCCs.
B043635 - The inspectors
noted excessive
dust. in both the hydrogen
recombiner
transformers
and power supplies during
a walkdown of the licensee's
switch-
gear rooms.
These
components
were not included in the
PM program.
The
licensee
subsequently
issued
a job order to perform
PM which was completed
on December
7,
1989.
RFC-1482 - The inspectors
observed
several
splices in the
MCC compartments.
Many of the splices
were performed in accordance
with RFC-1482,
which
terminated approximately
40 safety related
power feeds to motors.
A copper
extension
piece
was spliced to the field routed power aluminum cable that
supplies
power to the individual motors.
The engineering
department deter-
mined that termination of the aluminum cable to copper
connections
at the
motor starter in the
MCC compartment
was unacceptable,
therefore
the metal
were used to splice the copper
and aluminum cables.
The design
change
package
did not contain information about the type of sleeve,
the
material of the sleeve,
or the type of splice or anti-oxidizing agent which
is
common
when aluminum and copper are spliced.
Engineering
Design Speci-
fication (EDS) 608,
Revision
1, stated that aluminum sleeves
were of an
electro tin plated finish and specified
approved joint compounds.
However,
the design
change
package
made
no reference
to the type of sleeve
used.
The licensee
stated that the sleeves
were obtained
from stock including the
cable extension
pieces
and cable.
The licensee
could not provide documen-
tation regardi ng the traceabi lity of the cable or aluminum sleeve
because
the information was not written or documented
in the design
package
or other
quality documents
related to RFC-1482.
10 CFR 50, Appendix B, Criterion VIII requires that the licensee establish
measures
for the identification and control of materials,
parts
and
components.
Criterion VII further states that measures
shall
assure
that
identification of the item is maintained
by part numbers or serial
number
either
on the item,
as required throughout fabrication, erection, installa-
tion, and use of the item.
Failure of the licensee
to establish
documented
traceabi lity of the cable extension
pieces
and the aluminum splice kits is
a violation to
10 CFR 50, Appendix B, Criterion VIII (50-315/89031-02;
50-316/89031-02).
RFC 2900 - The inspectors
observed
the installation of a cable
from an area
radiation monitor to a control panel
in the auxiliary building.
The
completed work package
was only partially filled out and
many of the steps
were not filled out. In addition,
no gC inspections
or gC hold points were
established.
The licensee
used
a peer inspection
process
that consisted
of
a qualified maintenance
worker that accompanies
the maintenance
personnel
and verifies
gC inspection
hold points.
The inspectors
observed
several
maintenance
and surveillance activities
and
none involved
a
gC type inspec-
tion; however,
none of the maintenance activities had
gC inspection
hold
points established.
Inspection of maintenance activities was practically
non existent.
The inspectors
concluded that the licensee's
program for peer
type maintenance
inspections
was vague
and suffered
from lack of guidance
and acceptance
criteria.
10
The cable pulling procedure for safety related
components
had two gC
inspection hold points neither of'hich addressed
segregation
of power,
control,
and instrumentation
cables;
separation
of redundant
Class
1E
cables
and non-safety related cables;
maximum allowable cable pull tension
and the sidewall pressure
factor acceptance
criteria; or the allowable
minimum bend radius.
The inspector
noted that procedure
12
MHP 5021.082.005,
"Removal
and Installation of Power
and Instrumentation
and Control Cable",
Revision 8, was
one of the the few procedures
that included
gC inspection
hold points.
2 THP 6030 IMP.250 - The inspectors
observed
portions of the monthly 4kV
diesel start
and essential
bus undervoltage
relay calibration surveillance
performed
under procedure
2 THP 6030 IMP.250,
"4kV Diesel Start,
4kV ESS
Bus Undervoltage
Relay Calibration," Revision
7 and required
by Technical
Specification Section
3'.2,
Engineered
Safety Feature Actuation System
Instrumentation.
The inspectors verified that the voltmeter used
by the
technicians
was in calibration
and the type required
by procedure.
Technicians
indicated that the acceptance
criteria for the undervoltage
relay dropout
was 90.3 to 91.8 volts, which was consistent with the Technical
Specification
4kV Bus loss of voltage values.
The 'inspectors
noted that the
increment the analog
type voltmeter could indicate
was to the nearest volt,
that is,
90,
91 or 92, making the measurement
to the nearest
one-tenth of a
volt unlikely since there are
no division markings
between
the numbers.
The
inspectors
noted that the technicians
interpolated results while the volt-
meter's
indicator
was in motion, that is, in the increasing
or decreasing
direction and documented
the results in tenths of a volt.
The as-left drop
out voltage value of relay 27-3721C
was 91.2 volts and the pick-up voltage
was 100.2.
In addition,
the inspectors verified records for the voltmeter used in
calibrating the relays.
Procedure
2THP 6030
IMP.250 stated
in Section 3.0,
Equipment Required, that testing
personnel
shall
use
type
PA-161 analog voltmeter, or equivalent, with equal
or better accuracy
and
adequate
range to measure
the desired
parameter.
The accuracy of the PA-161
was
+1/o of full scale,
150 volts or +1.5 volts.
The tolerance of +1.5 volts
was the entire range or band of the Technical Specification
acceptenance
criteria drop out voltage from 90.3 volts to 91.8*volts and regardless
of
where -the drop out voltage occurred the accuracy of the test results
were
questionable.
Furthermore,
the technicians
used
a cumbersome
technique for
obtaining data that involved use of hand signals
by two technicians
to
transmit
messages
to indicate the moment the relay dropped out to
a third
technician.
The third technician,
who was not within sight of the first
technician,
adjusted
the input voltage
and responded
to the second
technician's
signal.
The inspectors
noted that the licensee
found the following four diesel start
relays out of calibration:
27-1T21B,
27-1T21C,
27-3T21C
and 27-3T21D.
In
addition,
relay 27-T21A-1 was also found out of calibra-
tion.
The inspectors
determined that these relays
have continuously
been
found out of calibration by the licensee.
Due to problems with the diesel
start relays the licensee
has
increased
the surveillance
frequency
from every
refueling outage to a monthly schedule.
The licensee
issued
CR 8.9-1352 to
document
the out of calibration relays
and was in the process
of issuing
an
LER.
11
The current testing
method
and testing
equipment did not appear
adequate
to measure with sufficient accuracy
the required Technical Specification
surveillance
parameters.
10 CFR 50, Appendix B, Criterion XI, test control,
states
that
a test program shall
be established
to assure
that all testing
required to demonstrate
that structures,
systems
and components will perform
satisfactorily in service is identified and performed in accordance
with
written test requirements
and acceptable
limits contained
in applicable
design design
documents.
In addition, Criterion XI further states
that the
test procedures
shall
assure
that adequate
test instrumentation is available
and used.
Failure to provide adequate
test methodology
and instrumentation
is
a violation of 10 CFR 50, Appendix B, Criterion XI (50-315/89031-03;
50-316/89031-03).
During field observation
and review of MCC compartments
associated
with
the
EDG the inspectors
noted that thermal
overloads
could be placed in one
of two positions,
which was in accordance
with the vendor manual.
The
inspectors
compared field thermal
overload size
and orientation data
with the engineering
data provided by the licensee for 20 motors.
Ten
thermal
overload sizes did not match the licensee's
design information.
In addition,
the licensee
found that"nameplate
motor data verified in the
field did not match the drawing data.
The full load
amps
(FLA) rating of
several
motors
was compared to the design drawings.
Six did not match the
drawings.
The discrepancies
included safety
and non-safety-related
loads.
The inspectors
noted that the thermal overloads installed in MCC compart-
ments
1-ABD-A-2E and
1-ABD-B-1C for the
EDG starting air compressors
were
three sizes
too large,
which would result in the air compressor
motor
operating
in an overloaded condition for an extended
period of time.
An
RFC was prepared
to have the devices
replaced.
In addition, the
inspectors
noted that five other non-safety-related
loads still had the
incorrect thermal overload size regardless
of which FLA was used,
as found
or as noted
on the drawings.
The licensee
indicated that the correct
thermal
overload would be replaced for the above loads
and that the drawings
would be updated to reflect the correct
FLA.
The inspectors
also noted the incorrect setting of thermal
overloads
in
MCC compartment
1-E2C-C-R2D,
which feeds
RHR loop isolation valve ICM-111.
RFC 12-2180 required that the thermal overload heater
be installed
and set
at the low trip current rating instead of the high trip current rating as
found.
The as-found position of the, thermal
overload heaters
was not
required to be documented
when the heaters
were removed during maintenance
because
this was considered "skill of the craft".
The licensee
stated that
if a question
arose
about the position of the heater,
the electrician would
obtain the nameplate
FLA and look up the
MCC vendor manual to determine
the
correct position.
Based
on the above discussion this explanation did not
appear
probable.
The licensee
agreed that the heater in
MCC 1-E2C-C-R2D
was incorrectly installed.
Failure to comply with the requirements
of RFC
12-2180
was considered
a violation of 10 CFR 50, Appendix B, Criterion
V
(50-315/89031-01B;
50-316/89031-01B).
The inspectors
determined that in. 1989
numerous
CRs
and at least
32 Problem
Reports
(PR)
had been written about inconsistencies
between
various design
drawings
and the actual field configuration.
For example
on December
10,
12
1989,
CR 89-2085
documented that flow diagram OP-2-511B-14 did not match
actual field conditions.
On February 2,
1989,
PR 89-220,
documented
that
an inconsistency
existed
between
various wiring prints in the
number desig-
nated for the terminal that was assigned
to another terminal.
On June
16,
1989,
PR 89-580 documented that
an unidentified jumper wire was found
installed in the terminal
bus for VFS-7 while troubleshooting chiller P7
tripping problems.
This jumper would have prevented
the chiller from
tripping on low flow.
The jumper was placed
by maintenance
to jumper
a
faulty switch rather than having it repaired.
In addition, the
IKC super-
visor indicated in the
PR that in the past there
had
been similar jumpers
identified.
On August 23,
1989,
PR 89-969 documented that, contrary to
PMI 2030, drawings maintained
by the maintenance
department did not reflect
the latest revision of drawings listed in the master drawing index.
The inspectors
observed
portions of Emergency
Diesel Generator
Sub Panel
DGAB and 600 Vac Auxiliary Bus 21A MCC2-ABD-A9ESS and identified several
wiring discrepancies.
Subsequent
investigation
by the licensee
determined
that wiring diagrams
PS2-94205-0
and PS2-92320-1
were not in conformance
with field installation.
CRs 89-2055
and 89-2056 were initiated to revise
the drawings.
The inspectors
determined that procedure
PMI-2030 "Document
Control," Revision
10,
was inadequate
because it failed to include the
requirements
that Master Drawing Indexes
be reviewed
by intended
users for
the latest
as built drawings located in the plant master file, which was
denoted
by an asterisk
in the Master Drawing Index.
The inspectors
also
determined that drawings issued
by the document control center
were not
the latest
as built drawings partially because
personnel
were not aware of
the requirements
denoted
by the asterisk
in the Master Drawing Index.
The
inspectors
concluded that management
attention
was weak in the area of
identifying and correcting as-built discrepancies.
Inadequate
procedures
is an example of a violation of 10 CFR 50, Appendix B, Criterion
V
(50-315/89031-01C;
50-316/89031-01C).
2.3.2.2
On oin
Mechanical
Maintenance
The inspectors
observed
portions of 18 mechanical
maintenance activities
as discussed
below:
A001682
A001845
A002213
A007539
A008991
A013632
A014194
A019318
Repair auxiliary building snubbers
Repair
steam leak on valve 1-RCA-1036
Maintenance of reheater
drain control valve I-MLC-401
Change oil in
DG starting air compressor
I-QT-142-CDI
Replace
the backwash
nozzles
in traveling screen
1-3
Repack strainer of south miscellaneous
cooling water
pump
Investigate
and correct problem in the acid
pump
Repair valve 1-DRV-350
13
A017539
A18578
B000265
8000425
B015829
B017262
8017133
B017427
B017 540
Lubricate
AFW and
EDG air compressor
Replace
north misc sealing
and cooling water
pump
Maintenance of drain control valve 2-MRV-470
Temporary
steam leak repair
using Furmanite
compound
Repair Unit 2 main turbine oil coolers
Weld on piping and fittings around 2-B-323
Replace
mechanical
seals
on motor driven
AFW pump
Replace
DG starting air compressor
2-gT-142-CD2.
Maintenance of north essential
(NESW)
pump
in-board mechanical
seal
8018578
Repair south lube oil coolers
17688
Replace
mechanical
seals
on
NESW pump
Based
on the observation of activities
and review of past maintenance,
the
inspectors
concluded that mechanical
maintenance activities in the pertinent
areas
described
in Section 2.3.2 were satisfactorily accomplished
by maintenance
personnel.
Concerns
were identified with misapplication of a thread sealant,
lack of safety precautions
in procedures,
undocumented
amounts of lubrication
used,
use of replacement
parts without engineering
review and lack of acceptance
criteria for pump packing leakoff.
A008991 - The workers
used
a thread sealant to install the
new nozzles
in
the screen
wash
system.
The job order and procedure did not address
the
use of Loctite or any other thread sealant
in the performance of this
maintenance.
A014194 - This job required the workers to wear rubber coveralls,
boots
and
a face shield while working in the acid storage
room.
The area also
required monitoring the atmosphere
for sufficient levels of oxygen.
While
the workers were cognizant of these
precautions
and took appropriate
action,
the job order
and work procedure
contained
no mention of these
measures.
A017539 - The inspectors
observed that routine
PM action
was accomplished
in accordance
with the job order and the applicable lubrication cards.
The
lubrication cards
provided the greasing
locations
and the type of lubricant
to be used,
but provided
no information about the quantity to be used.
The
lubrication card provided
a blank space for the quantity required,
but none
of the cards specified
a quantity.
The lubrication cards for all the
starting air compressors
and the
AFW pumps were also examined
and found to
have
no information provided for the quantity of lubricant required.
B000265 - The repair of valve 2-MRV-470 included replacement
of the
stem.
The specified part No.
1V389035162
was actually incorrect for the required
14
replacement
stem
and
a plug assembly.
Another stem part
No.
1K586935162,
slightly longer than the original'art,
was used for the repair of valve
2-MRV-470.
The replacement
part, class
23, standard,
was not reviewed by
engineering prior to its use for its suitability in this application
because
engineering
evaluations
were only performed
on class
30 safety-
related parts.
B017133 - During a walkdown of the Unit
1 and Unit 2 AFW pump rooms,
the
inspectors
noted that three of the six
AFW pumps appeared
to be leaking
through the
pump packing.
The job order identified excessive
leakage
through the inboard
and outboard
mechanical
seals,
the probable
cause
being
worn seals.
No other job orders
were written for the two remaining
pumps,
which also appeared
to be excessively
leaking.
Although
a job order
had been
issued
the licensee
explained that
a certain
amount of leakage
through the packing
was acceptable
per the vendor instructions,
but the
leakage
was not quantified.
The inspectors
reviewed the
AFW pump vendor
manual
and verified that the instructions require
a small
amount of leakage
for lubrication of the packing.
The manual further stated that shutting off
leakage
from the packing will result in burned packing,
scored shaft sleeves
and possible rotor seizure.
Moreover, the vendor manual
required that the
leakage
be controlled by making adjustments
of the gland nuts following the
startup of the
pump.
The inspector discussed
this last requirement
with two
cognizant maintenance
engineers;
both agreed that the only acceptable
method
for adjusting
pump packing is when the
pump is running.
The inspector
noted
that this requirement
was not specifically incorporated
into the motor driven
AFW pump maintenance
procedure
and not included in the turbine driven
pump maintenance
and procedure.
In addition,
the
pump manufacturer's,
"Pump
Operators'ata"
manual,
Second Edition on page
108, required the operator
to watch the packing carefully when starting
up.
The manual
stated that at
the first sign of heating,
the
pump should
be shut
down to allow the packing
to cool
and that several
pump starts
may be necessary
before the leakage
breaks
through
and the packing
box runs cool.
Additionally, Procedure
12MHP5021.056.002,
"Repair Procedure
for Turbine Auxiliary Feed
Pump,"
Revision 4,
made
no mention of any adjustment
to the packing before or
after the
pump was started.
The licensee
indicated that the procedure
would be revised
to incorporate
the acceptance
criteria.
Failure of the
licensee
to include qualitative acceptance
criteria in their repair
procedure is
an example of a violation of 10 CFR 50, Appendix B, Criterion
V (50-315/89031-01D;
50-316/89031-01D).
2.3.2.3
On oin
Instrumentation
and Control Maintenance
The inspector
observed
portions of seven
I&C maintenance activities as discussed
below.
A014129
Investigate/repair
U-1 pressurizer
heater
fan
failure
A014255
B017523
B043570
Repair
S/G
12 and
13 blowdown sample flow alarms
Repair turbine thrust bearing
lube oil gage
Power
level transmitter
from a
separate
source
15
1
THP 4030 STP.411
2 THP 4030
STP. 510
Solid state protection
system logic and reactor
trip breaker train "B" surveillance
(Unit 1)
Solid state protection
system logic and reactor
trip breaker train "A" surveillance (Unit 2)
12
THP 6030
Calibrate
Based
on the observation of these activities the inspectors
concluded that
maintenance activities in the pertinent
areas
described
in Section 2.3.2 were
accomplished
by skilled, knowledgeable
and conscientious
personnel.
However,
concerns
in the areas
of poor work techniques
on
BOP equipment,
hand agitation
of instruments,
tools beyond calibration date,
improper method
used for
calculating
response
time, failure to have procedures
"in hand,"
and improper
technique
used to clean
and test relays were identified during observation of
the following work:
A014129 - During replacement
of an
SCR fan electronic "paddle" switch, the
inspectors
noted that the technician
soldering the switch .into place did
not exercise
any standard
techniques for electronic soldering.
The solder
joints were not cleaned,
and the switch had to be forced into position
because
the
SCR fan circuit wiring was too large
for the switch's pierced
solder terminals.
It appeared
that
no job briefing had been
conducted
regarding
the size of the
SCR fan wire compared to the replacement
switch.
This activity exemplified the fact that non-safety related
maintenance
jobs
did not receive the
same attention to detai
1
and emphasis
on job planning
as safety related
and Technical Specification work items.
A014255
12
and
13 blowdown sample
low flow alarms did
not operate
when
removed
from service
because
the flow meter indicators
were "stuck" at .3
GPM.
A non-licensed
operator
"tapped" the meter face-
plate,
which caused
the meter indication to drop to 0
GPM and the alarms
operated.
The flow meters
were declared
These
instruments
were Tech Spec related
and
CR 1-12-89-2004
was prepared
by the licensee.
After discussion with both the operator
and
an
IKC maintenance
supervisor,
the inspectors
determined that the "tapping"-of these particular instruments
was
an isolated
case.
The inspectors
discussed
with the licensee
the
negative
aspects
of agitating electrical/electronic
instruments.
B043570
The inspectors
observed
two crimpers in a technician's
work cart
beyond the calibration due dates.
The technician
was aware of that fact.
One crimper
ECO-002
had
a calibration due date of September
2,
1989,
and
the other,
ECOH-1 had
a due date of September
9,
1989.
Although, the work
was non-safety-related,
the attitude of the worker was disturbing because
of the the potential for using the tools when performing either safety
related or non-safety-related
work.
This appeared
to be
an isolated
case.
As discussed
in Section 2.3.4.2, overall control of tools was good.
1
THP 4030 STP.411 - A technician incorrectly calculated
Breaker
time response
from a strip chart recorder trace.
The technician
used the time response
from the trace "trailing" step instead of the
"leading" step.
The procedure
included
an attachment that illustrated
the
proper method to determine
time response
for the breaker,
but this aid was
16
not utilized by the technician until prompted
by the
IKC supervisor
at the
job site.
A review of previous
t'ime response
calculations for this
surveillance
indicated that the calculations
were correct.
2 THP 4030 STP.510 - Paragraph
7.2 of STP.510 surveillance
required
an
operator to manually "rack-in" Reactor Trip Bypass
Breaker "A" to the
"TEST" position and subsequently
to the
"OPERATE" position as
a prelude to
testing
the "A" Train Reactor Trip Breaker.
The operator
was observed
racking in the bypass
breaker without the use of "double-asterisked"
('":)
Procedure
12-OHP 4021.082.018
"Racking In and Out Reactor Trip, Reactor
Trip Bypass,
and
MG Set Output Breakers,"
Revision 2, which was required
to be "in-hand" when performing this evolution, but was not at the job
site.
The licensee
prepared
Problem Report 89-1349 to document the
discrepancy.
Upon further review it was noted that
a reactor trip had
occurred in the past during performance of the
same activity when the
wrong breaker
was "racked".
Failure to follow procedures
is an example of
a violation of 10 CFR 50, Appendix B, Criterion
V
(50-315/89031-01F;
316/89031-01F).
Procedure
STP.510
was also deficient from a
human factors standpoint
in
that
a technician
was required to manually hold
a Shunt Block pushbutton
inside
an energized electrical cubicle for approximately five minutes
( steps
7.3. 14 and 7.3. 19).
During tni s evolution, the technician did not
take appropriate electrical
precautions
such
as
removal of hand jewelry.
12-THP 6030
During inspection of a Time Overcurrent
(IAC) Relay,
the inspectors
observed
a maintenance
technician cleaning
the relay drag
magnet
and disk with the adhesive
portion of a calibration sticker.
Step
8. 1.2-2 of Procedure
IMP.014 "Protective
Relay Calibration", Revision 8,
specified the use of black electrical
tape
when cleaning
IAC relay
mechanisms.
Failure to follow procedures
is
an example of a violation of
10 CFR 50, Appendix B, Criterion
V (50-315/89031-01E;
50-315/89031-01E).
The inspectors
observed
a technician
perform
a cursory inspection of the
relay wiring terminations
and
use
a screwdriver
to tighten terminations
on
the instantaneous
type
PJC relay.
The relay inspection portion
of the procedure
for IAC or
PJC relays contained
no details
on tools or
techniques
to be employed
when checking relay wiring terminations
and hard-
ware for tightness
such
as torque requirements.
Additionally, documentation
concerning
the "as found" condition of relays during inspection
such
as
dirt, debris,
or corrosion,
was inadequate.
The data
sheet
contained
space
for the technician to enter
comments
on the results of relay inspections,
but nothing was documented.
The inspectors
concluded that inconsistencies
existed
in the conduct
and documentation
of electrical
equipment inspections.
A review of the licensee's
NPRDS report revealed
several
instances
of
equipment
problems related to dirt and foreign matter inside electrical
devices
and enclosures.
2.3.3
Radiolo ical Controls
Maintenance
work was observed
in contaminated
and radiation areas
as were
movements of tools/equipment
to and from these
areas;
interactions of workers
with radiological protection personnel
were also observed.
Cleanliness
and
17
housekeeping
appeared
generally
good.
Radiological controls,
posting,
and
labeling were good.
Radiation protect'ion job coverage
and As
Low As is
Reasonably
Achievable
(ALARA) support for major maintenance activities were
considered
strengths.
Through observations
of work in the planning
and implementation
phase,
and
discussions
with licensee
personnel,
the inspectors
determined that radiological
controls were integrated into the maintenance
process.
The ALARA staff appeared
to implement effective
ALARA oversight of maintenance
activities.
The
ALARA staff had good management
support.
Communications
and
the working relationship
between
the maintenance
planning department
had improved.
The ALARA staff attended certain planning meetings,
reviewed engineering
designed
work modifications
and maintenance
work packages
that involved dose producing
jobs, administered
the shielding program,
conducted
pr'e and post-job surveys,
and
wrote the Radiation Work Permits
(RWPs).
In most cases
there
appeared
to be
sufficient lead time to perform ALARA reviews;
Proposed facility changes
are
reviewed by the
ALARA staff.
The licensee
was developing job history files,
a photo library of equipment,
and
dose
saving documentation
to factor lessons
learned into the planning process.
A computer
program will be installed in 1990 that
will provide maintenance
job
planners with historical maintenance
data.
Oose
savings
were achieved
through
use of portable venting systems,
flushing
of valves
and lines, training,
and
use of previous lessons
learned.
Audits by the onsite
QA organization,
an outside audit,
and the corporate office
of the radiation program were performed.
Findings of a recent audit performed
of radiation protection activities were reviewed; identified problems
were
adequately
addressed.
For non-emergent
work, monitoring to support
RWP issuance,
RWP job coverage,
and
use of dosimetry
appeared
good.
Coordination
and data
exchange
between
health
physics
and mechanical
maintenance
for high dose or dose rate jobs was improving.
RWPs were adequately
developed
and detailed.
In most cases sufficient advanced
notice was given to the radiation protection department
so that adequate
radiological controls are
implemented.
Weaknesses
in this area
were also identified as follows:
Sufficient communication,
planning
and adequate
advanced
notice to
HP was
weak for emergent
and unplanned
outage work.
Although this weaknes's
can
cause overall
ALARA pre-job planning
and radiation
surveys to be degraded,
the inspectors
found no evidence that sufficient radiological controls were
not implemented for this type of work.
Frequently,
scheduled
RWP work was not performed
as
scheduled
and resurveys
were performed before the work began.
Resurvey work causes
unnecessary
radiation exposure.
Work activities in the
same
area or on the
same
equipment especially during
18
an outage
were not coordinated so.that
resurveying
and duplication of work
could be reduced.
Work packages
did not always contain sufficient tools/equipment
for work
in radiologically significant areas.
Work packages
should
have sufficient
detail to prevent workers from spending
unnecessary
time in dose rate areas.
Identified outage
work was not always well planned in advance
of scheduling.
There
appeared
to be
a problem with a significant number of outage jobs that
were scheduled
at the
end of the Unit 1 outage
which were insufficiently
planned.
This weakness
caused
unnecessary
personnel
exposure.
There were
a high number of workers assigned
to radiation producing jobs.
Unplanned
outage work performed without sufficient planning
and
communication
led to unnecessary
radiation dose
and inefficient work.
The licensee
maintained
reasonably
low personal
doses.
The total person-rem
for 1989 was 508; the industry average for a
2 unit site was 732,
however,
improvement in outage planning/scheduling
would further reduce station dose.
2.3.4
Maintenance Facilities
Material Contorl
and Control of Tools and
Measurin
E ui ment
The inspectors
reviewed the licensee's
activities in the areas
of facilities,
equipment
and material control to assess
support given to the maintenance
process.
Interviews were conducted with various maintenance
management
and
craft personnel
to determine
the policies, goals,
and objectives;
and follow-up
observations
were performed to determine
the extent to which the plant practices,
procedures,
equipment,
and layout supported
the maintenance
process.
2.3.4. 1
Facilities
The inspectors
observed
the licensee's
mechanical
workshop facilities, tool rooms,
mechanic's
work areas,
and supervisor's
offices.
All the mechanical
supervisors
had offices close to the office of other maintenance
management.
The licensee
had
good work shop facilities, tool rooms
and other work areas
in close proximity.
Other facilities included welding areas,
a sand blasting area,
and
a carpenter
shop for packaging
'equipment to be shipped to outside vendors.
The electrical
maintenance
shop
was being remodeled.
Few provisions were
made
to provide adequate
work space for the craft while the
shop
was being remodeled.
An untagged
spare
breaker
was placed
on
a bench
and breaker
parts were lying on
the floor.
The inspectors
noted that the "Hot Tool Room," located in the Auxiliary Building,
had
a list of hot tools contained there,
and maintained control of the tools
issued or received.
No evidence of contamination of plant areas
or personnel
due to the lack of positive control of hot tools was noted during the inspection.
IKC maintenance facilities were adequate.
The instrument maintenance
workshop
was located adjacent to the turbine bui lding close to the control
room and
auxiliary electrical
areas.
The
IKC superintendent,
supervisors
planners
and
coordinators officer's were located adjacent
to or in close proximity to the
maintenance
shop area.
19
".3.'.2
Material
and Test
E ui ment Control
The inspectors
evaluated
material
storage,
spare parts control,
and measuring
and test equipment
(METE) control.
Weaknesses
were identified with parts
control, procurement,
engineering
involvement,
and planning.
The warehouse facility included both level
A and
B storage
space.
Access to
the warehouse
was controlled,
environmental
controls were adequate,
and
housekeeping
was good.
Controls for consummable
materials
such
as solvents
and
cleaners,
thinners,
paint lubricants,
and gasket materials
were adequate.
A
separate
section
was established
for flammable materials
and those that
required special
handling
such
as hazardous
materials.
The inspectors
determined that the design
change
program did not consider
spare parts
when
a modification to equipment is performed,
which ultimately
results
in lack of spare parts
when equipment fails to perform as designed.
The inspectors
reviewed
a printout of open non-outage
job orders
on hold
for parts.
The sample
indicated that
none
had
a high priority or safety
significance.
k
The work package
completed
by the planner for job order B000265, repair of
valve 2-MRV-470, included
a computer printout from the equipment data
base
which indicated that the required part,
a valve stem,
was available
in
storage;
in fact, three were indicated but only one was needed.
However,
incorrect parts were stored
in
a designated
bin due to
a purchasing error
that caused
the incorrect parts to be ordered.
The mechanic
suspended
work
to search for a substitute part,
found one,
and ultimately completed the
job; however,
actual
use of the substitute part was not documented
and the
substitution
was not evaluated
by engineering.
Even though this was
a
activity, parts control, procurement,
and engineering
involvement were
considered
weak.
Also, as discussed
in Section 2.5,
a potential
generic
weakness
exists with planning because
of an inaccurate
equipment data
base
for establishing. the number
and types of parts in stock.
Control of METE was satisfactory.
Defective or "calibration due" instruments
were segregated
from those in calibration
and acceptable
for use.
Procedures
were developed for the issue,
return,
and recall of MME.
The individual
checking out an instrument;
the work order,
procedure,
or location used;
date
out,
and date returned
were recorded for permanent
records.
Storage of ready
for issue
MME was considered
excellent.
= Inventories were conducted of all
"ready for issue"
METE twice a day.
MTE issued
from the central
equipment tool room,
such as,
torque wrenches
and
dial indicators,
was accounted for by personnel
in the issue
room, with ultimate
control of calibration status
maintained
by the
METE lab.
The
METE lab was
maintained
by six full-time technicians qualified in metrology.
These technicians
conducted calibrations of all on-site
M&TE except the calibration standards,
which
were sent off-site for calibration.
All calibration records
were traceable
to
national
standards.
2.4
Review and Evaluation of Maintenance
Accom lished
2.4. I
Backlo
Assessment
and Evaluation
20
The inspectors
reviewed the amount of work accomplished
compared
to the amount
of work scheduled.
Emphasis
was placed
on work that could affect the operability
safety-related
equipment or equipment
considered
important to safety,
which
included
some balance of plant components.
Maintenance
work backlogs
were
evaluated for cause
and impact
on safety.
A coordinated effort did not exist to identify and track the overall
and
PM backlog.
Periodic reports of backlogs
were issued to management
but the items were not prioritized, separated
by outage or non-outage,
nor
broken
down by
Work backlogs
were separately
kept by the
maintenance
and
IKC groups.
The total backlog varied between
900 and
1200
throughout
1989 with CM at 88K and
PM at 12K.
At the time of the inspection,
an estimated
1400 job orders
were open for
more than
90 days
and
500 were open for over one year.
With the current
maintenance
staff, the backlog of 1400 job orders would take approximately
four months to complete,
which is higher than the three
month industry
average.
Forty-five job orders classified "expedite" or "important" were
backlogged greater
than
90 days.
Several
delays were attributed to non-
availability of parts or jobs awaiting parts.
Although the parts backlog
was large, operability was not affected.
In the mechanical
and welding
areas,
the backlogs
have steadily declined during the past five months.
About 10'" of the backlog
was attributed to administrative
review and closeout.
2.4.2
Review and Evaluation of Com leted Maintenance
The inspectors
selected
the equipment
and systems identified in Section 3.1.2
of this r'eport for further review.
The purpose of this review was to determine
if specified electrical,
mechanical,
and
IEC maintenance
on those selected
systems/
components
was accomplished
as required.
This review included application of
risk-based priority to the performance
and extent of maintenance;
evaluation to
determine
the extent that
RCM was factored into the established
maintenance
process;
evaluation of the extent that vendor manual
recommendations,
Bulletins ( IEB), IE Notices (IEN), Significant Operating
Experience
Record
(SOERs),
and other outside
source
information was utilized; evaluation of the
extent that maintenance
histories,
NPRDS, information,
LERs, negative trends,
rework, extended
time for outage,
frequency of maintenance,
and results of
diagnostic
examinations
were analyzed
for trends
and root causes
for modifica-
tion of the
PM process
to preclude
recur rence of equipment or component failures;
evaluation of completed
JOs for use of qualified personnel,
proper prioritization,
adequate
work instructions, guality Control (gC) involvement, quality of documen-
tation of machinery history, description of problems
and resolutions,
and post
maintenance
testing; evaluation of work procedures
for inclusion of gC hold points,
acceptance
criteria,
ease of use,
and general
conformance
to NUREG/CR-1369.
2.4.2.1
Past Electrical Maintenance
The inspectors
reviewed
19 completed work packages
and
4 procedures
for the
attributes
included in paragraph
2.4.2.
A008279
Measure
the
1AB diesel
generator
and exciter air gas
A012225
Diesel would not maintain
speed
21
A013949
Auxiliary Building Ventilation System tripped
A014428
Locate
DC ground
B006652
Repair computer inverter backup voltage transformer
B012654
Locate
DC ground
1243
2289
4596
Clean, calibrate,
and inspect circuit breakers
Clean, calibrate,
and inspect circuit breakers
Clean, calibrate,
and inspect circuit breakers
020909
Clean
and inspect circuit breaker
21
PHC 4
706162
East
RHR pump breaker would not close
718266
Locate
DC ground
718613
Clean, calibrate,
and inspect circuit breakers
739183
S/G stop valve stuck in test position
91740
Clean, calibrate,
and inspect circuit breakers
MHI-7090
"Maintenance
Department
Inspection
Hold Point
Program,"
Revision
0
PMI-2010
"Plant Manager
and Department
Head Instruction,
Procedures
and Index, Revision
17
RFC 12-2982
Adjust setpoints
of safety related
pump motor
overcurrent relays
RFC 12-3008
Complete modifications for the miscordination
discrepancies
12
MHP 5021.056.002,
"Repair Procedure for Auxiliary Feed
Pump,"
Revision
4
h
12
MHP 5021.082.001,
"Inspection
and Repair of 4kV Circuit Breakers,"
Revision
7
12
MHP 5021.082.003,
"Inspection
and Repair of ITE Type K1600 and
K1600S
600
V Power Circuit Breaker," Revision
4
12
MHP 5021.082.006,
"Power Cable Termination
and Splicing," Revision
6
The work packages
reviewed were generally satisfactory.
Concerns
were identified
with inadequate
action to correct breaker failures,
splices,
inadequate
review of procedures,
and inadequate
control of fuses.
The
method for responding
to and locating dc grounds
was considered
a strength.
22
1243,
2289,
4596,
91740,
718613,
RFC 12-2982
and
FRC 12-30008 - These
items
included concerns
with possible relay coordination
problems.
Based
on
review of the referenced
documents,
the inspector
concluded that adjustments
made to safety related
pump motor overcurrent relays were not required to
be modified because
of the miscoordination discrepancies.
There were
instances
where fuses in the
250 Vdc distribution system did not have the
optimal 2/1 ratio,
however,
the inspector did not identify any instances
wnere tnis had
been
a problem.
Proper circuit breaker
and relay coordination
was maintained
through continuing design
review and control of relay setpoint
sheets.
Procedures
for calibration of relays
and circuit breakers
did not
include reference
to relay coordination
because
the subject is beyond the
scope of those
type procedures.
The licensee
recognized that relay
coordination
was important and that if not properly maintained,
a single
electrical fault could disable
power to one or both trains of safety related
equipment.
A014428,
B012654
and 716826
The licensee
implemented
a process
for locating
ground faults
on battery circuits by use of "D.C. Scout" instrumentation that
superimposes
an
ac signal
on individual battery circuits and indicates
the
faulted circuit by measuring
the lowest resistance
to ground and the highest
pulse magnitude.
During the past year the licensee
had issued
three job
orders to initiate action to locate ground faults.
The inspectors
noted
that in one instance
location of the ground took approximately
two hours,
which was in sharp contrast to the previous practice of operating
several
weeks with a
known ground
on the dc system.
The licensee's
process
for the
prompt location of grounds
was
a strength.
A013949 - On September
9,
1989,
the auxiliary building ventilation system
1-HV-AS-1 motor breaker tripped after five minutes of operation
because
one of the three connections
to the motor had disintegrated.
According to
job order A013949,
the wrong type and size of lugs"were
used to connect
the 'motor leads.
The lugs were too large for the wire and copper materials
were directly connected
to aluminum.
Consequently,
this caused
the
connections
to loosen,
which caused
the overheating
and subsequent
failure
of the motor.
Copper to aluminum connections
are not good practice
because
of the situation just described.
There are
numerous installations of this
type throughout the Donald C.
Cook Plant that have
been there
since the
plant was constructed;
however, significant problems
have not been reported.
706162 - On February 8,
1989,
scheduled
maintenance
was performed
on Brown
Boveri Type 5HK250 4kV Breaker T-1106.
During post maintenance
tests,
the
breaker
would not close
because
the operating
linkage would not reset
due
to hardening of the linkage grease.
Problem Report No.89-150 stated that
the grease
used
was believed to be of a type which would not require
replacement.
On February
27,
1989,
another
type 5HK250 4kV Breaker, T-llD4,
failed to close during
a test because
the linkage failed to reset.
Problem
Report
No.89-245 stated that the cause of the failure was
a build up of
old grease
and dirt in the breaker's
operating linkage.
The problem report
was reviewed
by Plant Assessment
Group (PAG) on March 17,
1989,
and deter-
mined the failure to be insignificant:
Prior to the
PAG review, the licensee
had notified the manufacturer of the failure of the closing mechanisms
in two
Type 5HK250 circuit breakers.
The licensee
requested
assistance
from the
vendor,
who on March 3,
1989,
issued
a
10 CFR Part 21 Report.
The report
was based
on the investigation
by the manufacturer
who determined that the
23
cause of the breaker failures was aging, dirt contamination
and hardening
of the grease
used for lubrication of the breaker's
closing mechanism.
The
breakers
were
17 years old and the closing mechanism
had never
been lubricated
because
of the licensee'
interpretation of the vendor manual,
which is
described
below.
Vendor
manual
1B6. 1.2.7-1,
under the "Lubrication" section for the
5HK250
circuit breakers,
states
in part,
"The circuit breaker requires
no lube ica-
tion during its normal service life.
However, if the grease
should
become
contaminated
or if parts are replaced,
any relubrication should
be done with
NO-OX-1D or ANDEROL grease
as applicable."
The licensee
mistakenly applied
the first statement
of the recommendation
without considering
the
second
statement.
In the
10 CFR Part 21 Report,
the vendor states
in part,
"Both
of these
statements
on lubrication must be considered
together.
The
second
statement
concerning
contamination
or parts
replacement
means that period-
ically, at least
when parts are replaced,
relubrication is required.
Also
dependent
upon the cleanliness
of the environment,
periodic checks for
contaminants
should be performed."
The Brown Boveri representative,
subsequently,
recommended
a procedure for cleaning
and lubricating the
closing mechanism
in order to provide for proper functioning of the breaker.
In an attachment
to problem report 89-245,
the licensee
committed to
revising
the maintenance
procedure
to include cleaning
and l,ubrication of
tne breaker closing mecnani sm on
a periodic basis.
Even though the licensee
was
aware of the problem,
no apparent
action
was
taken
and
seven additional
breakers failed to close
due to hardening of the
linkage grease
as follows:
Problem
Re ort
89-250
89-325
89-325
89-439
89-439
89-439
89-537
~Com anent
East
RHR Pump
East Motor Driven AFW Pump
West Motor Driven AFW Pump
Heater Drain
Pump Supply
1B2
Reserve
Feed to Aux Trans
1B5
Heater Drain
Pump
1D2
'mergency
Power
Feed to TllD
Date of
Concurrence
3/1/89
3/17/89
4/7/89
4/11/89
4/11/89
4/12/89
4/26/89
Problem Report 89-250 evaluated
by the plant Assessment
Group Committee
(PAG) on March 23,
1989, stated
in part, "All indicators point to this
being
an isolated incident.
No specific preventive
measures
are indicated."
Subsequently,
seven other breakers failed to close during testing
due to
binding of the operating linkage.
Failure to take prompt corrective action
is considered
another
example of a violation of 10 CFR 50, Appendix B,
Criterion XVI (50-315/89031-04A;
50-316/89031-04A)
.
Procedure
PMI-2010, "Plant Manager
and Department
Head Instructions,
Procedures
and Index", Revision
17, Periodic
Review 3.14, Section 3.14.1
states
in part, that "All effective instructions
and procedures
shall
be
reviewed
no less frequently than
once every two years.
Several
procedures
had not been
reviewed during the previous
two years,
including:
PMI 405,
MHI 2070,
MHI 7090,
12
THP 6030 IMP.071,
and
12
THP IMP.062.
As a result,
24
the procedures
were not updated to reflect feedback
and changes
to
activities.
This failure to follow procedures
is
an example
.",
a v'ola+i
n
of 10 CFR 50, Appendix B, Criterion
V (50-315/89031-01G;
50-316/89031-01G).
2.4.2.2
Past
Mechanical
Maintenance
The inspectors
reviewed
13 completed
mechanical
work packages
and
9 procedures
for the attributes
included in Paragraph
2.4.2.
The inspectors
noted that in
most cases,
the work packages
indicated that prior approvals for the work were
obtained,
some hold points were noted,
necessary
procedures
were included
and
the calibration status of the
M&TE was noted.
The maintenance
problems
and
resolutions
were documented.
The procedures
were reviewed for completeness,
necessary
approvals,
adequacy
of work instructions,
user friendliness,
inclusion
of (jC hold points
and acceptance
criteria.
The following work packages
and
procedures
were reviewed:
A003612
A004018
A007755
A008177
A010634
A014421
B003137
016548
028121
039847
710327
723568
723762
Test set point of 1-SV-78-AB2 on Unit
1
Rep'air of governor linkage of Unit
Repair fuel injector on Unit
1
Replace
governor
on Unit 1
CD DG
Disassemble
and inspect
check valve 1-FW-132-2
Test set point of valve 2-SV-78-AB2 on Unit 2 AB DG
Repair contorl valve 2-MRV-487
Annual
PM on control air dryer
Repair safety valve
Clean
and inspect
2 AB starting air receiver tanks
Replace Unit 2 TDAFP governor valve bonnett
Annual
PM on Unit 1 control air compressor
Replace
bearing
housing
on
MD AFP
12
MHP 4030.STP.046,
System
18 Month
Inspection",
Revision
1
12
MHP 5021.001.013,
"Fisher Type 7600 Series Butterfly Valves",
Revision
1
12
MHP 5021.002.001,
"Disassembly,
Inspection,
Repair
and Reassembly
of Reactor Coolant Pump", Revision
3
12
MHP 5021.016.001,
"Maintenance
and Repair Procedure for Component
Cooling Water Pump", Revision
2
12
MHP 5021.032.008,
"Emergency Diesel Generator Starting Air Compressor
Starting Air Compressor
Removal
and Installation", Revision
2
12
MHP 5021.032.012,
"Disassembly
and Reassembly
of Emergency Diesel
Engine
and Generator",
Revision
1
12
MHP 5021.032.022,
"Emergency Diesel
Engine Cylinder Head Inlet and
Exhanust 'Valve Inspection
and Repair", Revision
1
12
MHP 5021.032.037,
"Emergency Diesel
Engine Woodward Governor
Removal
and Installation", Revision
0
25
12
THP 6030. IMP.030, "Air Operated
Valve Check Out Procedure",
Revision
4
The work packages
were generally satisfactory.
Concerns
were identified with
documenting
nonconforming conditions,
a procurement
problem that caused
reuse
of defective
equipment,
and failure of MSIVs to meet acceptance
criteria for
closure time.
016548 - The work package for the annual
PM maintenance
of Unit 2 control
air dryer system did not include any procedures
for the maintenance
activities to be performed.
The mechanic
noted that none of the
54 filters
was installed in the six header filters. It was not clear from the record
how long the filters were missing.
A deviation report was not written by
the mechanic,
the work package
did not include any root cause for the
missing filters, and
no special
notation
was included to draw attention of
the planners or management.
723762 - The bearing
housing
purchased
for the Unit
1 East Motor Driven
Auxiliary Feed
Pump,
was unsuitable
and
had to be returned.
The licensee
used
the old bearing
housing.
A010634 - The work package for disassembly
and inspection of check valve
1-FM-132-2 did not include any acceptance
criteria for the torquing of the
cover nuts.
However, the package
did include
a sheet indicating the torque
used
and was signed
by the mechanic
and the
gC inspector.
MSIV Stroke Testing
On January
23,
1990, the licensee
stroke tested Unit 2
MSIV 2-2MRV-210 during the refueling outage.
The Technical Specification
required closure in five seconds;
however,
the valve took over six seconds.
During this test major steam flashing
and splashing
occurred at the
2-MRV-212 dump valve.
The
dump valve leaked
and caused
water to accumulate
on the MSIV, which consequently
caused
the MSIV to close
beyond the
acceptance
limit.
Only valve 2-MRV-212 appeared
to be leaking;
however,
the inspector determined that
on Unit
1 six of the eight
dump valves
had
leaks but only two had job order tags.
A review of past
MSIV slow stroke
times indicated that leaking
dump valves
was the likely cause.
Inadequate
maintenance
procedures
for the
non safety related
dump valve appeared
to
have resulted
in the poor maintenance
and performance of the MSIVs.
For
more information, refer to
NRC Report Nos. 50-315/90005;
50-316/90005.
2.4.2.3
Past Instrumentation
and Control Maintenance
The inspectors
reviewed past
I&C maintenance activities and procedures
for the
attributes described
in Paragraph
2.4.2.
The
ILC maintenance
philosophy
had
recently
been
expanded
to include
some concepts of RCM.
The inspector also
noted
a program unique only to I&C Department.
Procedure
IMP.347 "Job Order
Trend Evaluation Program",
Revision
0,
1989, provided
a method to identify and
disposition multiple instrument failures over
a period of one,
two, or three
years;
however,
actual
trending of failures was considered
slow.
Of 13
instruments
meeting the multiple failure criteria in May 1989, only 4 Trend
Reports
had been evaluated at the time of the inspection.
The
I&C job order
data
base identified 12 other instruments that met the multiple failure criteria
in October
1989, but no evaluations
had
been
done.
Various technicians
and
support
personnel
throughout the
I&C Department
conducted
evaluations
of Trend
26
Reports which appeared
to be the cause of of slowness
in evaluating trend reports.
A dedicated
engineer
had not been
assigned
to the
18C staff.
The inspectors
determined that
I&C maintenance
was primarily basea
on Tecnnical
Specification requirements
and vendor manual
recommendations.
Selected
vendor
source
documents
were reviewed to determine if requirements
specified were
incorporated into appropriate
maintenance
procedures.
The source
documents
reviewed were:
SS2200-761
Dynalco Corp.
Speed Transmitter,
Model
SS2000
No. 320-1382
Airpax Electronics
Device
GEH-2024A
G.E. Multicontact Auxiliary Relay,
Type HFA51
GEI-28803B
G.E.
Instantaneous
Relay,
Type PJCllXl
GEH-1753F
G.E.
Time Overcurrent
Relay,
Type
IAC51A
The inspectors verified that vendor recommendations
were adequately
addressed
in appropriate calibration procedures
except that maintenance
on
HFA relays
was "replace
as fail."
PM was not done although the vendor specified contact
cleaning
as
a maintenance
item.
The inspectors
reviewed
12 corrective maintenance
job orders
completed
over the
past year for quality and completeness
of documentation
for work history, failure
analysis
and post-maintenance
testing.
The inspectors
determined that attention
to detail
was weak
on job order documentation,
which is also discussed
in
Section 2.5.
The following concerns
were identified:
"Scope of Work" documentation
for all
12 Job Orders
reviewed was limited
to "Repair as necessary"
or "Repair and recalibrate".
Post-maintenance
testing documentation
was non-specific or
non-descriptive.
Of the
12 Job Orders
reviewed,
5 listed
post-maintenance
tests
as "tested for satisfactory operation."
Cause of Failure
on
4 of the
12 Job Orders
was not documented.
The "Tech Spec Related?"
block on
4 of the
12 Job Orders
was checked
incorrectly.
Recent job orders
reviewed reflected
an increased
management
awareness
about the
importance of job order documentation.
All of the more recent job orders
were
complete,
concise,
and descriptive
and documented
"causes
of failure."
2.4.3
Vendor Manual Control
Control
and validation of vendor technical
manuals
was weak.
A limited number
of vendor manuals
were reviewed to determine
the optimum
PM frequency for
components
essential
to safe
and reliable plant operation.
All new safety
related
vendor manuals
received at the site were sent to the corporate office
for review and approval.
The
new non-safety-related
vendor manuals
were
reviewed
by plant engineers
or maintenance
personnel.
The manuals
were being
27
sent to the corporate office at
a rate of approximately
50 manuals
per month
for review.
Az. znaz raze,
the ieview would not be completed for nine years.
Out of 6800 vendor manuals,
only 893 were reviewed
and approved at the time of
this inspection
including only 629 safety related
manuals.
The licensee
did not
know the exact
number of safety
and non-safety related
manuals.
The quality of
the current vendor manuals
was poor.
For example,
the
ESW pump vendor manual
(VICS 385) contained six pages of handwritten instructions
on
pump disassembly
and removal.
The manual
review sheet
acknowledged
the additional
pages
but
contained
no validation or justification to support the change to the technical
manual.
It appeared
that the additional
pages
were written by a maintenance
technician
based
on experience
in removing the
pump.
This additional information
was very useful,
but not formally controlled to show the source
document
and
the approval
of such information for use in the plant;
The vendor manuals
had
not been
adequately
reviewed
and released
for use
by maintenance
and other
station staff.
There were two controlling procedures
developed to control this
area:
Donald C.
Cook procedure
12
PMP 2030 VICS.001 - "Control of Vendor
Documents",
Revision
2;
and
AEPSC procedure
5.6 - "Vendor Information control
System
(VICS) for the Donald
C.
Cook Nuclear Plant", Revision
1
~
Based
on the findings noted
above,
the inspectors
concluded that systematic
evaluation of the vendor recommendations
and its incorporation into the
process
was weak.
2.4.4
A
lication of NRC Notices
Generic
and Vendor Information Letter s
The inspectors
reviewed select
instances
of important nuclear industry
events with potential applicability to Donald
C.
Cook in the mechanical
area,
to see
how effectively such information was disseminated
and evaluated.
Incoming information was screened
by plant shift technical
advisors
(STAs),
and then routed to appropriate
departments.
The system
proved effective
in July 1988,
when
a steam
leak developed in an extraction
steam line from
a high pressure
turbine at another
Region III utility.
The licensee
examined similar systems
and found appreciable
pipe thinning in an area
thought to have
low probability of erosion failure.
The affected sections
of pipe were replaced
and have
been included in future evaluations
as part
of the erosion/corrosion
program.
The Erosion/Corrosion
Inspection
Program,
outlined in procedure
MHI-5022 provided effective guidance to evaluate
degradations
in pipe wall thickness
in areas
suspected
of high potential
for erosion/corrosion.
The program
has only been in place since October
1989
so results could not be observed.
Although this program only addressed
piping, the concepts
involved provide the beginning of a plant aging program.
Information regarding industry initiatives in the electrical
area
was not
,
always
communicated
to the appropriate
levels of the maintenance
staff.
For example,
plant maintenance
personnel
interviewed by the inspection
team
had
no knowledge of Information Notice Nos. 83-19
and 88-69,
and G.E.
Service Information Letter No. 44, Supplement
4, regarding the type
HFA
relays potential for binding of the moveable contact fingers.
NRC Information Notices
Nos. 83-19,
88-69 and
GE Service Information Letter
No. 44,
Supplement
4, advised all licensee's
of the
need to ensure that
appropriate
plant personnel
were aware of the potential for binding of the
moveable contact fingers of all
HFA relays manufactured
by G.E.
and the
need for periodic verification of the relay wipe and gap settings.
Although
28
these
systems
are not classified
as Class
lE or safety-related, it was
considered
a weakness
that the licensee
has not given appropriate
conside-
ration to the possible
adverse effect on safety.
The licensee
indicated
that
a
PM program was being developed for these relays.
To the best of the
inspector's
knowledge,
none of these
type relays
had failed at Donald C.
Cook.
PM had not been
performed
on non-latching type G.E.
HFA relays in Class
1E
safety related applications,
the licensee'
Failure Data
Base
and various
drawings indicated that G.E
HFA non-latching type relays
were installed in
the emergency diesel
generator
starting air system,
the containment
ice
condenser refrigeration
system,
and the auxiliary feedwater
system initiation
logic.
All molded case circuit breakers
were not inspected,
maintained
and tested
as specified
in
However,
18 month
PM was
performed
on
some safety related
and containment penetration
molded case
circuit breakers
in accordance
with procedure
Ho.
12
MHP 5021.082.017,
which satisfied the criteria of the generic letter.
To the best of the
inspectors
knowledge,
there
have not been
any molded case circuit breaker
failure.
2.5
Maintenance
Work Control
The inspector
reviewed several
maintenance
records
and job orders to evaluate
the effectiveness
of the maintenance
work control process
to assure
that plant
safety, operability,
and reliability were mainta',ned.
Areas evaluated
were
procedures
for planning
and scheduling,
control of maintenance
job orders,
prioritization and scheduling of work, control of backlog,
and post maintenance
testing.
Results follow.
The maintenance
process
begins with identification of the
need to perform
maintenance
and continues
to post maintenance
testing,
review,
and documen-
tation of actions.
Work controls were delineated
in procedure
PMI-2290,
"Job Order," Revision 8, which described
how to complete
a job order form;
however,
formal procedures
did not exist for the remaining processes.
Procedure
PMI-2290 required that all jobs be planned but only general
guidelines
were provided, although
numerous
informal memoranda
were
available for use
by the planners
and schedulers;
the procedure
was
silent about the scheduling
process.
Planners
and schedulers
lacked job descriptions.
Among other tasks,
planners identified the required work procedures,
spare parts,
and post
maintenance
tests;
however,
formal training had not been provided to
either planners
or schedulers
in the respective
processes.
Interviews with planners
and schedulers
indicated that there
was
no
integrated
approach
to work planning,
scheduling,
and coordination in
the maintenance
organization.
Planners utilized an equipment data base, Facility Data
Base
System
(FDBS).
The
FDBS included data
such
as
component
names,
identification numbers,
locations,
manufacturers,
serial
numbers,
reference.-drawings,
applicable
procedures
and technical
specification,
vendor manuals,
parts data,
and
more.
These
data
were controlled and verified by the records
management
29
group;
however,
a formal feedback
system
from field users
was not in place
to assure
continued accuracy of the data,
which were frequently used for
job planning.
Maintenance
personnel
stated that retrieval
time was slow for computerized
data,
the data
base
and history were incomprehensive,
erroneous,
and
ineffective for use in planning activities.
0
Pre-job planning
was done only on major jobs.
Planners
rarely reviewed
previous job orders or researched
similar component failure records to
evaluate
the extent of a problem or for potential
common
mode failure.
This
probably occurred
because
completed job orders
lacked adequate
descriptions
of the problems,
the work done or the possible
cause,
even though
each job
order required the recording of such information.
Usually the job order
had
marked "not applicable" in,the
space
provided for stating the reason for the
work.
Only 2 of 40 job orders
reviewed
by the inspectors
had reasons
stated
for the work.
This weakness
affects planning
and determination of root cause
analysis,
and trending of failures.
This is also discussed
in Section
2.4.2.3.
Results of completed
maintenance activities
such
as problems encountered,
possible
cause of the problem, or actual
man-hours
expended
were not normally
fed back to the planning
and scheduling
departments,
nor to engineering for
needed
adjustments
of the
PM program to preclude
recurrence
of component
failures.
Scheduling
and coordination
had not been established
for CM,
PM, and
survei llance activities
on the
same piece of equipment,
which resulted
in
an increased
amount of equipment
downtime.
For example:
PR-89-195 stated
that the job order
had to be returned
because
design drawings were not
included in the work package;
PR-89-569
documented
the lack of coordination
of activities
on the
same piece of equipment
between construction
and main-
tenance
departments
that resulted
in workers receiving unnecessary
increased
exposure
to radiation;
PR-89-639
documented
that the maintenance
department
submitted
a clearance
to tag out components for maintenance
already completed,
which resulted
in unnecessary
removal of equipment
from service
by operations
and "standing alarms" in the control
room for six days.
Both planning
and scheduling activities were considered
weak.
2.6.
En ineerin
and Technical
Su
ort of Maintenance
2.6.1.
Cor orate
and Site
En ineerin
Engineering
support to plant maintenance
came
from the corporate office and the
plant engineering staff.
Three corporate divisions, nuclear operations,
nuclear
plant engineering,
and electrical
systems,
supported
the plant.
The Nuclear
Engineering Division (NED) consisted
of four sections
including mechanical
and
chemical
engineers.
The Maintenance
Department at the plant had three mechanical
engineers,
one electrical
engineer but no IKC engineer,
and
had to heavily depend
on the plant performance 'engineers
and the corporate office for engineering
support.
30
Maintenance
engineers
were primarily involved in plant modifications
and procedure
revisions applicable to
a specific area of expertise.
Maintenance
engineers
had
job descriptions
that defined responsibilities
which did not include involvment
in routine review of job orders unless specifically requested;
therefore
only
obvious generic
problems would be identified.
2.6.2
S stem
En ineers
The "System Engineer" concept
was relatively new and only three engineers
had
been assigned
system responsibilities.
The average
longevity on the job was
about
two months.
The system engineering
program
was defined in an interface
agreement
between
the corporate office and the plant;
however, plant procedures
had not been
developed
to implement the program.
Draft position descriptions
were developed for the three
grades
of system engineers.
One
system engineer
indicated that
he followed the system's
operation
and was informed of major
events,
but did not receive
any completed job orders for review and evaluation
of equipment failure trends.
2.6.3
Performance
En ineerin
Performance
engineers
evaluated
performance
in the areas of thermogoraphy
and
included vibration analysis for equipment
such
as
pumps,
fans,
and air compressors.
Results of the vibration monitoring were reported
to station
management if
problems occurred;
however,
no trending of the vibration monitoring results
was
performed
on individual equipment.
equipment
was purchased
about
a
year ago.
Five persons
were trained in its use;
however,
procedures
have not
been developed for implementing thermography
techniques
including the equipment
on which thermography
could be effectively utilized.
2.6.4
E ui ment Failure Anal si s
The inspectors
evaluated
the reporting of equipment failures to the Nuclear Plant
Reliability Data
System
(NPRDS)
and related
correspondence
which indicated that
reporting of fai lures to the
had
been satisfactory.
The use of NPRDS and other data
and information were reviewed to determi ne if
root causes
of failures and any necessary
corrective actions
were taken.
There
were
no formal programs
in place to address
concerns
associated
with plant aging
although
based
on
NPRDS data
some of the elements
may exist.
The cause
codes
used to identify the reason for component/equipment
failures does
however include
a category labelled "normal wear/aging".
The licensee
also
has
a formal program
established
to trend
and track pipe wall erosion
and corrosion which is described
in Section 2.4.4.
A review of all job orders closed out in the past year both
maintenance
and
IKC, which were attributed to "normal wear/aging" indicated that
many jobs received that cause
code
when the other choices did not fit or when
little or no root cause
investigation
was done.
It seemed
to be used
as
a default
value for
a cause
code
and as
such provided little value in determining the
characteristics
of plant aging at the facility.
Component Failure Analysis Reports
(CFAR) derived from NPRDS data for
Unit
1 and
2 for the 18-month period from December
1987 through
May 1989
were reviewed.
Several
components,
about
10 categories,
had significantly
higher failure rates
than the industry average.
For example,
the failure
31
rate of safety valves
exceeded
the industry average
by a factor of about
4.
Failure categories
were listed as failure to open within acceptable
ranges
or failure to reseat.
There
have
been
39 such failures at Donald
C.
Cook since
March 1986,
and several
valves
have repeatedly failed by
this mechanism.
The cause of failure to reseat
provided in the
NPRDS were
attributed to dirt, wearout,
or unknown causes.
Specific observations
of
safety valves are described
in Section 2.3. 1.
A root cause of these
problems
was not given.
Several
individuals were interviewed to determine
the analyses
conducted
and corrective actions
taken to address
the problem.
The
NPRDS supervisor
stated that the
CFARS were sent to various department
managers
who were
responsible
for taking appropriate corrective action.
The maintenance
department
manager
stated that the'orporate
nuclear engineering
department
was responsible for determining corrective actions,
and stated that
NED had
advised
the plant that the events
were isolated
and
a detailed investigation
of the problem was not necessary.
NED engineers
were interviewed but were
not aware of the
CFARS.
The inspectors
reviewed various
memoranda
about
this subject
between
the plant and corporate office and noted that there
was poor communication
between
the plant and corporate
technical
support;
in January
1987
a superficial investigation of the problem was done
by
engineering;
there
was
no specific analysis of the root cause of the
failures;
and
no corrective actions
were initiated or planned to address
the problem.
The ISI section supervisor
stated that
a preventive mainten-
ance
program for the safety valves did not exist and
had not been established
as
a result of budget
constraints'ased
on the above,
the inspector concluded that response
by the licensee
to this problem was not effective.
A detailed
study was not conducted
to
investigate
an obvious negative
trend and determine
the root cause of the
failures including failure mode
and appropriatness
of application.
During the review of NPRDS data,
CRs,
and
PRs for 1989, the inspectors
noted
that numerous entries identified an adverse
trend concerning installation
and control of fuses.
For example
in April 1989,
PR-470 documented
that 400A
fuses
were installed in batter charger
1AB1+2 and
1CD1+2
DC transfer cabinet
but drawings specified
300A.
In May 1989,
PR 89-406 documented that load was
shed
on bus
T11A and TllB due to inadvertent
removal of fuses during perfor-
mance of maintenance activities, which resulted
in a total loss of the West
RHR pump.
In May 1989,
PR 89-572,
documented that heat trace circuits had
20A fuses installed, while design drawings specified
15A fuses.
In August
1989,
PR-872
documented that fuses installed in Unit 1
CRCD Circuit ¹7 were
40A fuses
instead of the
35A called for by the drawing.
Finally, in December
1989,
PR-89-1342
documented
that fuses installed in HCC 2-AN A compartment
3D were
SA while the drawing specified
10A.
On July 21,
1989,
PR 89-907
was prepared after
a review of PRs by Shift
Technical Advisor personnel
identified numerous
problems with fuses or
breakers.
Four of the
PRs were written between April and July 1989'he
licensee
stated
in
PR 89-907 that "Identification of fuse/breaker
related
Problem Reports within a 22 month period of time created
the perception of
a possible
adverse trend."
PR 89-907 was closed,
but at least
two additional
PRs,89-872
and 89-1392 were written to document the installation of
incorrect fuses'he
inspectors
concluded that the licensee failed to
32
2.7
perform an adequate
root cause
analysis
and therefore did not correct the
cause
of the misapplication
and use of incorrect fuses.
Maintenance
and
Su
ort Personnel
Control
The inspectors
reviewed the licensee's
staffing control
and staffing needs.
Inspection activities included interviews with plant personnel,
training facility
observations,
in plant observations,
and review of documentation.
The licensee's
maintenance
department
had recently
been reorganized
to integrate
the
I&C department with the previous
complement of mechanical
and electrical
personnel
that formed the'lant maintenance
department.
Under the
new organiza-
tion,
I&C and electrical
departments
were combined to form an Instrumentation
and Electrical
( I&E) department,
which consisted of ILC technicians
and
15
electricians,
with 2 supervisors.
Electrical maintenance,
such
as relays
and
switchgear,
was performed
by I&C technicians
rather
than electricians,
as
was
the case prior to the reorganization.
One supervisor
and six electricans
were
scheduled
exclusively to MOVATS testing,
leaving
one supervisor
and remaining
electricans
to perform electrical
maintenance
tasks.
According to the licensee,
the electrical
maintenance
scope will expand to include preventive
and predictive
maintenance
on additional safety related
and
80P componets.
However, the
capability of the electrical
maintenance
staff to implement
such
an expansion
had not been evaluated
by the licensee.
Although maintenance
staffing appeared
adequate
at the time of the inspection, it was not clear that sufficient
resources
would be available in the future.
2.7. 1
Trainin
and
uglification
The inspectors
reviewed maintenance
training programs
in the welding, electrical,
mechanical
and instrumentation
and controls areas.
Detailed lesson
plans
on
several
topics
as well as the training records for maintenance
personnel,
including
a supervisor,
were also reviewed.
The records
adequately
reflected
sufficient training for the tasks that were observed.
Training for planners
and schedulers
was not provided.
Due to the large
number of fluid system leaks, training conducted
in the areas
of torque requirements
and flange
makeup were reviewed.
The lesson
plans
contained sufficient depth
and detail in these
areas.
The mechanical
maintenance
continuing training program also contains specific information about check valve
problems which includes
The training program provided
an integral part of the qualification system
used
for maintenance
personnel.
Formal training requirements
as well as on-the-job
training evolutions were documented
in an individual's qualifica ion matrix.
In discussions
with a maintenance
supervisor,
the inspector determined that the
qualification matrix was
used to assign
individuals to specific tasks,
but no
requirement
existed to ensure that qualified personnel
were used for all tasks.
In this area, all the necessary
elements
appeared
to be in place
such that
a
plant administrative
procedure
which provided guidance
and direction
on training,
qualification and the assignment
of qualified personnel
to maintenance
tasks
would provide
an effective system.
The established
training program for
maintenance
personnel
was considered
a strength.
33
2.8
2.8.1
MOVATS Testin
Pro
ram
Inspection
Report
No. 50-315/316/89-028
documented
the results of the NRC's
inspection
of the
licensee
'
MOVATS testing results to ensure operability
of critical safety related motor-operated
valves
(MOVs).
The scope of the
testing
was limited to 35 critical safety related valves in each un'rid
some additional
problem safety related
and
non safety related valves.
Testing
was performed
on Unit
1 during the Unit
1
1987 outage,
on Unit 2
during the Unit 2 1988 outage
and
some testing
was performed
on certain
valves in 1989 in accordance
with the procedures
which incorporate
the test
criteria of Bulletin 85-03 .
While the testing
per formed sati si fed the
criteria of Bulletin 85-03, the testing
was limited to a small
sample of
i3Vs.
Of approximately
500
MOVs in each unit, 250 are safety related.
Of
1000
MOVs in both units, the licensee
estimated that approximately
100 have
been tested
using the criteria of Bulletin 85-03.
Prior to 1987, there
was
no test program for MOVs.
MOVs were repaired
on
an
as
needed
basis.
PM No.
12
MHP 5030.012.001,
"Preventive Maintenance
Requirements,"
and the preleminary draft "Motor Operated
Valve Program"
dated June
1988, required that 33<< (42 valves of which 50~ must be
environmentally qualified equipment) of safety related
MOVs have
performed every refueling outage
including inspection
and cleaning of
electrical
components,
checking lubricants,
and the torque switch smooth
operation,
cleaning
and lubricating valve stems,
lubricating upper bearings
and repacking
the valve stuffing box, if required,
and setting torque
switches
and limit switches.
This program
was still in the rough draft
stage
and
had not been formally implemented.
According to the licensee,
evaluation is ongoing of long term
MOV testing
programs at other utilities as well as evaluation of the results of
preleminary testing
performed in accordance
with the criteria of Bulletin 85-03.
Additionally, the licensee
indicated that the formalized long term
program will incorporate
the testing criteria of NRC Generic Letter No.
89-10 and
be expanded
to include all safety related
MOVs.
2.8.2
SOER 86-03 Check Valve Failures
The inspectors
evaluated actions
taken in response
to
SOER 86-03 regarding
check valves failures.
A program was established
on August 30,
1988, to
implement the recommendations
of the
SOER.
There are
440 total check
valves:
10 per unit are
examined
under the
IST program and
an additional
23 are
examined for each refueling outage.
Procedure,
12
THP 5070 ISI.003,
"Disassembly
and Visual Examination of Check Valves per
SOER 86-03 Require-
ments",
Revision
0,
was issued at the time of the inspection.
During the
Unit 1 outage
in 1989,
29 valves were examined for the
Most
of the check valves were found to be in good condition;
however, four
exhibited minor pitting; one indicated erosion/corrosion;
and one with a
centerline split disc
had
a loose spring,
an eroded
stem hinge,
and
a
damaged
rubber seat insert.
All the valves were repaired to operable
condition.
2.9
Review of Licensee's
Assessment
of Maintenance
34
2.9.1
Audits and Surveillance
The inspection
team reviewed
samples of maintenance
related
gA survei llances
and audits.
gA findings were
made
known to managment.
While the technical
content
appeared
to be appropriate,
the
scope of the audits did not address
significant aspects
as follows:
None of the survei llances
under
PMI 5020 "Maintenance Policy" appeared
to
address
various electrical
maintenance
program content
and implementation
deficiencies that were identified by the inspection
team.
Surveillance
Report No.
12-89-134 failed to address
appropriate criteria
for 4KV circuit breaker relay calibration, in that the circuit breaker/fuse
coordination setpoints
as specified in the licensee's
coordination
study
were not verified.
None of the surveillances
under
PMI 6010 "Radiation Protection
and
Monitoring'-'ppeared
to address
approximate
395 piping leaks in the Auxiliary Building
in accordance
with Regulatory
Guides
1.21
and 4.1.
Reg Guides
1.21
and 4.1
require the gA program include measures
to survey possible radiological
exposures.
gA audits of the
PM program were performed in 1987
and
1988 but non'e
was
scheduled
or performed in 1989.
The inspectors
determined that lead
gA auditor qualifications were established
in accordance
with ANSI 45-2. 12 and specified in the licensee's
gualification
and Certification Procedure
No. 2. 1 for quality assurance
personnel.
2'.2
Review of Maintenance Self Assessment
2.9.2.1
Maintenance
Self Assessment
The inspectors
reviewed the report of the licensee's
self assessment
of
maintenance
performed
by corporate
and site personnel
in February
1988,
when
71
findings and recommendations
were identified.
Based
on reviews
and comparisons
with other industry self assessments
of maintenance
and the results of this
inspection
the inspectors
concluded that the licensee's
self assessment
was
performance
based
and effective in identifying maintenance
problems
and
concerns.
However,
gA did not utilize the .report. results to develop checklists
as part of audit plans for verification of corrective action.
At different
times subsequent
to the assessment
in February
1988,
36 of the
71 findings and
recommendations
had
been investigated
and closed;
however,
in December
1989,
19
of the 36 were reopened
because
of inadequate
corrective action.
Many of the
items have
remained
open for two years,
which indicated
poor management effort
to address
the concerns.
Furthermore,
target dates
have not yet been set to
correct the assessment
findings, which was considered
a significant weakness.
During this inspection
a large
number of previously identified weaknesses
were
still evident,
which indicated that corrective actions to address
most of the
deficiencies
was untimely and noncomprehensive.
For example:
(1) scope of the
PM program was minimal and not well defined,
formalized or integrated;
(2)
recurring maintenance
problems
were not trended
and analyzed;
(3) maintenance
history data
were incomplete
and erroneous;
(4) rework was not tracked or
35
analyzed for root cause;
(5) responsibility and authority of each maintenance
group was not delineated;
and (6) various computerized
forms of maintenance
data
lacked coordination.
In July 1987,
the licensee
established
the concept of "Quality Teams"
(QTs), to
give maintenance
workers
and other personnel
an opportunity to identify and
solve maintenance
work related
problems.
As stated
in the
QT Implementation
Plan,
a "vital support function" needed for the success
of the
QT program was
communication
between
the
QTs and management
"to ensure that team generated
solutions
are aggressively
addressed"
.
The inspectors
obtained
a lengthy list
of jobs performed in 1988 and
1989 by maintenance
workers that outlines problems
encounx,crea
and suggested
solutions.
Some
foremen associated
with ihe jobs were
interviewed to get
an assessment
of QT effectiveness.
Many foremen indicated
there
was
a profound lack of management
feedback to
QT suggestions
and
recommended
improvement
based
on field experience.
Most suggestions
received
no response.
One example
requested
an investigation into using qualified flexible conduit for
electrical
connection to the containment
pumps,
which are
removed every
outage
and require
numerous determinations.
The suggestion
affected
wear
on the
cable
ends,
time and consequently
man-rem exposure.
2.9.3
Effectiveness
of Corrective Action
The inspectors
evaluated
the effectiveness
of licensee's
corrective action to
correct deficiencies
noted during
a maintenane
assessment
conducted at Donald C.
Cook by an outside organization
in April 1988.
The inspectors
determined that
many of the corrective actions
taken
have
been
inadequate
in identifying the
cause
and resolving the problem.
For example,
the plant continues
to have
a
problem with a significant number of system leaks.
In addition,
36 of the
71
findings and recommendations
resulting from the February
1988 maintenance
self
assessment
had to be reopened
in December
1989 due to inadequate
corrective
action.
Contributing to this weakness
in corrective action is the lack of a
formal program to direct or implement root cause analysis,
which is addressed
in Procedure
PMI-7030, "Condition Reports
and Plant Reporting."
Problem reports
require
an investigation
and determination of root cause,
but in cases
where
a
problem report is not initiated,
a root cause
analysis will probably not
be done.
As
a positive note,
formal training sessions
were conducted
on root cause
analysis
by
a contractor
and were presented
to 44 plant personnel
in September
1988.
The fact that many of these
problems
remained
uncorrected
at the time of this
inspection reflects
a significant weakness
in the corrective action
system.
While numerous
plans
and proposals exist that address
the eventual
solution to
many of these
concerns,
the long-standing
nature of most of these
problems is
cause for concern.
Failure to take prompt and adequate
corrective action to
identified deficiencies is considered
a violation of 10 CFR 50, Appendix B,
Criterion XVI (50-315/89031-04B;
50-316/89031-04B)
.
3:0
Syyno sis
This synopsis highlights the inspection findings in terms that are meant to be
representative
of the presentation
tree that is attached
to this report.
A (+)
means that the area is good or has potential to be so;
a (-) means that the
area is weak or not fully developed.
Unmarked areas
are factual but were not
a (+) or (-).
36
3.1
Overall Plant Performance
3.1.1
Historic Data
(+)
The forced outage rate
was less
than half the established
goal; there
were
zero safety
system actuations,
the plant manager recently established
a system
to measure
and
manage
maintenance
effectiveness.
(-)
Operating records
since January
1989, indicated that the
number of
unplanned
reactor trips was exceeded
on both units; three of the six reactor
trips appeared
to be maintenance
related;
the
number of LERs was more than
twice the established
goal;
24 of the
54
LERs were attributed to maintenance/
surveillance
problems; unit availability was not met for either unit.
(Unit
1 = 69.3//70/o; Unit 2 = 74.4/>/80%)
3.1.2
Plant Walkdowns
(+)
Equipment
was well identified with color coding around the identification
number
.
(-)
Material condition was poor for a plant in operation:
there were
a
significant number of steam,
water, or oil leaks
from the
AFW and
DG systems,
and
numerous
safety valves;
there
were over 400 catch basins to control leaks
some of which were contaminated;
tagging of deficiencies
was not specifically
required therefore tagging
was inconsistent;
many deficiencies
were not tagged
and
some tagged
items lacked job orders therefore
may never
be repaired;
as-built drawing discrepancies
wer e noted
by the
team and the licensee.
3.2
Mana ement
Su
ort of Maintenance
3.2. 1
Mana ement
Commitment
and Involvement
(+)
The
1988 self assessment
was performance
based
and effective in identifying
maintenance
problems
and concerns.
(-)
Root causes
were not assessed
and corrective action
was not taken to preclude
and correct
several
programmatic
problems identified in 1988 during
a self
assessment
of maintenance
and recurring
problems with 4kV electrical circuit
breakers;
a significantly high number of safety -valve failures, four times the
industry average,
was reported to the corporate
nuclear engineering
department
but
a detailed
study was not conducted to investigate
an obvious negative trend
and determine
the root cause;
there
was
no feedback
from management
to guality
Team suggestions.
3.2.2
Mana ement
Or anization
and Administration
(+)
A RCM pilot program was recently initiated that eventually will be integrated
with the recently initiated
PRA, and ultimately integrated with existing
practices;
system engineers
are utilized to support the project.
(-)
A corporate
manager exists for the plant maintenance
division of fossil plants
but none was established
for the Donald
C.
Cook Nuclear Plant; only limited goals
were established
for maintenance
in 1989
and
none for 1990; maintenance
policies
did not exist for mechanical
and electrical
groups;
the
I&C and electrical-
37
mechanical
maintenance
groups were compartmentalized
instead of being integrated;
the job order prioritization system
was not uniform for all maitnenance
groups.
(-)
The recent reorganization left maintenance
personnel
confused
about authority,
responsibilities,
accountability
and interfacing because
these acti vities were
not formalized nor clearly defined for the various plant groups involved in
maintenance.
(-)
Maintenance
was primarily based
on Technical Specification requirements
and
vendor recommendations;
systematic
evaluation of vendor recommendations
and
incorporation into the
PM process
was weak; only 893 of 6800 vendor manuals
had
been
reviewed.
3.2.3
Technical
Su
ort
(+)
Whole body radiation dose
was considerably
below the industry average
but
station
goals
were not met; radiation protection job coverage
and
ALARA support
for major maintenance activitie were considered
strengths.
(+)
A unique
system,
"dc scout,"
was effectively used to identify the location
of grounds
on dc battery
systems.
(-)
Poor communication existed
between plant and corporate technical
support
staffs;
corporate usually determined corrective actions with minimum plant
engineering
input.
The system engineer
concept
was not fully developed;
implementing procedures
were not established;
vendor manuals
were not reviewed for QC inspection or
requirements;
completed
work requests
were not reviewed for trending or failure
analysis.
(-)
Technical
support
was weak
on corrective action for recurring problems;
engineering
support in the areas
of root cause,
failure analysis,
and post
maintenance
testing
was also weak; engineering
was not involved in resolution
of discrepancies
noted between
sizes
and set points of thermal
overload
installations; efforts were minimal in the areas
of predictive maintenance;
handling of generic industry information from outside
sources
was weak in the
electrical
area
and mixed in the mechanical
area.
Response
MOV common
mode failures
was
slow and only met minimum requirements;
only
100 of approximately
1000
MOVs were tested
using criteria from Bulletin 85-03.
(-)
QC "peer inspection"
was considered
ineffective, vague,
and lacking in
guidance or acceptance
criteria.
(At Donald
C.
Cook a "peer inspection"
program
has
been
developed to supplant conventional
QC inspection.)
3.3
Im lementation of Maintenance
3.3. 1
Work Control
(-)
Work histories in the form of documented
work activities
on job orders
was
weak: descriptions of work scope
were typically repair
as necessary,
or repair
and recalibrate;
post maintenance
testing
was neither descriptive
nor specific;
causes
of failure were not included; planning
and determination of trends
and
root causes
was severely
hampered.
Recent job orders indicated considerable
improvement.
38
(-)
Planning
and scheduling
were weak: work planners
and schedulers
lacked job
descriptions
and did not receive specific training in those
processes;
an
inta.'
.;
"'"==.". ';
planning,
scheduling,
and coordination did not exist for
scheduling
and coordination of CM,
PM,
and surveillance
activities which
contributed to increased
equipment
downtime.
Retrieval of computerized
data
used
for planning
was slow and the data were not comprehensive
and
sometimes
erroneous'-)
Planning,
communication,
and advanced
notice of HP was weak for emergency
and unplanned
outage
work.
= Mork was not well coordinated
or planned:
required
tools
and equipment,. were not specified,
and
a high number of workers were
assigned
to radiation producing jobs; frequently work schedules
were not followed
and required radiation resurveys.
All of these
shortcomings
have the potential
to cause
unnecessary
increased
radiation exposure.
(-)
The backlog of non-outage
CM job orders at 1772 was excessive
and more than
twice that planned.
A goal
had not been established
for maintaining
a ratio
between
PM and
CM; the total backlog for 1989 ranged
between
900 and
1200 with
CM at 88K and
PM at 12K.
(-)
Maintenance
procedures
did not include vendor
recommended
maintenance;
procedures
were technically weak and did not adequately
consider
human factors;
for the most part
gC inspection
hold points did not exist.
(-)
In several
instances,
activities were not accomplished
in accordance
with
procedures,
instructions,
or drawings.
As a result the following kinds of
problems
were identified:
equipment
was in indeterminate
status;
thermal
overload heaters
were incorrectly sized or adjusted; field verifications were
done with outdated drawings;
AFW pump vendor requirements
were not included in
maintenance
procedures;
relay contacts
were incorrectly cleaned;
a potential
reactor trip was created
by operations
personnel
not having
a required
procedures;
maintenance
procedures
were not periodically reviewed to assure
that
PM aspects
of components
were updated
based
on results of current
operating conditions.
3.3.2
Plant Maintenance
Or anization
(-)
Mechanical
maintenance
was poor in several
instances
as evidenced
by MSIV
failure to meet acceptance
criteria for closure time; misapplication of bolt
thread sealant;
procedures
lacked safety precautions
and acceptance
criteria
for torque values of cover bolts for a check valve and
AFW pump packing leakoff;
amounts of lubrication used were not documented for various pieces of equipment;
54 filters were missing from an air dryer but
a deviation report was not
prepared;
and the scope of MOV testing
was narrow.
(-)
Electrical maintenance
was poor in several
instances
as evidenced
by:
narrow scope of PM, G.
E.
HFA relays
wer e notably missing from the program;
information regarding industry initiatives was not always
communicated
to
appropriate
levels of the electrical
maintenanace
staff, for example,
informa-
tion about
HFA auxiliary relays;
fuses
were inadequately controlled;
equipment
accuracy
and technique
were inadequate
for the testing of the
under voltage
relays that actuate
the emergency diesel
generator.
(-)
I&C maintenance
was poor in some instances
as evidenced
by:
poor work
techniques
on
BOP equipment,
hand agitation of instruments,
tools beyond
39
calibration
due date,
and improper method
used to calculate
response
time;
evaluations
were not made of instruments with multiple failures.
(-)
Trending of vibration monitoring results
was not performed
on individual
equipment
and procedures
had not been
developed for implementation of thermo-
graphy techniques;
effects of component
aging were not formally analyzed; it
was noted that the cause
code
"normal wear/aging"
was often listed
on job orders
but it was by default and
no apparent
analysis
was done.
3.3.3
Maintenance Facilities
E ui ment and Material Control
(+)
Control of MME was satisfactory,
defective tool were segregated
from those
in calibration.
(-)
Spare parts were
sometimes
unavailable
because
some design
packages
did not
always
make
such
a consideration;
procurement,
parts control
and substitution,
and engineering
involvement in these
processes
was weak;
AFW pump parts
had to
be reused,
and parts for repair of valves were substituted
by maintenance
person-
nel without engineering
review; traceability was not maintained for materials
and
components
used in safety-related
motor control centers.
3.3.4
Personnel
Control
(+)
The established
training program for maintenance
personnel
as considered
a strength;
formal training sessions
were conducted
on root cause analysis
by
a contractor
and were presented
to 44 plant personnel
in September
1988.
(-)
Resources
did not appear sufficient to address
weaknesses
in the technical
support
area that required engineering
expertise,
reduction of the large
number
of parts
on back order,
and establishment
and implementation of an effective
program.
The inspectors
met with licensee
representatives
(denoted
in Paragraph
1) on
January
18,
1990, at the Donald
C.
Cook Power Plant
and summarized
the purpose,
scope,
and findings of the inspection.
The inspectors
discussed
the likely
informational content of the inspection report with regard to documents
or
processes
reviewed
by the inspectors
during the, inspection.
The licensee did
not identify any such documents
or processes
as proprietary.
40
AEPSC
CR
GRID
FDBS
FLA
GE SIL
IKC
IEB
IEN
ISI/IST
JO
K
KV
LER
MB(TE
NRC
PR
TS
V
'PPENDIX A
Alternating Current
American Electrical
Power Service
Company
Aux'.liary Feedwater
System
As
Low As Reasonably
Achievable
Balance of Plant
Corrective Maintenance
Condition Report
Control
Room Instrument Distribution
Director Current
Emergency
Core Cooling System
Electrical
Power Research Institute
Engineered
Safety
Feature
Facility Data
Base
Full Load Amps
Final Safety Analysis Report
General Electric Service Information Letter
Health Physics
Heating, Ventilation and Air Conditioning
Instrument
and Control
IE Bulletin
IE Notice
Institute for Nuclear
Power Operations
Inservice Inspection/Inservice
Testing
Job Order
Kilo
Kilo Volt
Licensee
Event Reports
Motor Control Center
Motor Operated
Valve
Measuring
and Test Equipment
Nuclear
Power Reliability Data System
Nuclear Regulatory
Commission
Nuclear Utility Management
and
Human Resource
Committee
Out of Service
Plant Assessment
Group
Preventive
Maintenance
Post Maintenance
Testing
Problem Report
Quality Assurance
Quality Control
Root Cause Analysis
Reliability Centered
Maintenance
Request for Change
Radiation
Work Permit
Systematic
Assessment
of Licensee
Performance
Significant Operating
Experience
Report
Safety
System Functional
Inspection
Technical Specification
Volt
I
~ ~
wT laX5