ML16341F655
| ML16341F655 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 03/28/1989 |
| From: | Huey F, Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F654 | List: |
| References | |
| 50-275-90-01, 50-275-90-1, 50-323-90-01, 50-323-90-1, NUDOCS 9004200461 | |
| Download: ML16341F655 (80) | |
See also: IR 05000275/1990001
Text
'
U. S.
NUCL'EAR REGULATORY CONSaISSION
REGION
V
Report Nos.:
30-275/90-01,
50-.323/90-01
Docket Nos.:
License Nos.:
Licensee:
.
Facility Name:
Inspection at:
50-272,
.50-323-
DPR-BO, 3PR-82
'
Pacific
Gas
and Electric
Company
'77 Beale Street,
Room 1451
San Francisco,
94106
Diablo Canyon Units
1 and
2
Diablo Canyon Site,
San Luis Obispo, California
PG8E Corporate Offices,
San Francisco,
Inspection
Conducted:
January
S - 12 and January
22 - February 2,
1990
Inspectors:
Z zg(qc
nson,
rogect
ection
se
ate
cygne
am Leader
P.
N. gualls,
Resident
Inspector
Assistant
Team Leader
J.
F. Burdoin, Reactor Inspector
R.
G. Gilbert, Program Assistant
R. L. Prevatte,
Senior Resident
Inspector
J.
F. Ringwald, Resident
Inspector
R. S. Hodor, Systems
Engineering Consultant
K. Sullivan, Electrical Engineering Consultant
Approved by:
~F
.
Hu
,
ref,
nglneer)ng
Sect>on
~Summar:
ate
sgne
Ins ection
on Januar
1 - 12 and Januar
22 - Februar
2
1990
Re ort Nos.
50-275/90-0
an
50-323/90-01
~Al
1:
A
p i1,
1
i
p
effectiveness
of the licensee's
corrective actions
program.
The system engi-
neerina
program, safety oversight groups, corporate
engineer ing activities,
emergency lighting, and plant housekeeping
conditions were also inspected.
Portions of inspection
procedures
30703,
35702,
40500,
40702, 40703,
40704,
62705,
64704,
71707,
92701
92709,
and
92720 were utilized during this
inspection.
0
n 04bi
~
" a7>
9004~
gCK 0>
DR
6
-2-
Results:
General
Conclusions- and
S ecific"Findin s:
1.
- Inadequate
control-was provided for .temporary
changes to surveil-
lance procedures.
Other weaknesses
were also observed
in the
.preparation
and implementation of surveillance
procedures.
(Paragraph
3.c(6));
2.
3.
5.
6.
7.
8.
The corrective actions
program
w'as effective in initiating
corrective actions- and in accomplishing timely corrective actions
for safety-significant
issues.
However, several
issues
of lesser
individual significance
had been
open for several
months to'
few
years.
(Paragraphs
3.b and 3.c)
While the initiation of corrective actions
was effective
(and
actively encouraged
by management),
no person or group within the
licensee's
organization
was responsible for driving the clos'ure or
resolution of action items.
Trending reports
prepared
by the
licensee
showed that the
number of open action requests
was contin-
uing to increase.
(Paragraph
3.e)
Weaknesses
were noted in some aspects
of the System Engineer
and
Design
System Engineer
programs.
(Paragraph
5)
The backlog of Nuclear Engineering
and Construction Services
(NECS)
engineering
work was sizeable'nd
was growing slowly, although it
appeared
to be managed effectively.
(Paragraph
6)
Plant housekeeping
was found to be in need of improvement.
(Paragraph
7)
Emer gency lighting systems
were found to be adequate for safe shut-
down in the event of a station blackout.
(Paragraph
8)
While applicable
requirements
were being met, the General Office
Nuclear Plant Review and Advisory Committee
(GONPRAC) was providing
minimal ongoing guidance
and oversight regarding the conduct of
audits
performed
under its cognizance.
(Paragraph
3.d)
Significant Safet
Natters:
None.
Summar
of Violations:
Three violations were identified:
(I) failure to take effective correc-
tive action (paragraph 3.c(4)), (2) failure to obtain approval of tempo-
rary changes. to approved surveillance
procedures
(paragraph 3.c(6)),
and
(3) improper housekeeping
practices
(paragraph
7).
0
'
DETAILS
1.
Persons
Contacted
Principal Staff:
- J. D.
- J. D.
- W. H.
- J. A.
- R. C.
- J. B.
Yi. J.
- D
B.
W.
Shiffer
Townsend
Wallace
Sexton
Anderson
Hoch
Angus
Miklush
Giffin
Senior Vice 'President,
Nuclear
Power Generation
Yice 'President,
Diablo Canyon Operations
,-Yice:President,
Engineering
Manager, guality Assurance
Manager,
Nuclear Engineering
and Construction
Services
Manager,
Nuclear Safety
and Regulatory Affairs
Assistant
Plant Manager,
Technical
Services
Assistant Plant Manager,
Oper'ations
Services
.Assistant
Plant Manager,
Yiaintenance
Additional staff members
contacted
during the inspection
are listed in
Attachment A.
- Attended exit meeting at
on February 2, 1990.
2.
Ins ection
Ob 'ectives
The overall objective of this inspection
was to assess
the effectiveness
of the licensee's
corrective actions
program.
This included
an assess-
ment of the following principal elements
of the program:
Effective definition of the program.
Proper initiation of appropriate corrective actions.
Effective and timely completion of corrective actions.
The effectiveness
of each of the principal quality oversight groups
involved in the corrective actions
program.
As part of'his assessment,
team members
were assiqned
to review and
walk down various plant systems.
Specific issues
related to these
systems
were identified for use in assessing
the effectiveness
of the
corrective actions
program.
The inspection
team also sought to assess
the effectiveness
of the
licensee's
System Engineer
(SE)
and Design System Engineer
(DSE)
programs (initiated, in part,
as corrective action for previously
identified weakness
in plant/corporate
interface).
Although outside the intended
scope of the team inspection,
one team
member also conducted
an inspection of emergency lighting systems.
'
3.
Corrective Actions Pro ram
The licensee's training staff provided the team a'brief introduction to
the computer-based
corrective action program.
The"team also reviewed
relevant directives,
interviewed members of the licensee's staff,
examined selected facility records,
and conducted
system
walkdowns in
order to assess
<he functioning of the corrective action program.
The
findings from .this effort are discussed
below.
a4
Pro ram Definition
The corrective action program at Diablo Canyon
Power Plant
(DCPP)
is defined .in Nuclear Plant Administrative Procedure
(NPAP) C-12,
Identification and Resolution of Problems
and Non-Conformances,
Revision
19.
The program is managed
through the Plant Information
Management
System
(PIMS),
a computer database
system.
This system
requires that the identifier of a problem (regardless
of the
quality classification)
or a nonconformance,
or suspicion that
a
nonconformance exists, initiate an Action Request
(AR) and report
the problem to his immediate supervisor.
The
AR is entered
into
the
PIMS system.
If access
to the
PIMS is not available,
the
individual should report the problem to his immediate supervisor
who will insure that an
AR is issued to address
the identified
problem.
Each
AR entered into the
PIMS system is sequentially
assigned
a
unique
number (this is done automatically
by the computer program)
as it is created.
Once entered,
the
AR is
a permanent plant record
and cannot
be deleted.
This system gives
a complete record of the
actions
taken, status,
and resolution for every problem entered
into the system.
Plant workers at the technician level are
required to have their supervisor enter
ARs into the system for the
problems they identified.
Employees
above the technician level
enter
ARs into the system themselves,
with supervisory review of
the
AR after it is entered.
Each
AR, once initiated, is classified
as either
a corrective main-
tenance
(CM) or administrative task
(AT) prior to implementation of
corrective action.
Once entered into the system,
each
AR is
reviewed for guality Assurance
(gA) program applicability and plant
operations
impact,
and is assigned
a priority based
on these
factor s. If a safety-related
system is involved, the
AR is
reviewed to determine if a nonconformance
report
(NCR) is required,
or whether
a quality evaluation
(gE) must be performed.
If the
problem requires evaluation for nonconformance,
significant event
investigation, root cause determination, reportability, or
justification for continued operation,
the
AR may require
additional
processing
using the steps
provided in the Decision Tree
for Problem Resolution,
Appendix 7.6 of NPAP C-12.
If an
NCR is
required,
then
a plant Technical
Review Group
(TRG) evaluates
the
NCR to determine
the root cause
and corrective actions.
The program appeared
to the inspectors to be
a broad-based
problem
reporting system,
and the actions required
by various personnel
involved with identifying and resolving problems
were adequately
delineated in procedure
NPAP C-12.
The
AR reporting program
began
onsite at DCPP in tune
1985
and
was
implemented in the
San Francisco offices in October
1988.
At the inception:of the
AP program, training was conducted for all
plant employees.
Training also
has
been provided periodically for
new employees.
Although no periodic refresher
training was
provided, plant personnel
interviewed appeared
knowledgeable
about;
='he
use of the
AR system.
One difficulty noted with the system
was
the difficulty in readily determining
component identification
( ID)
numbers,
in that an on-screen
index
was not provided by the
PIt15
program.
This problem appeared
to the inspectors
to at times
restrict the
use of the
PINS program.
This appeared
to be of
lesser
ID can
be added during review
by the Work Planning group.
However, since
AT type
ARs are not
normally routed to Work Planning,
determination of the
ID for these
ARs must
be done
by the originator or his/her supervisor.
b.
Initiation of Corrective Action
The team conducted
numerous
interviews,
reviewed
a wide selection
of plant records,
and walked
down several
plant systems
to identify
issues
requiring corrective actions.
It is considered
noteworthy
that this effort did not result in the identification of any items
deserving corrective action for which an action request
(AR) had
not been initiated.
Persons
contacted
and records
reviewed during the inspection
are
identified in Attachments
A and
C, respectively, to this inspection
report.
Inspection effort involved with system reviews
and walk-
downs is discussed
in paragraph
4 of this report.
Additional
reviews to determine
whether
appropriate
actions
had been identi-
fied were conducted
as follows:
(1)
Engineering Support
Discussions
and interviews were conducted with various
corporate
and plant staff members.
Corporate interviews
included the President's
Nuclear Advisory Committee
(PNAC)
Executive Secretary;
the Chairman
and Secretary of the General
Office Nuclear Plant Review and Audit Committee
(GONPRAC); the
Director of guality Assurance
(gA); one
gA engineer;
one
gA.
consultant;
one
gA supervisor;
and one
gA senior engineer.
In
the Operating
Experience
Assessment
area,
the group supervisor
and two engineers
were interviewed.
In the Engineering area,
two supervisors,
four group leaders
and approximately ten
other en'gineers
were interviewed.
Interviews were also
conducted with the cognizant
system engineers
and
some of the
design
system engineers
for the various
systems
reviewed,
as
discussed
in paragraph
4 of this report.
The results of these
(2)
interviews revealed .that, overall, personnel
were knowledge-
able of their jobs
and in the initiation of corrective action
requests.
'Plant Operations
Interviews conducted in this area
included the Assistant Plant
Manager for Operations
and Maintenance;
the Managers of
Operations,
Maintenance,
and Engineering;
two supervisory
and
two non-supervisory
engineers;
a shift supervisor;
a shift-
foreman;
two auxiliary operators;
an electrical,
an instrument
and controls
( IKC) and
a mechanical
maintenance
foreman;
a
machinist;
an electrician;
and an
ISC technician.
Each of
these
persons
appeared
to be knowledgeable
on the corrective
action program and their part in insuring its success.
All of
the above, with the exception of the electrician
and
machinist,
expressed
confidence
in their ability to input ARs
into the computer
and to use
PIMS.
These
two persons
stated
that deficiencies
or problems
are reported to their respective
foremen,
who input the problems into PIMS.
An auxiliary operator
expressed
a concern
about remaining
current with computer software
changes
as they occur.
An
inquiry into this matter revealed that
a telephone
HELP line
is available during normal working hours,
and
a refresher
course is offered by computer engineering
when sufficient
persons
to establish
a class
have requested
this training.
It
was stated that this training program was recently initiated
and
one class
was conducted
in January
1990.
The inspectors
attended shift crew briefings four times,
maintenance
supervisory morning meetings
three times,
and the
shift supervisor's
8:30 a.m.
work planning meeting
on four
different occasions.
On each occasion all of the meetings
were attended
on the
same
day to determine if the plant
problems
were communicated
through each of these
groups.
The
meetings
appeared
to be timely with significant events or
problems
being well covered.
On two 'occasions,
AR's discussed
in these
meetings
were verified to be on PINS.
The inspector
accompanied
an auxiliary operator
on his
required shift rounds
and observed
his performance of equip-
ment checks.
During these
rounds
a deficiency was identified
involving a leaking air regulator
and
a sticking gauge
needle
on the air supply to the spent fuel pool transfer
canal
gate.
The inspector verified that this item was documented
on
A0176728, initiated by the operator.
During the above rounds,
the inspector observed
AR tag Nos.
A0174079, A0174082,
A0079363
and A0176432 hanging
on various
equipment in the auxiliary building.
The operator
was able to
enter
PIMS and verify the current status of these
items.
Discussions
with this operator revealed that he was capable of
documenting deficiencies
in his area.
0
(3)
During the above
rounds it was also noted that lighting in
some of the auxiliary building areas
was marginally adequate
and not conducive to the identification of equipment
and space
problems.
Other
problems
noted
on these
rounds, such'as
oil'tanding
under equipment
and water
on 'the floor, were dis-
cussed with the operator.
His explanation, that this problem
would be reported if it persisted after initial cleanup,
was
considered
reasonable.
I
The inspector
observed
control
room activities and held
discussions
with shift personnel
on three separate
occasions.
The discussion
centered
around their part in the review of ARs
reported
by operators
under their supervision,
and their
identification and reporting of self-identified problems.
These
personnel
were very knowledgeable
on the computer,
the
AR system
and existing problems.
Plant Maintenance
The inspector monitored selected
portions of the mechanical
maintenance activities associated
with a failure of the Unit 1
positive displacement
charging
pump which occurred during'he
inspection.
This item was identified by operations
and
documented
on
on January
23,
1990 at 7:00 a.m.
At
9:00 a.m., mechanical
maintenance
conducted
a test
run and
isolated
the source of the problem to a crack in the
pump
suction casing.
The system engineer,
maintenance
engineer
and
work planner
were actively involved in determining the scope
and depth of repairs
needed.
The knowledge
and coordination
efforts of the mechanical
maintenance
engineer
and the
assigned
machinist were timely and impressive.
The repairs to
this
pump were tracked for the duration of the inspection.
Selected
portions of the compressed air system were walked
down with the system engineers
on three different occasions
during the inspection
(review of the compressed air system is
discussed
further in paragraph 4.f).
Extensive discussions
were conducted
focusing
on past system
and component
problems,
in-process
work and corrective maintenance,
and other work
activities
on this system.
The general office design engineer
participated in one of these meetings.
These
persons
were
very aware of past
system
problems
and activities in process
or planned.
No significant deficiencies
were identified
during these
walkdowns that had not been previously documented
in the corrective action system.
Timeliness
and Effectiveness
of Corrective Actions
The various interviews, walkdowns,
and record reviews discussed
in
paragraph
3.b resulted in review by the inspectors of many active
and completed action requests
(ARs).
These
reviews indicated that
the priority system
used for classifying
ARs was effective, in that
problems
which had safety significanc'e or another
reason for-
expeditious
resolution
had
been
addressed
in
a timely manner.
However, these
reviews also identified,several
items of lesser
individual significance which had
been
open for,extended
periods,
and which 'indicated that additional attention
needed to be given to
the closure of ARs.
These long-standing
active
ARs are discussed
below.
(1)
Pump
(AFW) Governor Cooling Water Flow
During walkdown of the Unit 1
AFW .system,
the inspecto~'oted
a tag for AR No. A0085279 attached
to flow indicator FI-12 in
the cooling water line to the turbine-driven
AFW pump gover-
nor.
This tag stated
"no flow indicated."
Review of the
indicated that it was
an administrative
task
(AT) type AR-
which had
been initiated in November,
1987.
The history of
the concern traced
back through several
ARs and work orders
(for Units
1 and 2) to AR No. A0000974, initiated in July
1985.
The licensee
determined early in the process
that the
indication of no flow to the governor oil heat exchanger
did
not affect operability of the
AFW pump.
Various steps of the
review had also determined that (1) there
was
no physical
blockage of the cooling water lines
and (2) the flapper in the
Unit
1 FI-12 was about twice as thick as in Unit 2.
(2)
Resolution of the no-flow indication focused for some time on
impr'oper operation of FI-12, and Engineering
recommended
in
October
1989 that it be replaced with a
new indicator of the
same type.
This recommendation
was not accepted
by the system
engineer,
and the
AR was reassigned
for furthe'r evaluation.
In November
1989, after testing
showed that FI-12 did indicate
flow introduced
from a test source
(hose connection), it was
concluded that the problem was actually one of flow balancing
(i.e., two bearing
heat exchangers
in parallel with the gover-
nor oil heat exchanger
were carrying almost all of the flow,
and flow through FI-12 was actuall
low).
At the time of the
inspection, further testing
was
p armed to try balancing the
flow so that FI-12 would indicate flow through the governor
oil heat exchanger.
The total time to resolve the concern
.. with FI-12 (in both units) appeared
to be excessive,
with more
than four years elapsing before it was concluded that the
indication was valid and that actual
low flow was the reason.
Overgreasing
of Electrical Motors
NRC Information Notice 88-12, Overgreasing of Electric h1otor
Bearings,
was reviewed
by the Operating Experience
Assessment
(OEA) group,
and recommendations
were sent to the Plant Staff
Review Committee
(PSRC)
on 6/13/88.
The
PSRC agreed to the
recommendations
on 9/29/88 and issued
an Action Request
(A/R).
The completion date
was revised to 4/1/89 and then to
10/31/89.
As of 1/10/90, the action
was still not complete
because
resources
for this project had
been shifted to other
activities.
Plant maintenance
personnel
stated that over-
greasing
had not been
a problem at Diablo Canyon,
and that the
issue
was being addressed
cautiously to ensure that corrective
(3)
action to address
the issue did cot result in undergreasing
of
motors.
Nevertheless,
the inspector
concluded tttat the time
to complete
these
PSRC-approved
actions
to .address
recognized
industry concerns
was excessive.;
Blind Flange
on Condensate
Storage
Tank
(CST) Overflow Line
C
A licensee-conducted
Safety System Functional Audit and Review
(SSFAR) of the
AFW system determined in July 1989 that
a blind
flange (with a 2-inch hose connection)
was installed
on the
14-inch overflow line for the Unit 2 CST.
The
SSFAR raised
several
questions,
including why the flange
was in place
and
whether possible overpressurization
of the
CST had occurred.
The inspectors
noted that
a work order
(WO) was written and
the flange was
removed
from the overflow'ine on the day of
discovery.
The absence
of a flange on the Unit
1
CST was also
verified.
Examination
by the inspectors
identified two ARs,
two quality evaluations
(gEs), three action evaluations'(AEs),
and the one
WO (referenced
above) dealing with this issue,
and
making numerous
references
to one another.
Although this
made
it tedious to determine
the actual status of related actions,
it was determined that little action, other than removal of
the flange (along with consideration of security concerns
and
confirmation that other tanks
were not affected),
had
been
accomplished.
In particular, the following actions called for
by the
SSFAR were still incomplete:
Correction of system flow diagram.
Engineering evaluation to determine
whether the
CST could
have
been overpressurized
(an 'initial evaluation
by
Engineering that this was indeterminate,
and therefore
not
a concern,
was rejected
by gA).
Determination of reportability.
Determination of root cause.
(4)
While these actions
were being tracked
by the licensee's
program for eventual
completion, the amount of time to address
them (particularly the question of reportability) appeared
to
be excessive.
(SG)
Slowdown Monitor
While observing control
room activities
and discuss'ing
correc-
tive actions
on problems identified by operations,
the
inspector determined that Operations
had experienced
recurring
problems with Technical Specification (TS) 3.3.3. 10.
The
concern
was with the radioactive
gaseous
effluent monitoring
instrumentation for the steam generator
blowdown tank vent
gross radioactivity monitor (RN-27).
The steam generator,
blowdown system at
DCPP is, designed to
maintain
water chemistry within specified
limits.
The .'blowdown of approximately
20 - 30
gpm
per'enerator
flows to the .blowdown tank
and discharges .to'he
circulating water discharge
tunnel.
To conserve water;
a
second
blowdown system .recycles the flow through
a treatment
and recovery system to 'the main condenser.
Each of the above
systems
has
a capacity of approximately .150
gpm.
Each unit is
equipped with the above systems.
The steam generator
blowdown flow to the blowdown tank is
continuously monitored for radioactivity by the blowdown
radiation liquid sample monitor RN-19. If this system detects
a high concentration of activity in the blowdown flow, the
blowdown isolation valves
and the blowdown tank effluent
valves will be automatically closed.
Approximately 35 percent of the blowdown flow flashes to steam
inside the tank and is vented to the atmosphere.
The
remaining
65 percent, is condensed
in the blowdown tank.
This
condensed
portion is monitored
by radiation monitor RN-23
prior to discharge.
The steam
vented to atmosphere
is
monitored for gross activity by radiation monitor
RN-27.
This
monitoring system takes
a sample
from the steam being vented,
passes it through
a sample cooler to condense
the steam to
water,
and routes
the condensed
sample through the monitor.
Past experience
has revealed that the
RN-27 sample cooler
becomes
air-bound during startup
and when the blowdown flow
rates
are changed.
This problem was documented
on AR's
A0021200
and A0029247 in 1986.
Design
changes
DCP-J-35910
and
36910 were issued in November
1986 to modify the sample lines
and correct this problem.
The modifications were accomplished
in September
1987, but did not correct the problem.
Since
that time, operators
have
been required to verify proper
system flow each
12-hour shift'uring their rounds
and also to
recheck
the system if blowdown flow changes.
Discussions
with operations
management
and the system engineer
for this system revealed that the licensee
was concurrently
pursuing
two plans in an attempt to resolve this problem.
One
proposed
plan would replace
RN-27"and provide
a positive flow
to this monitor as part
a planned
upgrade of the plant
radiation monitoring system.
This project was in the planning
stage
and was listed under the
FY-90 budget
as
Budget Line
Items (BLI) 63
A and
63 B. If approved
and implemented, this
project could be completed in 1992.
The other plan involved
a
proposed
TS change
removing the requirement for RN-27 and
permitting removal of the monitor.
Based
on the above, it appeared
that management
had
been
aware
of this problem for over three years,
but had not taken appro-
priate action to correct the problem.
At the time of the
inspection,
operator
action
was required
each shift to verify
that the monitor .-was operational
Under conditions
and
procedures in effect at that time, RM-27,
a TS-required
component,
could .be inoperable for up to
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
This
indicated
a failure of management
to take appropriate
corrective action
and resolve this
known deficiency,
and was
considered
by the team to constitute
a violation of 10 CFR 50,
Appendix;B, Criterion XVI..
(Enforcement
item 275/90-01-01)
(5)
Calibration Ratios for Measuring
and Test Equipment
(METE)
NCR DC0-87-gA-N001, Measuring
E Test 'Equipment
(MSTE) Calibra-
tion Accuracy Ratios,
was issued in September
1987.
The Tech-
nical
Review Group
{TRG) met initially in October
1987
and then
twice more before
a
new TRG Chairman
was
named
on January
15,
1988.
The Plant Manager requested
a
new direction
on February
10,
1988.
On February 25,
1988,
gA Audit 88804T resulted in
an Instrument
and Controls
( ISC) Stop Work Order.
The next
TRG meeting did not occur until April 30,
1988.
Department
action plans
were not due until February
17, 1989,
and were
submitted
by that date except for the Maintenance
Department,
which did not submit theirs until August 16,
1989.
The
inspector
reviewed the activities associated
with this
NCR and
concluded that the time to develop action plans
was excessive.
The inspector further concluded that, while the action plan
development
time was excessive,
the impact
on nuclear safety
was minimal once the problem was fully understood
in that
ISC
stopped calibrating their own test equipment
and utilized gA-
approved calibration vendors,
including General
Construction,
. until they had completed
the actions
indicated
by this
NCR.
(6)
Surveillance
Procedure
Weaknesses
During a review of five surveillance tests
conducted
on the
Unit
1 safety injection system during the fall 1987 outage,
the inspector
noted the following discrepancies:
After step 8.3.1 of STP.V-4A, Functional Test of ECCS
Check Valises, Revision 3,
per formed on November 14,
1987,
an additional step
was
added directing the operator to
"close 1128,
112C [ ]."
Also, step 8.2.26 of this proce-
dure stated,
"Record flow on FI-9718," and included
acceptance
criteria of greater
than or equal to 3976
GPM.
A measurement
of 2380
GPM was recorded for FI-971B.
A
notation at this step specified that the procedure
was in
error and that the flows of FI-9718 and FI-970B should
be
summed to give the required data for this step.
The
surveillance test result was accepted
based
upon this
notation.
No On-The- Spot
Change
{OTSC) was written.
Step 7.4 of STP.V-SC,
ECCS Hot Leg Check Valve Test,
Revision 2, Performed
on December 4,
1989 stated,
"Verify
10
current calibration of the following plant instruments,"
"
and listed SI Test Line Flow, FI-928A and FI-928B.
These
.
instruments
cannot
be cal'ibrated.
Test engineers
noted
that these instruments
were not calibrated
and continued
with .performance of the procedure.
No OTSC was written.
On step 8:16.25 of STP.V-5C,
ECCS Hot Leg Check Valve
Test, Revision 2, performed
on December 4, 1989,
a
requirement
was handwritten in to "Cap" valve SI-41.
No
OTSC was written.
Step 7.5 of STP.V-5A,
Check Valve Leak Test,
Post-Refueling
Maintenance,
Rev. 5, performed
on
December
1,
1989 required that the current calibration of
SI test line flow indicators,
FI-928A and FI-928B,
be
verified.
Although these
instruments
cannot
be
calibrated,
no
OTSC was
made to the procedure
to change
these
requirements.
Technical Specification (TS) 6.8. 1 requires that written pro-
cedures
be implemented including the procedures
recommended
in
Appendix
A of Regulatory
Guide 1.33.
Appendix
A of Regulatory
Guide 1.33, Section B.b, states
that "... procedures
are
required for each surveillance test,
inspection ... listed in
the technical specifications."
TS 6.8.3 specifies
approval
requirements
for temporary
changes
to the procedures
of TS 6.8. 1.
Plant Administrative Procedure,
AP E-454,
Issuance
and
Approval of On-The-Spot
Changes
to Procedures,
Revision
15 (in
effect during this time period), Section 2.1, states, "It is
necessary
tn issue
an On-The-Spot
change
(OTSC) if ...The
procedure
cannot
be followed as written".
The above
examples
constitute
a violation of Technical Specifications 6.8.3.
(Enforcement
Item 275/90-01-02)
Licensee Audits 88831T,
performed September
30 - November
14,
1988; 88833T,
performed
November 21,
1988 - February
17,
1989;
and
SSFAR 89800T,
issued
May 31, 1989,
documented
similar
findings wherein
OTSCs were not issued prior to performance of
surveillance
procedure
changes.
The continuing recurrence of
this problem indicates
a failure by the licensee to take
effective corrective action to address
this concern.
Other items noted during
a review of these
procedures
appeared
to the inspector to indicate
a lack of rigor in procedural
adherence.
These included:
On STP.V-15, 8.4.3.b, neither block LCV112B nor LCV112C
was checked to indicate which valve was closed;
On Step
8.4.14,
"Close
CVCS 8106 and/or HCV-142," nothing
indicates
which was done;
on Step 8.4.6,
"Open or Bypass
HCV-142," nothing indicates
which activity was performed;
.11
%he shift-manager did*not check "yes" or "no", regarding
concurrence
with Step 9.6.a;
and
on Attachment 11.3,
D,
WWST level, no;check
was entered to .indicate which level
indicator"was .used.
On STP.V-4A, Step 9.3.1,
"Are all valves tested. deter-
"
mined to be
OPERABLE?",
a check to indicate-."yes" or "no"
was not made
by the shift foreman.
Other observations
noted during the review of these procedures..
included:
Step 8.4 of STP.V-5C recorded
Psat
as
124.4 psig.
Step
8.7.8, required adjustment of pressure
until it is
,slightly above Psat.
A reading'of
150 psig was recorded
in this step.
The gage accuracy of the indicator used,
PI-942 is +60psi, leaving the actual
pressure
as possibly,.
less
than Psat.
A similar action
was observed
in STP.-
V-5A.
Step 8.10. 1 recorded saturation
pressure
(Psat) at
121 psig.
Step 8.12.4 recorded actual
pressure
P) at
100 psig; since
P was less
than Psat,
no additional.
actions
were required.
Using the +60 psi
gage accuracy
correction,
actual
pressure
could Eave
been greater
than
Psat,
requiring additional
procedure
steps
to be
performed.
Additional information provided to the
inspector
subsequent
to the inspection
showed that this
accuracy
was technically adequate for performance of
these tests,
although the issue indicated insufficient
rigor in the application of instrument error to test
readings.
STP.V-5A and
V-5C contained
steps
which stated "... if a
steam void is suspected,
the line can
be repressurized
from the
RHR System
by opening
8885A or 8885B.
If a
valve is opened to repressurize,
ensure that it is
reclosed".
The procedure
also stated "If the pressure
on
PI-942 is greater
than Psat,
close 8963,
open 8961,
then
carefully throttle open 8963 until pressure
is reduced to
approximately Psat.
Close 8963"
(No guidance
was pro-
vided to reclose
8961).
Each of these
steps
contained
several
valve manipulations
and
a variety of actions
which could lead to operator confusion
and error.
Due to a valve misalignment in November
1989 during perfor-
mance of STP.P-4B,
"Routine Surveillance Test of Containment
Spray Pumps", the licensee
ran
a containment
spray
pump with
the outlet valve closed.
Licensee corrective actions for that
event included changing the plant Engineering Writer's Guide
to include increased
signoffs.
During discussion of the above
findings with the licensee,
management
also recognized
the
inadequacy
in the quality of procedures
and stated that
corrective actions
would be taken.
32
Battery Charger Firing Nodules
To evaluate
the timeliness
and effectiveness
of corrective
- actions initiated by the plant and design electrical engineer-
ing staffs for the vital
125V
DC system,
the inspector
reviewed
18 ARs initiated for this system during calendar year
- 1989.
Except for battery charger problems, this review did
-not identify any significant areas of concern.
The vital
125V
DC systems
at the Diablo .Canyon
Power Plant
(DCPP) Units 152 incorporate
a total of ten Class
1E battery
chargers
(five per, unit).
The chargers
were manufactured
by
.Exide Power Systems
Division (Nodel
UPC, Three
Phase)
and are
approaching
20 years old.
Located within each
charger are six
firing module circuit boards.
Basically, the firing modules
form part of the control circuitry necessary for regulating
and balancing the output current developed
by each of six
associated
solid state, silicon controlled rectifier (SCR)
devices.
Upon an identified failure of a firing module, the plant's
practice for repair of the affected battery charger
has
been
to replace
the affected circuit board
as
an entire unit.
Following replacement,
the failed circuit boards
have
been
discarded.
The licensee
has not performed troubleshooting of
such circuit board failures to the component level.
Action Request
(AR) No. A0161585, dated
September
21,
1989,
was found to have
been initiated by the Plant System Engineer
to document
and track his finding that the battery charger
manufacturer,
Exide, is
no longer producing or stockin9
replacement firing module circuit boards for the type of
chargers
currently in use at
DCPP.
During discussions
with
members of the
PGSE Plant and Design Electrical Engineering
staff, it was learned that the
125V
OC Battery Chargers
are
experiencing
a relatively high rate of firing module circuit
board failures.
In addition, the engineering staff indicated
" that the vast majority of such failures
have
been detected
during the performance of a specific section of preventive
maintenance
tests
which requires
the load current developed
by
each of the six SCRs
be balanced
to within +5%.
At DCPP,
such
testing is performed at approximately
18-month intervals in
accordance
with electrical
maintenance
procedure
NP E-55.2,
Routine Preventive
Naintenance
'Of Station Battery Chargers.
The licensee
was not maintaining
a formal method for tracking
equipment failures at the sub-component
level.
Therefore,
an
accurate
estimate of the firing module failure rate was diffi-
cult to determine.
Consequently,
somewhat differing failure
rate estimates
were reported to the inspection
team.
For
example,
the electrical
design engineering
group leader stated
that
4 card failures
had occurred during the previous
18
months, while a
memo dated
December
12, 1989, from the design
~
'
13
system engineer to the p'1ant system'engineer
indicated
a
failure rate of 4 board failures .every
12 months.
It should be noted that sub-component failure information of
this type is, at best, difficult;to retrieve using the present
Plant Information Management
System
(PINS) configuration.
While the fai lure of a specific piece of equipment (e.g.
battery charger)
would be expected
to generate
a.separate
AR,
that is entered into the
PINS tracking system,.the identifi-
cation of specific sub-component(s)
replaced
during subsequent
corrective maintenance activities
was typically being docu-
mented only on the corrective maintenance
work order(s).
Therefore, finding .the exact
number of failures of a specific
type of sub-component
(such
as the firing modules)
would
require
a manual
review of all corrective maintenance
work
orders written against
each piece of equipment that uses that
sub-component (i.e. the
10 battery chargers).
An estimate of firing module failure rate
was also attempted
through
a review of the Institute of Nuclear
Power Operation
( INPO) Nuclear Plant Reliability Data System
(NPRDS) data
base.
This review, however, did not identify any firing
module circuit board failures reported
by DCPP.
Based
on
discussions
with the licensee's
NPRDS coordinator, it appeared
that the failure of equipment to meet preventive maintenance
test specifications
is classified
by
INPO as
an "incipient"
type of failure.
Since
such failures are typically detected
prior to the occurrence
of an actual
equipment operability
problem, their. reportability under existing
INPO guidelines is
optional.
Corrective actions
taken
by the licensee
to resolve the firing
module failure rate vs. availability concern
include locating
a source for the purchase
of 29 replacement circuit boards
and
evaluating
the feasibility of relaxing the current preventive
maintenance
acceptance
test criteria.
These criteria require
balancing
load current developed
in each leg of the charger
from +5% at 200 Amps (half-load) to +lOX at 300
Amps (3/4
load) . The adjustment of individual ECR load cur rent balance
is currently specified in PGSE electrical
maintenance test
procedure
number
MP E-55.2, Routine Preventive
Maintenance of
Station Battery Chargers.
Step
Number
15 of this procedure
was found to specify
a +5% tolerance in load balance
between
individual
and instructed the technician to adjust the
firing modules to obtain the desired values.
The inspector.
reviewed the manufacturer's
instruction book for the Exide
Model
UPC Battery Chargers
(PGSE Instruction Book Number
DC-663344-34-l).
Based
on this review, specific manufacturer-
recommended
tolerance
values for such adjustments
of the
Firing Nodules were not clear.
During a subsequent
interview,
the System Engineer stated that
a plan to revise this test
requirement
to a 'less restrictive test criterion (i.e. 10Ã),
was
based
on his telephone
conversations
with the manufacturer
and is in accordance
with the manufacturer's
recommendations.
0
14
Although such corrective
actions,.may mitigate 'this concern in
the short term, they do not appear to provide,a long-term
solution.
The licensee
had not performed
a root:cause
analysis
to determine
the exact nature'f the. circuit,board
fai lures that have occurred.
Such an;assessment
would provide
valuable troubleshooting
information which may identify
recurring failures of a particular circuit board component.
In addition, since the existing preventive maintenance failure
data
do not indicate
how far out of tolerance the firing
module circuit boards
have
been found during previous
fai lures, it is not clear .that relaxing, the existing testing
criteria would significantly reduce
the observed failure rate.
In addition, it should
be noted that the
29 replacement
boards
have not as yet been
purchased
and that approximately
6 boards
remain in spare stock.
d.
Performance of Safet
Oversi ht Grou
s
The team also assessed
the performance of the various safety
oversight
groups in the licensee's
organization, particularly with
regard to their involvement in the corrective actions
program.
This review included the following oversight groups:
On-Site Review Group
(OSRG)
Plant Staff Review Committee
(PSRC)
Plant guality Assurance
(gA)
Plant guality Control
(gC)
General Office Nuclear Plant Review
8 Advisory Committee
(GONPRAC)
President's
Nuclear Advisory Committee
(PNAC)
Corporate guality Assurance
(Technical Auditing and
Program
Auditing)
Nuclear Operations
Support
(NOS)
Operations
Events
Assessment
(OEA)
Although time limitations did not permit the team to perform an
extensive
review of the performance of each of the above groups,
.
the level of review performed indicated
each of the groups to be
participating effectively in support of the corrective action
program.
An observation
was
made regarding
GONPRAC.
Overall, this was
considered
to be an effective and insightful group with significant
industry experience.
An inspector's
attendance
at one meeting
showed little hesitancy
by the
GONPRAC to probe
and address
~
'
significant issues.
However, regarding their responsibility 'for
audits required
(by the'Technical
Specifications) to be conducted
"under the cognizance" of the'ONPRAC, the Committee's
review was
not extensive.
The review did confirm that audits
were conducted
by gA in the proper scope
and frequency,
but little input was
provided to gA regarding
issues of current industry emphasis
or of
specific concern to the Committee members.
GONPRAC also did not
normally review the resulting audit reports, but,reviewed
those
significant issues
brought'o their attention
by the
gA auditors.
'I
The review of industry experiences,
including
NRC Information
Notices,
by
NOS was found by the
team to be effective.
However, it
'ppeared
to the team that clear responsibility for review and
feedback of DCPP operating experience
was not defined.
Licensee
representatives
stated that Training and other groups
performed
portions of this function.
Licensee
management
stated that this
responsibility would be considered for assignment
to a
new
organizational
group which was still being evaluated
(see followup
item in paragraph 3.e).
Conclusions
Overall, the inspection
team considered
the licensee's
corrective
action program to be functioning with reasonable
effectiveness.
In
view of the records
reviewed
and interviews conducted, it is
noteworthy that
no issues
indicating
a need for corrective action
were identified which had not been entered into the
PINS corrective
action program.
The team also did not identify any problems
or
issues of safety significance which were not corrected
in an appro-
priate
and timely manner.
However,
as discussed
in paragraph
3.c
of this report, several
items of lesser individual significance
were determined to have
been
open for extended
periods,
and it was
not apparent
that the licensee
had addressed
the collective
significance of these
long-standing
issues.
The team was not able
to determine
how many other such
items were still open in the
corrective actions
system.
The team noted that. each organizational
group was responsible for
acting
on action requests
(ARs) assigned
to it (until completed or
reassigned
to another group).
However,
no group or person
appeared
to feel responsibility or "ownership" for managing
the overall
system,
or for shepherding
individual
ARs to completion.
In addi-
tion, trend analyses
performed
by the licensee
showed the total
number of ARs to be increasing with time.
This was partly due to
a
management
policy, considered
a noteworthy strength,
which
encouraged
licensee
personnel
to maintain
a low threshold for the
initiation of ARs.
However, there
was
an apparent
need for someone
to more actively encourage
the closure of ARs.
Management
was
similarly concerned with the number
and average
age of quality
evaluations
(gEs)
and nonconformance
reports
(NCRs).
Plant
management
stated at the end of the team inspection that,
based
on
an assessment
previously in progress,
a
new organizational
group
was being established
to provide oversight of the corrective,
16
actions,
root:cause, <rip reduction,
and other similar programs,
and 'to provide feedback to <he plant staff-on
DCPP operating
experiences.
The licensee'.s
plans in this regard will be evaluated
during future inspections.
(Followup Item 275/90-01-03)
~5R
Selected plant systems
were assigned to members of the inspection
team
for emphasis
during the inspection.
This emphasis
included walkdown of
the system,
examination of corrective actions
and other records associ-
ated with the system,
and interview of the system engineer.
Recent
history or problems
were also reviewed where appropriate.
Inspection
findings on the various systems
reviewed are discussed
below.
a.
Safet
In'ection
S stem
From a list of outstanding
ARs for the system,
the inspector
selected
35 for a detailed review of the status.
Although some
appeared
to be untimely in completion,
adequate justification was
documented
regarding
why the items were still open.
The inspector selected
35 closed
ARs and reviewed the closure of
each.
The inspector
concluded that in each
case
proper evaluations
and corrective actions
had
been taken.
The inspector
performed
a walkdown of the SIS for each of the
units.
Discrepant conditions,
such
as small leaks evidenced
by
boric acid buildup, were noted;
however, all conditions
observed
by
the inspector
had
been
recorded
on an AR.
The inspector interviewed the SIS system engineer
and judged
him to
be well qualified and knowledgeable
about the system.
The
inspector also reviewed the last two quarterly system reviews
and
noted that they appeared
to be well documented with items of
concern clearly identified.
b.
Auxiliar
S stem
Approximately 64 ARs were issued for the
AFW system
between July
1
and December
31,
1989.
The inspectors
selected
10 of these for
detailed review, including examination of the identified problem,
its proposed resolution,
and documentation of a guality Evaluation
(gE).
The
gEs normally include the immediate corrective actions,
root cause
analyses,
and corrective actions to preclude repetition.
The problems
were found to be clearly identified, with corrective
actions properly articulated in the documents.
Although no
safety-related
issues
were found to have received
improper or
untimely attention, the inspectors identified two problems of
lesser significance which had required excessive
time for
completion of corrective actions
(see
paragraphs 3.c(l) and (3)).
A walkdown of accessible
portions of the Unit 1
AFW system did not
identify any discrepant
conditions which were not documented
in the
~
'
17
Plant Information Management
System
(PINS) corrective action-data
base.
Numerous
adverse
housekeeping
items were noted,
as discussed
further in paragraph
7.
- Discussions
with the system engineer
showed
him to be familiar with the
AFW system
and knowledgeable
of
its performance history.
The 'i~spectors
reviewed the results of the recently concluded
,Safety System Functional Audit and Review (SSFAR), report 89808T,
issued
November
17, 1989.
This
PGSE internal audit assessed
the
operational
readiness
of 'the
AFM system
and its associated
components.
The inspectors
noted that, although the audit was
performed
under the auspices
of the guality Assurance
Manager,
staffing of the audit team relied heavily on contractor support.
Licensee
management
noted that this
had
been
done in order to
provide the technical
background
needed
by the audit team.
The
inspectors
acknowledged this objective, noting that the licensee
should also provide sufficient involvement of PGSE employees
in the
audit and in the resolution of identified corrective actions to
ensure that substantial
corporate
memory from the effort remains
with the
PGSE staff.
Licensee
management
agreed with this concern
and stated that it was being considered
in the staffing of audits.
The
SSFAR identified 21 concerns
and
17 recommendations
requiring
followup.
These
were grouped
as
6 Nonconformance
Reports
(NCRs),
15 gE-AFRs (audit finding reports),
and
17 ARs.
The inspectors
verified that each of the concerns
and recommendations
identified
in the report
had
been properly tracked to an
The
SSFAR report established
target dates for staff responses
to
gE-AFRs
and ARs.
These target dates
allowed 30 days for a gE-AFR
and 45 days for an AR.
The inspectors
noted that in most cases
the
response
goals established
by gA had
been met; however, in about
one-third of the cases it appeared
that
a response
had yet been
made.
Licensee
gA representatives
stated that followup on these
issues
was in progress.
A representative
of Technical Auditing, in a telephone
interview,
stated that management
recognized
a slippage
in timely responses
to
the action items
and was taking steps
to address
the matter.
Effective February 5, 1990,
a two-man team
was to conduct followup
on action items
and ensure that corrective actions
were properly
handled.
The
SSFAR team leader
was to lead the followup team.
As
part of management's
incentive goals for 1990, the team would be
responsible for a detailed review of each
item and would complete
the process
by May 1990.
Additionally, periodic memoranda
would be
issued to management
covering the status of corrective actions
and
highlighting areas
in need of management
attention to ensure
the
completion of timely action.
Emer enc
Diesel
Generators
The emergency diesel
generating
(EDG) system
(System
21) was
inspected for the timeliness
and effectiveness
of corrective
~
'
18
.actions necessary
to maintain <he five emergency
diesel
generatino'units
at .Diablo Canyon in reliable operating condition.
This wa~
.achieved
by examining
a wide variety of records
and documents,
including 40 action requests,
17 maintenance
history records,
8 surveillance Nests,
.6 nonconformance
reports,
12 work orders,
2 .-
,design
change
packages,
11 system procedures
(operating,
mainten-
ance, etc.),
2 system status
reports,
and various piping and
instrument drawings (flow diagrams).
These
documents
applied to
-the engine
and generator,
as well as the fuel oil storage
and'ransfer
systems.
The recurring records
reviewed, in most cases,
were those
generated
during the past six to seven months.
The
system
was also discussed
and reviewed with the staff members
who
are directly involved with the system,
including the system
engineer,
design
system engineer,
plant engineer,
and plant
operators.
System
21 was also discussed
and reviewed with the
guality Support Manager,
Onsite guality Audit Supervisor,
Acting
guality Control Supervisor,
and various other staff members.
The
EDG system consists of five 2600
KW diesel
generating units.
Two are installed per Unit, with the fifth unit installed
as
a
"swing" unit, available to either Unit
1 or Unit 2.
Three of the
EDG units are located in the reactor plant Unit
1 area of the
turbine building, and two are located in the Unit 2 area of the
turbine building.
A sixth (new) diesel
generator of the
same
capacity is schedule
to be installed in Unit 2 area of the turbine
building during 1992.
This modification will provide three
dedicated
EDGs each for Units
1 and 2, eliminating the
need for a
swing
EOG unit.
The five emergency diesel
generator units were inspected
in the
field several
times during the inspection period to follow up on
corrective maintenance
work and surveillance in progress
during
this period.
The two redundant fuel oil storage
and transfer
systems
were also walked
down to confirm modifications completed
on
the systems
during the inspection period.
Several
housekeeping
problems
were noted during these
walkdowns of the
EOG system,
as
discussed
in paragraph
7 of this report.
A modification made to each of the redundant fuel oil storage
and
transfer
systems
was completed during this inspection period.
This
modification consisted of installing
a pressure
control valve
(PCV)
in the fuel oil transfer
pump bypass line (piping).
The
operates
to prevent the transfer
pump from cycling on and off to
replenish
the five EDG fuel oil day tanks
when all
EDG units are in
service during and following an accident.
Continuous operation of
the transfer
pumps is considered
a safer
mode of operation than-
frequently cycling the transfer
pump on and off as the level
controls for each
day tank call for for the addition of fuel.
However, in making the modification, two valves were relocated in a
manner which inhibits the transfer of diesel fuel oil between
storage
tanks without compromising the intended separation
of the
two storage
and transfer systems.
The transfer of fuel oil between
19
storage tanks is
a monthly operation,
required under Surveillance
Test Procedure
(STP) N-25A, Leak Rate Test for Underground
Fuel
Oi1
storage
Tanks.
Procedure
N-25A was in the process of being revised
.during the inspection period to accomp1ish
the transfer using
a
.portable .pump.
A review of the processing
of the 'DCP for this'modification
revealed that Operations
was not afforded sufficient time to review
the design pursuant to procedure 3.6, Operating Nuclear
Power 'Plant
Design
Changes,
prior to the advance
design coordination meeting.
Operations indicated that,
had they been given sufficient time to
review the initial design for the modification, they would have
identified the prospective inability to transfer fuel oil between
storage tanks
(using the installed transfer
pumps)
as
an Operations
concern.
This was identified as
a licensee failure to fully follow
the established
procedure 3.6,
and constituted
a violation of
'0
CFR 50, Appendix 8, Criterion V.
Before completion of the
inspection, the vmspector
determined that the licensee
had
recognized this concernand taken appropriate corrective actions.
Consistent with the
NRC Enfoncement Policy,
1D CFR 2, Appendix Z,
this item was sot included in the Notic~ of Violation Mich
accompanies
this inspection repoM.
(Non-cited violation
275/90-01-04)
Generally, it was concluded
from the inspection of the
EDG system
that corrective actions
had been properly initiated where appro-
priate,
and that the timeliness
and effectiveness
of corrective
actions for the system were adequate.
It also appeared
that
licensee
personnel
were familiar with and were effectively using
the PINS and
AR systems
to initiate cormctive action on identified
problems
and deficiencies.
Vital 125V
DC S
tern
(1)
Backgr ound
The vital DC system provides continuous
power to such loads
as
circuiX4reaker control
and protection, diesel engine
generator control and ln otection, reactor coolant system
control valves, annunciators
and 9G-to-AC voltage inverters
for nuclear instrumentation.
At Diab1o Canyon',
redundant, safety-related
{Class ZE) loads
are supplied from three physically separate and electrically
independent
125V
DC switchgear
buses for each unit. Each of.
.the three
125V
DC switchgear buses is supplied power from a
dedicated battery and
a dedicated battery charger.
In
addition,
one backup battery charger is shared
between
two
125V,DC buses
and
a dedicated
backup battery charger is
provided for the third 125V DC bus (i.e., UniM 2 and
2 each
have five battery chargera).
(2)
(3)
Corrective Actions'Related
To The Vital 125V DC'ystem
e
The assessment
of corrective action activities associated
~with
the vital 125V
DC system concentrated
on a review of selected
problem tracking 'documents,
which included Action Requests
(ARs), guality Evaluation - Audit Finding Reports
(gE-AFRs),
and Corrective llaintenance
Work Orders
initiated during calendar year
1989.
In addition, interviews
were conducted with p'lant and design engineering staff members
involved in the evaluation
and resolution of problems
asso-
ciated with this system.
Except for the fo'llowing issues that
are discussed
in detail in other sections
of this report,
these
reviews did not identify any significant areas
of
concern with the licensee's
corrective action program.
Battery charger firing module failure rate vs.-
replacement availability concern
(Paragraph
3.c(7))
Training of Design System Engineers
(Paragraph
5)
Housekeeping
deficiencies
observed
during the system
walkdown (paragraph
7)
System
Ralkdown
On Wednesday,
January
31,
1990 the inspector participated
in a
walkdown of the
DCPP Unit
1 and
2 vital 125Y
DC system
and the
4160V switchgear.
Licensee
representatives
present
during the
walkdown included the Plant
and Design System Engineers for
the
125V
DC system,
the Electrical Maintenance
Engineer,
and
the Nuclear Engineering
and Construction
Services
(NECS)
Electrical Engineering
Design
Group Leader.
Overall, the systems
appeared
to be well maintained with no
obvious signs of material
degradation
or poor quality repairs.
The inspector
performed
a visual inspection of the internal
areas of a selected vital 125V
DC battery charger
and
a 4160
switchgear circuit breaker cabinet.
This visual inspection
did not identify any issues of concern.
The cabinet internal
areas
were free of debris,
and electrical
connections
and the
physical configuration of components
appeared
to be
acceptable.
e.
480/4160V
S stems
Background
The 480 and 4160 Volt AC systems
have presented
the licensee
with few difficulties during the past few years.
Since these
systems
were not included in the system engineering
program
when it was initially instituted, there
was
no formal site
System Engineer,
and there
had
been
no joint walkdowns with
the Site and Design System Engineers,
and no quarterly system
reports.
A station electrical
maintenance
engineer
was acting
~
'
21
(2)
(3)
f.
Com
as the site System Engineer for these
systems
(as discussed
.ir,
paragraph
5, the corporate
Design System
Engineer
was not
aware of .this when he was. interviewed
by the inspector).
Corrective Actions Related to the 480/4160;VAC Systems
A detailed review of approximately
50% of all the
94 gEs, on
PINS and approximately
20K of the 256 ARs issued
during .1989
revealed
no unusual
concerns,
no chronic problems,
and
no
indications of corrective actions
which had not received
appropriate
levels of attention.
The inspector
noted that that switchgear associated
with a
given piping system were usually entered into PINS under the
system
number of the piping system rather than under the
system
number for the switchgear.
While many examples of this
were noted, there were
some exceptions
which indicated
some
inconsistency
in this area.
The inspector
had
no additional
concerns
with the 480/4160
VAC systems
beyond those described
under
system walkdown.
System
Walkdown
A walkdown conducted
on January
31,
1990 revealed
systems
which appeared
to be operable
and in good physical condition.
However,
two adverse
conditions
were noted.
One was the
absence
of relay calibration cards in Unit 2 for the 4160
VAC
"F" Bus, for two overcurrent relays for safety injection
pump
circuit breaker ¹21,
and for auxiliary salt water
pump circuit
breaker ¹21.
A second
adverse
condition was
a Unit 2
4160
VAC "G" Bus differential relay which had not been cali-
brated since July 21,
1983.
These conditions
were being
addressed
by cognizant personnel,'nd
calibration of the "G"
Bus relay was scheduled for the
1990 refueling outage.
A number of housekeeping
deficiencies
were noted in these
rooms, including two which had the potential to impact
operability.
One was
a beverage
can
on top of a 480
VAC
transformer;
the second
was
a missing section of fire barrier
foam between
the Unit 2 4160
VAC "H" and
"G" cable spreading
rooms.
This reduction in foam thickness
might have permitted
a fire in the "H" room to spread to the "G" room under certain
circumstances.
These
concerns
are discussed
further in
paragraph
7 of this report.
ressed Air S stem
Background
and History
The compressed air system at the Diablo Canyon
Power Plant
(DCPP)
was designed
and installed
as
a shared
system for units
1 and 2, and provides the service
and instrument air for both
units.
Air enters
the system through
a filter on the air
compressor
The compressed air passes
through
an aftercooler,
22
where the heat of compression is removed,"then through a.
pre-filter and the air dryer before it is stored inChe
,receiver Vor system
use.
Afterfilters further clean the air
before delivery to the various .systems
requiring
compressed'ir.
The compressed
air system at
DCPP is non-safety grade,-
as is the case for most U.S. plants;
however, it does
serve-
a
function of mitigating complications of plant .transients
and
~
challenges
to safety systems. ".
Operating experience
with the compressed air system
has
been
marred
by numerous
and persistent
operating
problems,
including the following:
System underdesign for all of the plant's air needs
r
System contamination consisting of grit, rust, scale
and
water intrusion
(2)
Numerous air system leaks that contribute to the system's
volume requirements
Component failures, including compressors,
dryers,
valves, regulators,
and instrumentation.
A contributor to the compressed air system
problems
was the
inadequacy of preventive maintenance.
Corrective actions
Inspector guidance for the air systems
portion of the
inspection
was provided
by Operating
Experience
Feedback
Report,
NRC Information Notice 87-'8; the Region
V
maintenance
team inspection
conducted
on July ll - 22,
1988
(Report 0275/88-15
5 323/88-14);
and the licensee
responses
to
the enforcement
items identified in that inspection report.
Over the past several
years,
in response
to the numerous
operational
problems involving the compressed air system,
the
licensee
has
embarked
on
a major upgrading of the system.
Changes
to the system,
including those in place, currently
being installed,
and future enhancements,
were reviewed
and
evaluated
by the inspection
team.
As part of the evaluation,
the piping and instrument drawings
(PSIDs) were reviewed,
along with applicable
design
change notices
(DCN's)
and
actions
requests
(AR's).
Replacement
of air cooled rotary compressors,
nos.
5 and 6,
with new water cooled rotary type compressors
(DCP-J-43374)
was in process
at the time of the inspection.
The root cause
of the high maintenance
and operational
problems for the
original air compressors
was identified as
a higher ambient
operating temperature
than that for which the units were
designed.
The replacement
water cooled compressors
were
on
~
'
23
site at the time of the inspection,
but had not been
installed.
Installation work was being performed
on one
100
percent'apacity
cooling water booster
pump, capable'of serving both
compressors.
A backup cooling water pump, also being
installed, will auto-start if the operating
pump. trips .from
power failure.
A solenoid-operated
auto bypass is provided
around
each
compressor
to assure
minimum pump cooling water
flow.
The plant fire water system
serves
as
an additional
backup
source of cooling water should the service cooling
water system fail.
The two compressors,
currently powered from a unit
1 non-vital
480V bus, will be powered from different unit busses,
along
'ith
the
new cooling water pumps.
The rebuilding of the compressed air system also includes
installation of a new larger capacity air dryer unit along
with resized
pre- and afterfilters
ahead of the receivers.
An ongoing major cleanup of the instrument air system
was in
progress
at the time of the inspection to free it of sand,
rust, pipe scale,
and water found in the system during 1988.
This was expected
to be completed during the next refueling
outage of unit 2 (spring of 1990).
The instrument air system
was being supplied with air by a
temporary air compressor
located in the yard on the west side
of the turbine building.
The plant's rotary air compressors
Nos.
05 and 06 were aligned to supplement
the instrument air
system if demand
should
exceed
the capacity of the temporary
air compressor.
The four installed reciprocating air compres-
sors
were aligned
as
a third source of instrument air if
needed.
The licensee's
plans,
pursuant to AR A0150078
and design
change
DCP-J-43374,
to replace
the presently installed air
cooled compressors
with modern water-cooled
compressors will
be accomplished
in phases,
since the air system is always
required
when either or both nuclear units are in operation.
The anticipated
completion date for the replacement of
compressors
05 and 06 is early 1991.
Procedural
changes
have
been
implemented for system operating
procedure
OPK-1, Compressed Air System,
Revision 4.
The
changes
were
needed to meet the
demands
of the air system
under the temporary configuration necessary
to accomplish
the
installation of the
new compressors.
Air system leaks at
DCPP have
been
a problem,
and
seem to be
more prevalent
than in other U.S. plants.
A number of action
requests
{ARs) from the second six months of 1989, involving
24
"
C
compressed air system leaks,
were .reviewed
and, discussed. with
the system engineer
and the system design engineer.
Implemer>-
tation of corrective action specified
on these
AR's was found
to be timely except for leaks requiring repair during
a 'system
outage..
The system engineer for, the compressed air system
was
unable to verify'whether the plant
had
a program:to evaluate
the various root causes
of compressed air system',.leaks
and
implement corrective action in appropriate
cases.
The
reviewed did not request
a quality evaluation
(gE) be
performed.
The compressed air system
has experienced
problems with two of
its monitoring instruments,.the
air flow meter
and the
moisture analyzer.
ARs have
been written for each instrument;
however,
progress
has
been slow in resolution of the problems.
In discussions
with the systems, engineer,
he indicated that
final resolution of system
problems is often sought prior to
testing of the complete
system.
Based
on review of the proposed
and completed modifications to
the compressed
air systems
at
DCPP, including walkdowns
.of
selected
portions of the system
and interviews with the system
engineers,
the inspection,team's
conclusion
was that the
licensee
has
taken appropriate
measures
to enhance
the
reliability and maintainability of the system.
The team's
review included interviews
and discussions
with the system
engineer
and the system design engineer
assigned
to the
compressed air system.
Both engineers
were found to be
aggressively
following system operation
and modifications,
and
they were found to be technically competent
in their areas
of
responsibility.
5.
S stem
En ineer
Pro
ram
PGSE issued letter No. DCL-89-206, dated August 4,
1989 in response
to
NRC Enforcement Action No. 89-85.
As part of the actions
accomplished
by the licensee
in response
to the
NRC concerns
which prompted the
enforcement letter, the licensee's
response
discussed
implementation of
a plant System Engineer
(SE) Program,
increased
involvement of Nuclear
Engineering
and Construction Services
(NECS) engineers
in plant
operations,
and actions to strengthen
the interface
between
NECS System
Design Engineers
(SDEs)
and the plant staff.
Specific reference
was
made to "... the emphasis
placed
on coordination of design
and
operations activities between
the plant System Engineers
and
NECS System
Design Engineers."
One of the inspection
team's objectives during this inspection
w'as to
assess
the effectiveness
of the
SE and
DSE programs
and their working
relationships.
This was accomplished
through interviews, review of
governing procedures,
examination of quarterly system status
reports,
and interface with SEs
and (in some cases)
DSEs
as part of the system
reviews discussed
in paragraph
4.
~
'
25
The team's
observations
and findings regarding the System
Engimeer
and
Design System Engineer
proarams
are discussed
in the following
paragraphs.
A
'
a.
Plant
S stem
En ineers
The plant System
Engineer'-Program
was defined in 'Administrative
Procedure
(AP) A-350, System Engineering
Program, Revision 1.
This
procedure
appeared
to have
been generally effective in establishing
the program, but provided insufficient guidance
in some areas.
For
example:
Vhile minimum initial quali'fications were established for
assignment
of an individual as System Engineer,
no specific
training requirements
were identified as prerequisite to
assignment.
AP A-350 indicated...that
"the concept of
on-the-job training is the core of the qualification and
training program."
The
AP also stated that within two years
of initial assignment,
the System
Engineer
should
be assigned
to participate
in the Technical Staff Training Program.
Successful
completion of this program
was stated to be
a
prerequisite
to continued
assignment
as
a System Engineer.
Paragraph
4. 1.10 of AP A-350 stated that the System Engineer
"... should provide
a Readiness
For Restart Evaluation for
his/her system
when requested
or following significant outages
However, the
AP did not indicate
how or to whom this
report should
be provided.
Requests
for documentation
(e.g.,
compressed air system)
and discussions
with System Engineers
indicated that this was not routinely accomplished.
During
discussion
of this question,
Technical
Services
management
stated that System Engineers
do not report accomplishment of
this task to anyone -- they just do it.
Nuclear Plant Administrative Procedure
C-26, Root Cause
Analysis, Revision
0 (in Step 5.2.1) stated that the System
Engineer should perform an investigation of events for root
cause.
AP A-350 did not indicate this or state that the
System Engineer would be assigned
to the root cause investi-
gating team.
However, discussion with System Engineers
indicated that they have actively participated in the
investigation of events
and problems associated
with their
assigned
systems.
AP A-350 did not provide sufficient guidance
on the conduct
'nd
documentation of quarterly system walkdowns; e.g.,
the
type of information which should
be included in the quarterly
reports.
As
a result,
some of the quarterly system status
reports
were more complete
than others,
and
some did not
appear
to provide
a complete
and accurate
status of the
system.
For example,
the compressed air system 3rd and 4th
quarter reports did not provide estimates
of when requested
~
'
.work. on design
changes. would 'be accomplished
on the .system.
'They did not address
specific";problems
or delays in getting
Casks
accomplished
that may need -management;assistance
or
- attention.
The trending
and recommendations. section of this
report only, stated that system performance
was improving and
.provided ~o basis for'this solution.
The report did not
,provide
a status of design
changes
or modifications in
progress.
The
AP stated that System Engineers
should
do trending of
system
performance,
but-gave little guidance
on what informa-
tion should
be trended,
or how.
Plant management
stated
during discussion of the above
issues
that
a revision to AP A-350 was planned to address
the inspector's
observations
and to incorporate other improvements
based
upon
experience
to date with the System Engineering
Program.
Interviews
and interface with the plant System Engineers
during the
course of the inspection
indicated that most were well qualified,
knowledgeable,
and actively involved in issues
dealing with their
assigned
systems.
Staffing weaknesses still existed in some areas
for example,
the 480/4160
VAC systems
did not have
a System
Engineer assigned,
although
an electrical
maintenance
engineer
was
fulfillingthis function very effectively.
Some
20 System
Engineers
had completed
the 20-week Technical Staff Training
Program, with six to eight more scheduled
to participate in the
next course to be given this year.
This course
includes
approximately
10 weeks
devoted to study of various plant systems,
and also includes
80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br />
on the plant simulator.
The plant systems
engineering
supervisor
was developing
an intro-
ductory training curriculum for new persons
coming into the systems
engineering
program.
This was expected to be completed
by the end
of the second quarter of 1990.
He was also developing qualifica-
tion standards
for each
System Engineer assignment
which were
expected to be completed
by mid-summer
1990.
Initially, when
PGSE
changed
to the System Engineer
program from the surveillance test
(ST) engineer
program,
the test engineers
stayed with the system
they had under the
ST engineer
program.
At the time of this
changeover,
only one
new person
was brought into the System
Engineer
program.
He came from the general office design group.
He had completed the training program which included plant systems
and time on the simulator;
and
he was given on-the-job training for
his system
by his supervisor.
Consequently,
no introductory
program
was provided at that time.
Overall, the team concluded that the System Engineering
Program
was
working reasonably
well at Diablo Canyon,
and was making positive
contributions to improved interface with NECS.
System Engineers
with whom the team interfaced
were generally well qualified.
Some
weaknesses
were noted in the program,
as discussed
above.
~
'
27
Desi
n S stem 'En ineers
~ ~
The 'NECS Design 'Design .Emgineer
program
was addressed
in Engineer-
ing:Procedure'No.
3.14, 'PGIIE System Engineer
Program.
This
provided for a Design System Engineer to be assigned
to principal
plant systems.'ections
3.4 and 4.3 of this procedure,
along with
AP A-350., provided for the plant System Engineer
and the
Design 'System.-Engineer
Co jointly conduct the quarterly system
walkdown and prepare the quarterly System Status
Report which is to
be submitted to the
DCPP Plant Manager.
These
references
also
indicated that the System Engineer
and Design System Engineer are
to consult
as necessary
on issues
involving their assigned
systems.
The team's
review of the Design
System Engineer program, including
interviews
and discussions
with several
persons
involved, indicated
that it was not as fully implemented
as the plant System
Engi'neer
program.
Strengths
were noted in some
areas -- the Design
System
Engineer for the compressed air system, for example,
was very
involved with his System Engineer counterpart in planning signifi-
cant modifications to the plant's
compressed
air system.
Evidence
was observed of meaningful
involvement by Design System
Engineers
in many of the quarterly system walkdowns
and in other issues.
On
the other hand,
weaknesses
in the program were observed
as follows:
As with the plant System Engineers,
specific training require-
ments for Design System Engineers
had not been established.
One electrical
Design System
Engineer
who had
been assigned
for about two months,
although experienced
in the electrical
engineering discipline with PGIIE, had
no prior nuclear
experience.
During an interview,
he stated that
he
had not
received
any training specifically related to his system,
and
was not aware of any training planned for the near future.
He
also stated that while he had met with his plant System
Engineer counterpart,
they had not performed
a joint walkdown
of their assigned
system or formally discussed
the status of
current issues.
This electrical
Design System
Engineer
had
been assigned
for only about
two months,
and
had difficultywalking the
inspector through
a one-line diagram of his system.
Based
on
the inspector's
review of the System Status
Report prepared
for the fourth quarter of 1989, which had
a cover sheet
showing the Design System Engineer's
name, it appeared
that
the Design
System Engineer for this system
had participated
in
the system walkdown and contributed to the report.
During
'iscussions
with the Design System Engineer
(DSE) at the time
of the inspection,
however, it was learned that the
DSE had,
in fact, not participated in the system walkdown or contri-
buted to the report.
The
DSE stated that the cover sheet of
the report was signed for him by the System Engineer without
his specific knowledge or instruction.
During followup dis-
cussions,
the plant System Engineer stated that his signing of
the quarterly cover sheet for the
DSE was
an oversight
on his
part -- in that
he had
been previously responsible for prepar-
0'
'
28
'i~g the quarterly status report, since
a Design System'Engineer
had onlv recently
been assigned.
Some
'NECS design engineering 'groups
used contract engineers
'or
a significant portion of %heir Design System Engineers.
-This was"notably true Sor the electrical distribution group,
although
some of the 'contract engineers
had
been working with
PGIWE for .several
years..
A weakness
noted
was that one contract
engineer
assigned
as
an electrical
DSE did not
know who his
plant SE:counterpart
was.
The licensee
stated that the use of
contract .personnel
was necessary
to staff the group with
qualified engineers
in the time frames established.
The team
noted that for the long term, however,
management
must
consider the balance of contract
and
PGIIE staff personnel
which will give the flexibility needed while ensuring that
corporate
knowledge about important plant systems
is retained.
A check of ten engineers
assigned
to one electrical engineer-
ing group indicated that five did not have
a site badge,
and
that only one. was
badged for protected
area entry.
The
'icensee
noted that badging for some others in this group was
in progress.
Other observations
indicated
a need for some
Design System
Engineers
to work more closely with their System Engineer
counterparts.
For example,
one electrical
DSE did not
know
that
a maintenance
engineer
was acting
as plant System
Engineer for his system.
One
DSE Group Leader also indicated
that
he did not get
a copy of quarterly system status
reports,
although Engineering
procedure
3.14 indicates that
he should
receive
and review
a copy.
c.
Conclusions
Overall, the System'ngineer
and Design
System Engineer
programs
appeared
to have
been established.
The Design
System Engineer
program
was not as fully implemented
as the System Engineer
program.
Both programs
showed
room for additional
improvement in
program definition, establishment
of training,
and the effective-
ness of the interface
between
them.
6.
En ineerin
Activities
A brief review of engineering activities was conducted
to ascertain
the
staffing and workload experienced
by the Nuclear Engineering
and
Con-
struction Services
(NECS) engineering staff.
The organization
had about
1250 open engineering
work items, with the backlog appearing
to be
growing slowly.
NECS management
planning estimates
indicated
a total of
approximately 973,000 engineering
and drafting work-hours, including
design basis
data
update activities.
This estimate
also included all
capital
improvements
authorized for 1990 and
1991 (representing
about
25K of the total), plus existing Operations
and Maintenance
(08M)
engin'eering
support work.
This represented
approximately
one and
one
quarter years of engineering effort for the approximately
400 engineers
20
"
{PGSE and .contractor)
who compr'ise the corporate engineering staff
.available to work on
DCPP,.
NECS management
considered
the engineering
workload <o be under control,
and appeared to have
an effective priori-
tization system.
The team noted that the level of DIEM work appeared to
be growing.slowly, however.
The licensee
was
aware of this
and appeared
committed,to ensuring that the
08M growth remains controlled.
'No violations or deviations
were identified.
7. ~kk
Plant conditions
and material/equipment
storage
were assessed
during the
inspection to determine the general
state of cleanliness
and housekeep-
ing.
During plant tours, inspectors
were alert for debris, potential
hazards, oil and water leakage,
and equipment conditions; e.g.,
bearing
oil levels,
and the configuration
and cleanliness
of electrical
connections.
'During wa1kdowns of selected
areas
in the plant by the various
team
inspectors
the following housekeeping
discrepancies
were identified:
Damaged fire barrier seal
in 4KV vital cable spreading
room (on.
north wall, separating
rooms
"G" and "H").
A piece of foam fire
barrier material
6" x 2" x 1" deep
was missing
on the
H side of the
fire stop, with an ear plug container stuffed into the opening;
on
the
G side,
a cigarette butt (apparently snuffed out in the fire
stop material)
was protruding from the fire stop.
Debris in the bottom of panel
1PM247 (by Unit
1 oil-water separator
room,
85 foot level)
Beverage
can
on top of transformer
"G" and plastic water cup on
floor, Unit
1 480V switchgear
room "G"
Cigarette butt in safety
panel
RNPIC,
Rack No. 3; Unit 2, cable
spreading
room
Masking tape
and cardboard
tag in Unit 2 remote
shutdown
panel
White plastic bottles
and debris
on floor at 85-foot level, Unit 2
containment penetration
area
Black duct tape
and miscellaneous
debris (bolts/nuts)
on floor at
100-foot level, Unit
1 near auxiliary feedwater
(AFW
valves, north
side of containment
Tools,,parts,
and other debris in instrument cabinets Panels
1-PM-82, 2-PM-72, air compressor
control
panel
PM-150 (also
had
broken handle)
Oil and grease
under air compressors
5 and
6
Portable vent fan, air sampler,
and extension
cords (not is use)
near
AFW .valves
on 100 foot level
~
a
30
Buildup. of boric acid crystals
noted in various locations
(packing
on safety injection (5I) pumps
1-1 and 1-2 and several
valves in
area)
Diesel
Generator
(DG) rooms looked poor during the week of January
8, and the inspector informed the Plant
and System Engineers.
The,
rooms were not cleaned
up until the inspector again
commented to
the System Engineer during the week of January
22
Cardboard cartons, etc., stored
on top of computer,
Unit 1 Plant
Computer
Room
The team concluded that housekeeping
was generally poor, considering
that both units
had
been operating routinely since completion of the
Unit I refueling outage
about
two months earlier.
The examples
above
demonstrated
a failure by the licensee
to meet the requirements
of
established
housekeeping
procedures
and were considered
to be
an
apparent violation of 10 CFR Part 50, Appendix B.
(Enforcement
Item
273/90-01-05)
Emer enc
Li htin
62705,
64704
The plant's
examined to assess
its availability
for necessary
response
to emergency conditions.
consists of three
systems:
DC emergency lighting, AC emergency light-
ing, and battery operated lights (BOLs).
The
supplied at
125V from the non-vital station batteries.
It is located
principally in electrical
equipment
rooms, stairways, exits
and
entrances,
corridors,
passageways,
and at lower levels in all other
areas.
The
AC emergency lighting is supplied from two of the three vital 480V
buses
through dry type, single-phase
transformers,
and is limited to 100
KW of power.
It is located throughout the plant to provide minimum
lighting.
Emergency battery operated lights are provided in engineered
safety feature
(ESF) equipment
areas
and various
access
routes thereto.
This lighting system consists of individual battery
power pack lights
capable of providing eight hours of illumination if normal
DC emergency
and
AC emergency lighting is lost.
The battery
power
pack built-in
charger maintains
a continuous
charge
on the battery.
The
AC emergency lighting circuits are routed in separate
conduits
from
the normal
AC lighting on the secondary
transformer sides to panels
and
fixtures.
On the primary side, the
AC power from the vital 480V buses
is run in separate
conduits or in respective vital routes.
The
circuits are in separate
conduits in vital operating
areas of the plant.
The lighting fixture supports for the three
emergency lighting systems
are installed to seismic requirements.
After the diesel
generators
start
and the single-phase
AC emergency
transformers
receive
power, the
DC emergency lights are automatically
turned off.
The average
period of operation of the
DC lights is
15
seconds.
31
'A walkdown of selected
areas
was made to evaluate
%he coverage 'of
- emergency lighting in those
areas
required for remote shutdown'of the
Units.
The walkdown started at the control
room and 'proceeded "to the
access
-route
(main stairway
No.
1) to the following remote
shutdown
areas:
battery switchgear
rooms,
4160Y switchgear
rooms,
480V
- switchgear areas,
remote
shutdown
panel
areas,
and emergency
diesel
'enerator
rooms.
The three plant emergency lighting 'systems
described
.
above were found in all of these areas.
The
DC emergency lighting:
fixtures were identified with a yellow circular label while the
emergency lighting fixtures were identified with a red circular label.
The battery operated lights were readily recognizable.
It was concluded
that the em'ergency lighting coverage
in those
areas
surveyed
was
adequate.
'To evaluate
the licensee's
testing
and ma'intenance
programs for the
three
emergency lighting systems,
the inspector
examined.,the
following
surveillance test
and preventive maintenance
procedures:
STP M-17Bl, Functional Test of Emergency
DC Lighting System (six months
frequency).
STP N-1782, Functional Test of Emergency
DC Lighting System Inside
Containment'during
outage).
STP M-17C1, Functional Test of the Emergency Battery Operated Lighting
(BOL) System (six months frequency).
STP M-17C2, Discharge Test of the Emergency Battery Operating Lighting
(BOL) System (twelve months frequency).
STP H-17C3,
Check of the
Emergency
AC Lighting System for Safe
Shutdown
Route Il'lumination (six months frequency).
HP E-55.5, Maintenance of Battery Pack
Emergency Lights (two months
frequency).
AP C-81, Standard
Plant Prior ity Assignment
Scheme.
The inspector
assessed
the thoroughness
of the above surveillance tests
and preventive maintenance
tasks
and the frequency at which they were
being performed.
This was
done by reviewing the computer readout list-
ing the dates
when the
and
PN tasks
were accomplished
during the
past
two to three years.
Fifteen work orders
under which the above
listed surveillance tests
and preventive maintenance
task were performed
were reviewed.
The inspector concluded that the timeliness
and
thoroughness
of the surveillance tests
and preventive maintenance
tasks
were acceptable.
The inspector
evaluated
the corrective maintenance
(CM) program for
repairing
and returning to service battery operated lighting units by
examining
a sample of twenty action requests
(ARs) which initiated
corrective maintenance for BOLs.
Many of the
ARs resulted
from the
performance of STP M-17C1.
The priorities assigned for completing the
~
'
32
'
work appeared
to conform to administrative procedures
C-81.
Priorities
1 and
2 are normally assigned
to corrective maintenance
for BOLs
required for safe shutdown of %he plant.
These corrective maintenance
jobs were usually completed
in 48 to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
In those
instances
where
maintenance
could not
be performed within,a,reasonable
time, the
BOL was
usually changed
out with a spare
BOL from the warehouse until the
maintenance
was completed.
The corrective maintenance
program for BOLs
appeared
to function as prescribed with the
CH work .orders. being
accomplished
in a timely manner.
The inspector also examined three
ARs which dealt with FSAR reviews
related to Appendix
Based
on the facts that the
emergency lighting systems
at the Diablo Canyon .Plant are well
distributed throughout the plant, overlap
one another,
are periodically
tested
on
a regular bases,
and are maintained in a good operating
condition; it was concluded that the systems
were adequate
to ensure
safe
shutdown of the Units from outside the control
room in the event of
a station blackout.
9.
~Ei
N
On February 2, 1990, the team met with senior licensee
management
(identified in paragraph
1) and other licensee
representatives
(identified in Attachment
A) to discuss
the scope
and findings of the
team inspection which reviewed the corrective actions
program at the
Diablo Canyon plant.
Issues
identified during the inspection
were
discussed
in detail.
During the exit meeting,
licensee
management
representatives
made the following remarks in response
to certain of
the items discussed:
Regarding
the System Engineer
and Design System Engineer
programs,
stated that more
DSE rotations to the site were planned;
and that
additional definition would be provided regarding
SE/DSE qualifica-
tion, training,
and responsibilities.
It was expected that these
would be addressed
by about mid-1990 in revisions to the applicable
procedures.
Regarding followup of open corrective actions, stated that manage-
ment was evaluating the establishment
of a central root cause
and
corrective action group.
Regarding
the discussion of outstanding
engineering
work, agreed
with the inspectors'haracterization
of the workload of open
engineering
items;
and stated that the hiring of additional
engineers
is being evaluated.
The licensee
representatives
did not identify as proprietary any
information reviewed by or discussed
with the inspectors
during the
inspection.
Attachment
A
Additional Personnel
Contacted
During the Inspection
D.
J.
A.
G.
D.
D.
- p
p.
C.
J.
- T
J.
B.
M.
p.
K.
R.
L.
- E
G.
- D
A.
J.
T.
E.
W.
p.
J.
D.
T.
S.
S.
R.
W.
- T
B.
G.
p.
C.
J.
- G
W.
R.
J.
M.
K.
p.
S.
0.
A.
L.
D.
L.
E.
W.
C.
J.
A.
W ~
L.
G.
C.
Aaron
Albers
Al 1 en
Anderson
Bar kley
Bauer
Beckham
Bedesem
Belmont
Benitou
Bennett
Blakely
Bri 1 ey
Burgess
Burgess
K.
M.
A.
G.
E.
D.
Cosgrove
Coville
Davis
deUriarte
Elder
El 1 i s
Emmel
A.
L.
F.
J.
R.
D.
H.
L.
M.
C.
T.
D.
R.
W.
L.
0.
S.
J.
C.
T.
Ewart
Farrer
,
Fetterman
Foat
Fridley
Glynn
Goelzer
Grebel
Gross
Hamby
Hanes
Harbor
Harris
Heggli
Henretty
Hicks
Ivora
Jacobson
Kane
Kao
Chan
B. Clark
D. Cobbs
C. Connell
L. Corsiglia
4
Director,
NPG Power Production
Engineerimg
Maintenance
Foreman,
Mechanical
Machinist
Shift Foreman
Shift Foreman
Senior
Power Production Engineer
Senior Nuclear Generation
Engineer
Power Production Engineer
Control Operator
.
Senior Nuclear Generation
Engineer
Manager,
Maintenance
Senior Nuclear Generation
Engineer
Shift Foreman,
Operations
Supervisor,
Plant Engineering
gA Technical Assistant
Electrical Engineer
Supervisor,
Mechanical
Engineering
Electrical Maintenance
Foreman
Acting Project Manager
Assistant
Group Leader, Electrical Distribution
Systems
guality Control Specialist
Supervisor, Reliability Engineering
Supervisor,
gA Program Auditing
Supervisor
Engineer
Electrician
Mechanical
Engineer
Electrical Helper
Control Operator
System
Engineer
Electrical
Group Supervisor
Electrical Maintenance
Engineer
Manager,
Operations
System Engineer.
Blowdown
System Engineer,
Emergency
Diesel Generators
Regulatory
Complian'ce Supervisor
Senior Electrical Engineer
Machinist
Instrument
and Controls (I
& C) Technician
System Engineer,
Compressed Air System
Supervisor,
Auditing
Senior Engineer,
Technical Auditing
. Auxiliary Operator
Auxiliary Operator,
Operations
gA Engineer
Engineer, Quality Control
Group Support
Technical Assistant,
Operations
Group Leader,
Mechanical
Engineering
Attachment
A -- Additional Persons
Contacted
(continued)
.i
W.
J.
W.
K.
R.
T.
- Pl
B.
J.
T.
A.
J.
D.
R.
C.
B.
D.
T.
G.
H.
- W.
W.
S.
J.
B.
D.
B.
- D
B.
- R.
F.
- M
E.
K.
C.
J.
D.
S.
J.
J.
M.
J. Kelly
C. Kelly
J.
Keyworth
Klaesius
P.
Kohout'.
Lee
E. Leppke
S.
Lew
A. Lowrie
A. Nelson
L. Nicholson
J.
Nystrom
W. Ogden
Ortega
J. Parry
H. Patton
W. Patty
W. Pelliseor
P.
Perez
J. Phillips
T.
Rapp
R.
Ryan
N. Sabharwal
E. Skaggs
D. Smith
Spaulding
Supremo
A. Taggart
Tashiro
G. Todaro
A. Toste
R. Tresler
R; VanDemarr
B. Wallace
E. Weber
A. Wejrowski
M. Welch
M. Wilde
Williamson
D. Woessner
C.
Young
W. Zimmermann
Regulatory
Compliance Engineer
Engineer
Emergency
Planning Supervisor
I 8
C Technician
Emergency Safety Supervisor
Senior Mechanical
Engineer
Engineering
Manager
Director, Nuclear Regulatory Affairs
Auxiliary Operator
System Engineer, Auxiliary Feedwater
System
Nuclear Generation
Engineer
Supervisor,
Electrical Planning
Licensing Technical Specialist
System Engineer,
System Engineer,
Compressed
Air
Manager, Reliability Engineering
Shift Supervisor,
Operations
Senior
Systems
Engineer
Consultant
Work Planning Manager
Onsite Safety Review Group Chairman
Unit
1 .General
Foreman,
Mechanical
Design System Engineer, Air Systems
Senior Engineer,
Operations
Group Leader, Electrical Distribution Systems
Group Leader,
Mechanical
Engineering
Consultant
Director, Quality Support
Electrical Maintenance
Engineer
Security Manager
Foreman,
Operations
Project Engineer
Mechanical
Foreman
OPEG Engineer,
Blowdown
Environmental Qualification Coordinator
Mechanical
Maintenance
Planner
Machinist
Nuclear Generation
Engineer
Consultant
Director, Special
Projects
Director,
Operational
Experience
Assessment
Group
- Attended exit meeting at
DCPP on February 2, 1990.
0*
'i
Attachment-B
Procedures
Reviewed:During .the Inspection
i
2)
3)
4)
5)
6)
7)
8)
9)
10)
Procedure Title
Control of Main Annunciator Problems
Event Investigation
Justification for Continued
Operations
Technical
Review Groups
Root Cause Analysis
Licensee
Event Report Processing
Non-Routine Notification and
Reporting to the Nuclear
Regulatory
Commission
Relationship
Between Plant
Organizations
and General Office
Staff During Normal Operations
Duties
and Responsibilities
of
Duties
and Responsibilities
of
the Shift Technical
Advisor
General Authorities and
Responsibilities
of Nuclear
Plant Operations
'No.
AP C-154
NPAP C-18
NPAP C-22
NPAP C-23
NPAP C-26
NPAP E-11
NPAP C-ll
NPAP A-10
AP A-10
AP A-51
NPAP A-100
Revision
Date
~Rev.
0
1/1/89
Rev.
3
1/13/90
Rev.
1
1/16/89
Rev.
4
11/25/89
Rev.
0
8/19/89
Rev.
7
12/6/89
Rev,
4
ll/13/87
Rev.
5
9/23/89
Rev.
5
9/23/89
Rev.
3
10/07/87
Rev.
11
ll/18/88
12)
Auxiliary Operators
Routine Plant
Equipment Inspections
Dissemination of Operations
Department Policies
AP A-100 S2
Rev.
1
3/5/88
AP A-100 S3
Rev.
0
6/26/87
14)
15)
16)
General Authorities and Responsi-
bilities of the Shift Foreman
Shift Control
Room Manning
Requirements
General Authorities and Responsi-
bilities of the Shift Foreman
NPAP A-102
NPAP A-104
AP A-150
Rev.
6
6/9/88
Rev.
7
10/25/89
Rev.
3
11/15/88
'
Attachment 'B Procedures
Reviewed, (continued)
17)
18)
19)
20)
21)
22)
23)
24)
25)
26)
27)
28)
29)
30)
31)
32)
35)
Procedure Title
Conduct of Plant Equipment Tests
Surveillance
Testing
and Inspection
Bypass of Safety Functions
and
Control of Jumpers
Mechanical
Bypass,
Jumper
and Lifted
Circuit
8 Accountability System
Control of Lifted Circuitry and
Jumpers
During Maintenance
Cl earances
General
Requirements
for Plant
Maintenance
Programs
Plant Equipment Failure Tracking
and -Trending
Maintenance
and Surveillance of
Environmentally gualified Equipment
Determination of Preventive
Maintenance
I 5
C Department
Preventive
Maintenance
Program
Plant Logs
System Engineering
Program
Compressed Air System
Compressed Air System Lineups
Issuance
and Approval of
On-The-Spot
Changes
to Procedures
Procedures
Identification and Evaluation of
Problems
and Non-Conformances
Standard
Plant Priority
Assignment
Scheme
No.
NPAP C-3
AP C-351
NPAP C-4
AP C-4Sl
AP C-4S3
NPAP C-6
NPAP C-40
AP C-40
S2
NPAP C-41
AP C-62
AP C-"450
NPAP E-6
AP A-350
OP K-1
OP K-1.1
AP E-4S4
NPAP E-4
NPAP C-12
SAP C-81
Rev.
13
6/6/89
Rev.
0
3/4/88
Rev.
6
6/18/87
Rev.
3
3/11/86
Rev.
2
7/7/86
Pev.
3
2/2/S9
Rev.
0
9/4/89
Rev.
8
11/28/89
Rev.
3
Rev.
1
7/7/86
6/6/89
Rev.
4
3/17/89
Rev.
5
Rev.
16
8/14/89
12/10/89
Rev.
8
7/26/89
Rev.
19
12/14/89
Rev.
4
10/1 1/88
Revision
Date
Rev.
7
7/7/86
Pev.
11
4/12/S9
Rev.
6
3/6/86
'
Attachment
C
Plant Records
Reviewed
i
To determine if:problems were:being identified and documented,
an extensive
review of active and completed records
was conducted.
This review covered
the following plant records:
Control
room and operations
logs for the period of November
1
thr ough 'Z2,
1989
26 sequentially
issued action requests
(ARs) (on various plant
equipment)
issued during July 1989
24 open
ARs on the compressed
air system
16 closed
ARs on the compressed
air system
10 ARs for auxiliary feedwater
system
12 maintenance
work orders
on recurring tasks
20 surveillance tests
performed
by operations
and maintenance
on
various
components
and systems
5 corrective maintenance
work orders
40 ARs on the
5 emergency diesel
generators
(EDGs)
17 maintenance
history records on'the
6 non-conformance
reports
on the
8 STPs
on the
12 work orders
on the
Partial
review, Safety System Functional Audit and Review
(SSFAR)
system,
including concerns
and
recommenda-
tions identified therein
system status
reports for the compressed air, safety injection,
emergency diesel
generator,
125V DC, and the
480/4160V
AC systems for the last two quarters
numerous
plant drawings
'
j /
~
~
'Attachment
C -- Plant
Records
Reviewed (continued)
7he following records
and reports
were reviewed at the corporate office:
64 quality evaluations audit finding reports
(gE-AFRs) from the
Safety System Functional Audit and Review (SSFAR) of the Vital
,Electrical Distribution System conducted
from Narch
13 through
April 7,, 1989 (including engineering
responses)
18 ARs related to the
125V
DC from January
1989 to January
1990
all
1989 quarterly system status
reports
on the
125V
DC system
2 design
changes
on the compressed
air
system
the President's
Nuclear Advisory Committee
(PNAC) meeting minutes
for 1989
the Western
Region Joint UtilityAudit (WRJUA) team reports for
1988/89
the General
Office Nuclear
Power Review and Audit Committee
(GONPRAC) charter,
procedures,
gA audits,
selected
ARs and meeting
minutes for the past
6 months
Corporate guality Assurance
reports
included;
45 audit reports;
17
gE-AFRs,
17 nonconformances,
and
2 gA quarterly reports
approximately
50 safety review event followers initiated by the
operating experience
assessment
group
82 ARs and
43 gEs
on measuring
and test equipment calibration
41 gE-AFRs,
53 ARs,
1
SSFAR and
3 months of Nuclear Operations
Support
gC engineering internal audits
approximately
50% of 94 gEs
on
PIMS and
20% of 256 1989
ARs related
to 480/4160
VAC systems
The above discussed
reviews of plant and corporate
records did not reveal
any
significant problems
which had not been entered into the
PINS corrective
action system.
~
'