ML16341E709
| ML16341E709 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 06/16/1988 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L, Pulsipher J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E707 | List: |
| References | |
| 50-275-88-11, 50-323-88-10, NUDOCS 8807010434 | |
| Download: ML16341E709 (80) | |
See also: IR 05000275/1988011
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/88-11
and 50-323/88-10
\\
Docket Nos:
50-275
and 50-323
License
Nos:
Licensee:
Pacific Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Diablo Canyon Units 1 and
2
Inspection at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
+84/~I
Inspectors:
L.
M. Padovan,
Resident
Inspector
Date Signed
K.
E. Johnston,
Resident Inspector
~.~~
c
P.
P. Narbut, Senior Resident
Inspec or
J.
C. Pulsipher,
Approved by:
M.
M. Mendonca,
Chief, Reactor Projects
Section
1
Date Signed
wl>~ lzS.
Date Signed
+ yr, /d"I
Date Signed
Date Signed
Summary:
Ins ection from A ril 10 throu
h Ma
28
1988
Re ort Nos.
50-275/88-11
and
~/
Areas Ins ected:
The inspection included routine inspections of plant
operations,
maintenance
and surveillance activities, follow-up of onsite
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
25026,
30702,
30703,
37700,
57050,
57080,
60710,
61726,
62703,
70307,
70313,
71707,
71709,
71710,
71881,
73756,
90712,,92700,
92701,
92702,
93702,
and 94703 were applied during
this inspection.
SS07010434
SS0617
ADOCK 05000275
9
-2-
Results of Ins ection:
Two violations were identified.
The first dealt with ineffective corrective
action in dealing with the loss of system cleanliness
controls
as described
in
paragraph
13. d.
The second violation dealt with mechanics failing to follow
procedures
during maintenance activities
as described
in paragraph
5.a.
An unresolved
item is described
in paragraph
13.c. dealing with the operability
of the Auxiliary Saltwater
(ASW) system during the period of time that the
heat exchanger differential pressure
setpoint
was raised.
An apparent
weakness
is implied by the situation of uncertain
oper ability of
the
ASW system in that it can
be concluded that system design
bases
have not
been successfully
communicated
to plant personnel
and that the result of this
may have led to, or could lead to, plant personnel
making system setpoint
changes
which they do not recognize
as affecting system operability.
An additional inspector
concern raised during this reporting period is the
perceived lack of timely, effective corrective actions in dealing with
situations
in which plant personnel
made errors.
The two examples
discussed
in the report 'are the subject of violations; specifically repeated
cleanliness
problems
and the failure of mechanics
to follow procedures.
In both cases
the
job at hand
was corrected
but plant management
appeared
content to allow the
normal processes
resolve the root cause of the problems.
The normal process
involves
a nonconformance
report and
a technical
review group meeting,
a
process
that can
and does
take months.
The action that appears
to be missing
is an immediate
response
to ensure
other personnel
involved in similar work
are quickly alerted to the errors
made.
During the reporting period there were good examples of individual plant
personnel
who exercised
an inquisitive safety minded approach
to their work.
Specific examples
were the identification of misaligned detectors
in the main
steam line radiation detectors
by an
I8C technician,
the identification of
improper surveillance
schedules
for time response
testing of vital
instrumentation
channels
by an I8C technician,
and identification of the
possibly generic
problem with containment ventilation butterfly valves
identified by engineers
involved in the integrated
leak rate test.
Additionally, the licensee's
actions leading to the discovery of possible
generic
problems with Westinghouse
ARD relays
was noted
as
an example of
thorough root cause
analysis.
DETAILS
1.
Persons
Contacted
"J.
D. Townsend,
Plant Manager
- D. B. Miklush, Acting Assistant Plant Manager,
Plant Superintendent
J.
M. Gisclon, Acting Assistant Plant Manager for Support Services
- C. L. Eldridge, guality Control Manager
K.
C. Doss,
Onsite Safety
Review Group
R.
G. Todaro, Security Supervisor
- T. Bennett, Acting Maintenance
Manager
D. A. Taggert, Director guality Support
~T. J. Martin, Training Manager
W.
G. Crockett, Instrumentation
and Control Maintenance
Manager
J.
V. Boots, Chemistry and Radiation Protection
Manager
L.
F.
Womack, Operations
Manager
~T.
L. Grebel,
Regulatory Compliance Supervisor
- S.
R. Fridley, Senior Operations
Supervisor
R.
S. Weinberg,
News Service Representative
W. T.
Rapp,
Chairman,
Onsite Safety Review Group
M. Tressler,
Project Engineer,
NECS
The inspectors
interviewed several
other licensee
employees
including
shift foreman
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
Denotes
those attending the exit interview on May 27,
1988.
2.
0 erational
Status of Diablo Can
on Units 1 and
2
During the reporting period Unit 1 continued its second refueling outage.
Notable occurrences
included the discovery of fatigue cracking in reactor
coolant
pump lubrication system
components,
some evidence of pressurizer
surge line movement, possible generic problems with Westinghouse
ARD
relays, biological growth in diesel
fuel oil day tanks,
combustible fire
barrier material,
and indications
from the ILRT that 48" butterfly valves
used for containment
purge
and exhaust
may have directionally dependent
leak characteristics.
3.
Unit 2 remaining at power for the reporting period.
0 erational
Safet
Verification
71707
a.
General
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations of those activities
were conducted
on a daily, weekly or monthly basis.
On a daily basis,
the inspectors
observed
control
room activities to
verify compliance with selected
Limiting Conditions for Operations
(LCOs) as prescribed
in, the facility Technical Specifications
(TS).
F
Logs, instrumentation,
recorder traces,
and other operational
records
were examined to obtain information on plant conditions,
and
trends
were reviewed for compliance with regulatory requirements.
Shift turnovers. were observed
on a sample basis to verify that all
pertinent information of plant status
was relayed.
During each
week, the inspectors
toured the accessible
areas of the facility to
observe
the following:
(a)
General plant and equipment conditions.
(b)
Fire hazards
and fire fighting equipment.
(c)
Radiation protection controls.
(d)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(e)
Interiors of electrical
and control panels.
(f)
Implementation of selected
portions of the licensee's
physical
security plan.
(g)
Plant housekeeping
and cleanliness.
(h)
Essential
safety feature
equipment alignment and conditions.
(i)
Storage of pressur ized gas bottles.
The inspectors
talked with operators
in the control
room,
and other
plant personnel.
The discussions
centered
on pertinent topics of
general plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
A
lication of the
ualit
Assurance
Pro
ram to Diesel
Generator
Fuel Oil
Tem orar
Instruction 2515/93
Closed
In January
1980, the Office of Nuclear Reactor Regulatory requested
all licensees
to check their guality Assurance
(gA) programs with
respect to diesel
generator
(DG) fuel oil, and to include
DG fuel
oil in their gA programs or provide justification for not doing so.
The inspector verified that the licensee
has included the
DG fuel
oil system in its gA program.
The quality classification list
specified the
DG fuel oil storage
tanks, transfer strainers,
transfer filters, and transfer
pumps
as "g".
This implies that the
provisions of Appendix 8 to 10 CFR 50 apply.
Section
4 of this report addresses
fuel oil problems
encountered
during this reporting period.
No violations or deviations
were identified.
4.
Onsite Event Follow-u
93702
a
On April 13, 1988, with Unit 1 in a refueling outage
and Unit 2 at
100X power, results of a routine 18 month calibration of main steam
line post accident monitoring radiation monitors required all eight
(four per unit). steam line monitors to be declared
The
GM tube detectors
were found to be positioned in their main steam
line shield casks
such that the detectors
did not fully extend into
the shield aperture
and were only partially sensitive to potential
radiation from the steam lines.
Incorrect detector positioning
occurred during original installation
due to poor installation
instructions
and calibration procedural
errors.
Accordingly, the
monitors were considered to have
been inoperable
since August 1983
for Unit 1 and April 1985 for Unit 2.
However, alternate
proceduralized
methodologies
wer e available to identify and assess
tube ruptures.
Previous identification of this
problem did not occur since radiation monitor surveillance test
procedure
(STP) I-18R2 specified presentation
of the radiation
source at the detector well top, rather than of the detector
cask
aperture
due to the close proximity of the casks to the main steam
lines.
The licensee
indicated the radiation monitor vendor would be
contacted to evaluate
the appropriateness
of reportability under
Part 21.
Further followup of this event will be done during the
review of licensee
event report 50-275/88-11.
b.
On April 16, 1988, Unit 1 experienced
a spurious
containment
ventilation isolation due to a high radiation alarm on radiation
monitors
RM ll, 28,
and 21.
No cause
was determined.
The licensee
made
a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency
10 CFR 50.72 report.
Note:
Licensee
actions to reduce spurious actuations
caused
by radiation monitors
are addressed
in report 50-275/88-13.
C.
On April 19, 1988, Unit 1 experienced
a spurious
containment
ventilation isolation signal
due to a high alarm on RM-12
(containment particulate).
No cause
was determined.
d.
On April 20, 1988, Unit 1 fuel reload
was completed.
On April 22, 1988, for Unit 1, the licensee
determined that
technical specification 3.11.1
had been violated for some period of
time not exceeding
one hour and 10 minutes.
The technical
specification required continuous
sampling of particulate
and iodine
samples of the plant. vent.
This function is usually provided by
radiation monitor RE-24.
Due to planned work on RE-24,
a temporary auxiliary sample
pump had
been properly placed in service prior to securing
RE-24.
During the
ILC work on RE-24, technicians
secured
the temporary
sample
pump,
thereby violating the technical specification.
There
does not appear to be any technical
consequences
to this act.
The unit was in a refueling outage
and local portable air monitoring
equipment
was in place
and monitoring work activities.
Additionally, a vent stack release, if one occurred,
would contain
primarily noble gases
and
a smaller
amount of particulate
and
iodine, if any.
Potential
noble gas release
was monitored during
the entire time by RE-14A and
B and
showed
no release.
Licensee corrective actions will be followed up through
LER 88-12.
On April 23, 1988, Unit 1 experienced
a containment ventilation
isolation due to radiation monitor RM-14A spiking.
No cause
was
determined.
On April 26, 1988,
Regional
management
conducted
an onsite meeting
with licensee
management.
The results
are reported in Inspection
Report 50-275/88-14.
On May 5, 1988, during Unit 1 midloop operation for removal of steam
generator
nozzle
dams,
the licensee
discovered that part of the
reactor vessel
vent arrangement
of the temporary
system,
Reactor
Vessel
Refueling Level Indication Systems
(RVRLIS), had been
removed.
Specifically,
RVRLIS valve 613 had been
removed.
The
licensee
formed an Event Investigation
Team (EIT).
This event
had
no technical
consequence
in that the temporary
system
remained
vented to atmosphere
as it was intended through
a different path.
The error was preliminarily determined to be personnel
error in that
general
construction
personnel
(GC) performed the work without a
clearance.
The activities discussed
in this section involved
apparent
or potential violation of NRC requirements
identified by
the licensee for which appropriate
licensee
actions
were taken or
initiated.
Consistent with Section IV.A of the
NRC Enforcement
Policy, enforcement action
was not initiated by Region
V.
On May 5, 1988, during the performance of a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
load test
on
Unit 1 diesel
generator 1-1, the licensee
determined that fuel oil
filters were being severely clogged by biological growth.
The
condition identified itself as
a load reduction
due to fuel
starvation.
Operators
switched to the other fuel filter and load
was reestablished.
The inspector
reviewed the licensee justification for continued
operation of Unit 2 (Unit 1 was shutdown for refueling) and the
inspector
determined that the licensee's
analysis of this condition
was acceptable..
The inspector also reviewed the licensee's
plan of action to correct
the situation
as well as to prevent recurrence.
Initial licensee
plans included tank cleaning, biocide treatment
and increased
testing.
Follow-up of this item will be accomplished
through the licensee's
event report.
On May 9, 1988, during planned preventative
maintenance
of Unit 1
pump bear ings and their lubrication system,
the
r
\\
licensee
noted several failed bolts,
an extruded gasket
and cracked
parts in the assembly
which provide motive force and directs
lubricant flow for the reactor coolant
pump thrust and radial
bearings.
The problem was first identified in RCP 1-2.
Investigation of the
remaining
pumps, indicates at least
one of the cracking problems
may
be generic since the
same failure to a lesser
degree
was evident.
The broken bolts
and
a second cracking problem may be isolated
due
to improper assembly or may be
a generic vibration problem.
The licensee is continuing investigative actions
and has,
subsequent
to the inspection period,
documented this problem in voluntary LER
50-275/88-15.
The licensee is planning corrective actions for Unit
1.
The licensee
has provided justification for continued operation
of Unit 2 in the
LER and the inspectors
review of the
JCO will be
the subject of regional
correspondence
in conjunction with NRR
review.
The residents
followed licensee
actions closely.
Regional
and
project management
personnel
were in communication with the licensee
on this matter.
Follow-up of this item will be conducted
as part of
normal inspection activities.
On May 10,
1988, the licensee identified the fact that time response
testing for reactor trip and essential
safety feature
instrumentation
had not been conducted in accordance
with the
schedule of frequencies
described
in the technical specifications.
The technical specification require
such instrumentation to be
tested
on
a rotational basis; specifically to be tested
every
"N x
18" months
where
"N" is the number of channels of instrumentation.
The licensee
had not been doing this in all cases
and
had in effect
confused
the number of available channels with the number of
components
(e.g.
and therefore in some
cases
was
testing at lesser
frequency than required.
The licensee
determined that Unit 1, which was shutdown,
was late on
time response
testing for situations
were there were two or less
channels
available.
For Unit 2, the operating plant, the licensee
concluded that
surveillances
were not late for any time response
testing but this
position was predicated
on an assumption that the technical
specification tables (e.g. 3.3.1) did not include any requirement to
test what appear
to be single channel (i.e. N-1) functions every
18
months.
Discussions
of this subject with regional
and headquarter
technical
staff indicated that further review would be required
upon licensee
submittal of an
LER dealing with the subject.
The issue will be
followed up through the
LER process.
On May ll, 1988, during Unit 1 Diesel Generator 1-2's
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run,
the foamed fire barrier material
around its'xhaust
stack began to
burn.
The fire was quickly extinguished
and no diesel
generator
inoperability occurred.
The fire barrier material apparently
broke
down when exposed to the
heat of the exhaust pipe with time and became
a flammable material
itself.
The possible
generic considerations
of this event were
related to the regional fire specialist
who will perform follow-up
of this item.
The licensee
removed the fire barrier material
from the other diesel
generator
locations
and is pursuing
a design
change for permanent
corrective action.
Fire watches
have
been set in the interim.
On May 12, 1988, the licensee
made
a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency
report due
to the Fuel Handling Building ventilation system switching to iodine
removal
mode
due to a radiation monitor (RM-58) spike.
No cause
was
determined for the spike.
On May 13, 1988, the inspector
became
aware of a nonconformance
report written on April 30 which dealt with a cracked stator inboard
clamping ring on the motor of a Containment
Fan Cooler Unit (CFCU)
motor.
The inspector determined that the problem was not similar to
that described
by
NRC Information Notice 87-30 which described
generic cracks in large vertical electric motors in surge ring
brackets.
The responsible
licensee
engineer stated that the
CFCU crack had
been found as part of a visual inspection during a planned
maintenance activity and was not found to be generic
as determined
by the inspection of the other
CFCU motors (inspected to that time).
On May 18, 1988, Unit 1 commenced pressurization for a integrated
leak rate test (ILRT) of the containment.
The conduct of the test
and its results
are discussed
in section
14 of this report.
During the test it was noted the inside containment valves for
containment
purge supply and exhaust
(RCV 11 and
FCV 660) did not
appear to hold pressure.
Subsequent
to the ILRT the licensee
performed
a local leak rate test of the valves
and found them to be
tight.
The anomalous
leak behavior of the valves, i.e.,
directionally dependent
leak characteristics,
caused
the licensee to
declare
the valves inoperable in Units 1 and 2 and to commence
an
investigation.
At the end of this reporting period, although the seal ring of one
valve had been replaced,
the licensee
had not been able to
pressurize
the valve inside containment to the required level.
The
licensee's
Event Investigation
Team was continuing its efforts to
repair the valves.
This matter will be followed closely as part of
the routine inspection
program.
P ~
On May 19, 1988, Unit 2 experienced
a non reportable
event when an
I&C technician attempted to remove the display screen for the plant
computer.
In removing the screen
a short was caused
which resulted
in the loss of one bus of instrument power (PY-24).
This caused
a
number of bistables
to trip, a number of feedwater controls to go to
manual,
rods to step in, and letdown to isolate.
Subsequent
operator action restored
120
VAC power.
Plant parameter
changes
during the event were minimal due to operator actions.
On May 20, 1988, Unit 1 experienced
a pure water spill estimated to
be 500-1000 gallons of water in the 115 foot elevation of the
Auxiliary Building.
The spill was caused
by a failure of the freeze
seal isolating work on a
CVCS valve.
The licensee is investigating
the cause of the freeze
seal failure.
On April 28, 1988, the inspector
became
aware of a revision to a
nonconformance
report
made
on April 13,
1988.
The nonconformance
NCR DCI-87 EM-N121 was originally written on December 2, 1987,
and
dealt with malfunctions of diesel
generator l-l during test.
Specifically the diesel
picked upload but immediately shed
load.
The problem was narrowed to a binding relay (a Westinghouse
ARD
relay).
The relays binding resulted in varying contact resistance
(40-1300
ohms) which affected logic circuits.
Physical
inspection
noted concrete-like
dust in the relays which was attributed
(initially) to original construction dust.
Subsequently
the licensee
removed
some of the faulty relays
and sent
them to the manufacturer,
for analysis.
determined
and stated in a reply dated
March 8, 1988, that the dust
like material
was
due to degraded
solenoid potting material
and that
the relays
had not been supplied
as safety grade material.
A meeting
was held by the inspector with licensee
personnel
on April
28,
1988.
The results of the meeting indicated that 155 such relays
were installed in the plant with 136 of them in the diesel
generators
and the remainder in non-safety related
uses.
Of the 136 relays,
one in each diesel
generator affects
low voltage
logic circuits in which the contact resistance
problem can affect
their operability.
The five relays, that are affected by contact
resistance,
are in circuits used only when the diesel is being
tested for operability, that is, in parallel with offsite power.
In
an emergency situation i. e.
loss of offsite power (when the diesel
generators
are required to load) the
5 relays would not hamper
actual operability.
The remaining
131 relays are in 125 Vdc
circuits in make or break situations that are not affected by the
contact resistance
change.
Of these,
eight are critical relays with
important functions
such
as engine start and water jacket pressure
relays.
As corrective action, the licensee
has replaced all relays in the
diesel
generator with signs of degradation.
The remaining critical
relays will be replaced during the current Unit 1 refueling outage
and the upcoming Unit 2 refueling outage.
On May 3, 1988, the licensee's
corrective actions,
proposed actions
and justification for continued operation
were discussed
with
regional
and
NRR managers,
and were found acceptable.
On May 26, 1988, the licensee
submitted
a voluntary
LER regarding
the degradation
of the relays.
This item will be followed up with
licensee's
LER 50-275/88-09.
s.
Fire in a Unit 2 Auxiliar
Buildin
Rad Maste
Dr er Cabinet
On May 24, 1988 at approximately 2:00 p.m.
a fire was discovered
inside
a rad waste dryer cabinet.
The dryer, located inside
a
ventilated rad waste tent area inside the Unit 2 Auxiliary Building,
'was being used to dry rad waste filters which had apparently
collected
flammable paint chips.
The fire was initially identified by a roving fire watch who
notified the Operations
and Radiation Protection
departments.
A
health physics technician,
wearing
a respirator,
extinguished the
fire by unplugging the heater
element,
dousing the cabinet with
carbon dioxide,
and placing the filters and rags contained in the
cabinet into a bucket of water.
The fire was out within ten minutes
and
an Unusual
Event was not
declared.
The licensee
suspended all rad waste dryer operations.
~
~
~
~
No violations or deviations
were identified.
5.
Maintenance
62703
The inspectors
observed portions of, and reviewed records
on, selected
maintenance activities to assure
compliance with approved procedures,
technical specifications,
and appropriate
industry codes
and standards.
Furthermore,
the inspectors verified maintenance activities were
performed
by qualified personnel,
in accordance
with fire protection
and
housekeeping
controls,
and replacement
parts
were appropriately
certified.
a 0
Safet
In ection
S ectacle
Flan
e
On April 26, 1988, the inspector
observed
maintenance activities to
reverse
the spectacle
on the safety injection relief valves
return line to the pressurizer relief tank (PRT).
The spectacle
flange, consisting of a blind flange and an orifice, had been
installed with the blind flange earlier in the outage to facilitate
the local leak rate testing of containment penetration
71.
The
orifice side
needed to be reinserted to return the line to service
for operations
and safety injection system testing.
The inspector found a number of problems with the maintenance
activity:
o
The work package
in the field included only the odd numbered
pages of Maintenance
Procedure
(MP) M-54.4, the procedure
governing the replacement of spiral
wound gaskets
used in this
The mechanics
were not aware of the fact that half the
procedure
was missing prior to identification by the inspector.
o
The mechanics
were not using the lubricant specified in MP
M-54.4 for the lubrication of bolts.
They were using
Chesterton
instead of Felpro N"5000.
o
The mechanics
were not using the data sheets
included in MP
M-54.4 for recording flange alignment and other important data.
o
The work order was poorly written, in that it did not specify
the use of the data sheets
for
MP M-54.4 and in fact the only
instructions
given for final flange reassembly
were:
"At the
completion of STP,
Mech. Maint. to restore all systems to
operating state,
as required
by engineer
and foreman in
charge."
The problems fall into two categories;
an inadequate
work package,
and mechanics
not following the applicable procedure.
The
work
order was written to cover both the insertion of the blind flange
and the reinsertion of the orifice.
Mhen the package
was reissued
to the field for the reinsertion of the orifice it included only the
above step for the mechanics
to perform which had not been signed
off previously.
The
STP referred to was
STP V-671, the local leak
rate testing of the containment penetration.
The step
does not call
out
MP M-54.4 or its data sheets.
Other steps in the work order,
previously signed off, describe bolt torque
and referred to
M-54.4.
However, those
steps
did not specify that the data sheets
need to be filled out.
Although the inadequate
work package contributed to the problems,
the activity could have
been performed correctly had the mechanics
taken the time to read the package
and have it corrected or
requested
guidance
from their supervisor.
This was not done
and as
a result the wrong lubricant was
used
on the bolts.
The lubricant
used
had not been qualified to be used
on safety related bolting
applications.
Failure to follow MP M-54.4 is an apparent violation
(Enforcement
Item 50-275/88-11-01).
Following identification by the inspector,
the licensee identified a
number of immediate corrective actions:
The bolts were cleaned
and relubricated with Felpro N-5000.
The Maintenance
Manager held a meeting with the maintenance
department to discuss
procedural
compliance,
the need to use
data sheets
included in procedures,
and that only the materials
specified by the procedure
may be used.
The guality Control Manager
gave instructions to the
gC
department
not to approve work orders with instructions
as
general
as "Restore all systems
worked to operating state,
as
required
by engineer or foreman in charge."
10
The licensee
convened
a Technical
Review Group
(TRG) to review the
Nonconformance
Report
(NCR) associated
with this incident.
At the
conclusion of this inspection period %he
TRG had not yet specified
any further corrective actions.
b.
Other Maintenance Activities Observed
The inspectors
observed
and found acceptable
portions of the
following maintenance activities:
o
Auxiliary Salt Water
Pump l-l reinstallation following
overhaul.
o
Unit 1 Auxiliary Building Ventilation System
2A gasket
replacement.
o
Control rod drive mechanism repair activities.
o
Upper internals clearing operations for reassembly.
o
Repairs associated
with reactor coolant
pump lubrication system
cracking.
One violation and
no deviations
were identified.
6.
Survei 1 lance
61726
By direct observation
and record review of selected
surveillance testing,
the inspectors
assured
compliance with TS requirements
and plant
procedures.
The inspectors verified that test equipment
was calibrated,
and acceptance
criteria were met or appropriately dispositioned.
Surveillance activities examined during this period included:
o
Integrated
leak rate testing for Unit 1 containment
described
in
section
14.
o
Surveillance testing of the
ASW/CCW problems identified in section
13. c. of this report.
o
Inservice inspection testing,
section
12. of this report.
o
Surveillance testing of the main steam line radiation monitors
described
in section 4. a. of this report.
o
Diesel fuel oil sampling surveillance
discussed
in section
4. i of
this report.
No violations or deviations
were identified.
7.
En ineerin
Safet
Feature Verification
71710
The inspector walked down accessible
portions of the Units 1 and
2
Auxiliary Saltwater
system including local
and control
room indication
and system breakers.
Findings are discussed
in section 13.c. of this
report.
No violations or deviations
were identified.
8.
Radiolo ical Protection
(71709
The inspectors periodically observed radiological protection practices
to
determine whether the licensee's
program was being implemented in
conformance with facility policies and procedures
and in compliance with
regulatory requirements.
The inspectors verified that health physics
supervisors
and professionals
conducted frequent plant tours to observe
activities in progress
and were generally aware of significant plant
activities, particularly those related to radiological conditions and/or
challenges.
ALARA consideration
was found to be an integral part of each
RWP (Radiation Work Permit).
No violations or deviations
were identified.
9.
Ph sical Securit
71881
Security activities were observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative procedures
including vehicle
and personnel
access
screening,
personnel
badging, site security force manning,
compensatory
measures,
and protected
and vital area integrity.
Exterior lighting was
checked during backshift inspections.
No violations or deviations
were identified.
10.
Licensee
Event
Re ort Follow-u
92700
a.
Status of LERs
Based
on an in-office review, the following LERs were closed out by
the resident inspector:
Unit 1:
87-10, 87-16, 87-19, 87-23, 88-02, 88-03, 88-06,
88-12
Unit 2:
87-04, 87-14, 87-23
The
LERs were reviewed for event description,
root cause,
corrective
actions taken,
generic applicability and timeliness of reporting.
No violations or deviations were identified.
11.
0 en Item Follow-u
92701
a.
C Ins ector Failin
To Perform Ins ection
Enforcement
Item
50-275/88-03-03
Closed)
The inspector
reviewed the licensee's
response
to a Notice of
Violation issued
on March 28,
1988 concerning
a guality Control
0
12
Inspector
who stamped
and initialed his acceptance
of cleanliness
on
his inspection plan without visually inspecting inside the body of
Valve No.
8484B for cleanliness.
The inspector
reviewed the corrective actions taken
and found them
acceptable.
Therefore, this item is closed.
Unauthorized Entr
to the Radiolo ical Controls Area
Enforcement
Item 50-323 88-04-01
Closed
The inspector
reviewed the licensee's
response
to a Notice of
Violation issued
on March 28,
1988 concerning the unauthorized entry
of an individual to the Radiological Controls Area (RCA).
In their
response,
the licensee
stated that the 'individual was counseled
by
his supervisor.
In addition,
a review determined that the existing
RCA postings,
procedures
and training program were adequate.
However, the postings for the
RCA were clarified to more clearly
denote entry and exit points,
and the bar rier support
was improved
to reduce
the amount of sag in the yellow-magenta
rope delineating
the
RCA.
Based
on these actions,
no further actions
were
deemed
necessary.
The inspector
reviewed the actions
taken including the changes
to
the
RCA barrier and found them acceptable.
Therefore, this item is
closed.
Revisions to Procedures
Controllin
Maintenance
Performed
on
Ener ized
E ui ment
Follow-u
Item 50-275/87-04-03.
Closed
In response
to findings in Inspection
Report 50-275/87-04 with
respect to inadvertent control rod withdrawal
due to a
miscommunication
between
I&C and Operations,
the licensee
committed
to revise procedures for control of equipment required to be
energized
during maintenance.
The inspector
reviewed Tagging
Requirement
Procedure
AP C-7S1 which had been revised to require
that information tags placed
on equipment
be documented for
installation and removal.
The inspector also reviewed work orders
for systems
required to be energized
during maintenance
and found
that they required the technician to sign off that the Shift Foreman
had been notified prior to performing the work and following
completion.
In addition, the work orders specified where
information tags
were to be hung and required their removal
following maintenance.
Based
on the above,
Open Item
50-275/87-04-03 is closed.
Protected
Area Escort
Res onsibilit
Enforcement
Item
50-275/87-44-01
Closed
NRC Inspection
Reports 50-275/87-44
and 50-323/87-45 contained
a
violation regarding plant security.
In a March 10, 1988, letter
PG&E addressed
the identified security concerns.
The
inspector
reviewed the licensee's
corrective actions
and determined
them to be acceptable.
Accordingly, this item is considered
closed.
Details pertaining to the corrective actions
are not provided in
13
this report due to the security safeguards
nature of the
information.
e.
Ino erable Unit 1 Rod Position Deviation Monitor
0 en Item
50-275/87-38-02
Closed
Open item 87-38-02 was concerned with root cause
determination of
the "P-250
Rx Alm Axial Flux/Rod Pos" alarm window unexpectedly
clearing during a plant evolution.
As explained in LER 87-19-01,
the cause of the problem was identified to be in a subroutine of the
computer program which controlled alarm functions.
The subroutine
was found to function unpredictably if the rod bank demand values
were initialized improperly.
Corrective actions
were described in
the
LER.
This item is considered
closed.
Entr
into Technical
S ecification
TS 3.0 '
0 en Item
50-275/87-38-03
Closed
This open item was concerned with the root cause
determination of
fuse failures in control rod drives.
As described
in LER
50-275/87-16-01,
fuse failure was attributed to poor solder
connections
at the fuse
end caps.
Corrective actions
were described
in the
LER.
This item is considered
closed.
g.
Di ital Electro-h draulic Control
S stem Malfunction
0 en
Item 50-275/87-04-01
Closed
This open item involved inadvertent disruption of the
DEHC load
control (software)
program during turbine maintenance activities.
As corrective action, the licensee
revised Operating
Procedure
C-3: II "Main Unit Turbine-Startup" to add
a caution that after
an
outage or any major turbine maintenance,
the P-2000 computer
(DEHC)
should
be reprogrammed.
Accordingly, this item is considered
closed.
h.
Manual Valve Maintenance
0 en Item 50-275/87-01-03
Closed
A 1987
NRC team inspection identified manual
valves which had not
been
greased
or maintained
by a preventative
maintenance
(PM)
program.
In discussions
with the team members
licensee
management
indicated the Operations
Department would identify valves
needed to
be operated
during accident
and recovery periods,
and these
valves
would be entered into a
PM program.
The licensee
concluded the
necessary
safety system valves were included in the existing sealed
valve checklists
(Operating
Procedure
K-10 "Systems
Requiring Sealed
Valve Checklist" ).
The inspector verified OP K-10 had been revised
to include stroking and lubrication of all sealed
valves,
once every
18 months.
This item is considered
closed.
No violations or deviations
were identified.
14
Inser vice Ins ection
73051)
Several different methods of nondestructive
examination
were observed
by
the inspectors.
These included liquid penetrant
examination (previously
written up in NRC Inspection
Report 87-42), A-scan ultrasonic examination
and visual examination.
The inspector witnessed ultrasonic examination
of a Unit 1 reactor pressure
vessel
stud.
The required
equipment
and
materials,
specified in licensee
procedure
N-UT-3 "Ultrasonic Examination
of Bolting with Diameter
1 Inches
or Greater,"
were observed
to be in
use,
and the specific area,
location
and extent of the examination
was
clearly defined.
The inspector
observed
personnel
perform
a
qualification test
on a calibration standard
made from a spare
vessel
stud,
and observed ultrasonic equipment calibration.
Transducer size,
frequency,
and type were in accordance
with the procedure,
and reject,
damping
and filter settings
were set at minimum values.
No indications
in the stud examined
were detected.
The inspector also observed
the licensee
perform visual inspection of
support
15-95
on the suction piping to
RHR pump 1-2.
Examination of the
rigid support
and
PSA-10 snubber
was performed in accordance
with ISI
Procedure
VT 3/4-1 "Visual Examination of Component
and Piping Supports".
The as-found condition of the rigid support
and snubber
was acceptable,
however,
procedural
discrepancies
were found.
The "Figure 1" and "Figure
2" labeling
was missing from the drawings of page
12 of revision 4 of the
procedure.
The "Hydraulic Snubbers"
(Figure 1) diagram
on page
12
contained
the statement
"...subtract
the 'Z'imension...from the
measured
position setting."
This statement conflicts with training
provided to the ISI examiners.
The drawing on page
14,
above Table 1,
was not clear to ISI personnel
interviewed
by the inspector.
This
drawing should
be revised for clarity.
Finally, on Attachment 1, page
3
of 3 the "post installation verification of snubber/strut
washer
placement"
contained check-off boxes
such
as "thickness,
O.D. acceptable"
and "remaining gap acceptable"
without the procedure
containing guidance
on how to measure
the parameters
or what criteria was being used.
The
inspector
was informed the post installation verification was not a code
requirement.
The licensee
was
made
aware of the procedural
discrepancies
and plans to correct the procedures.
Code repair activities observed
by the inspector,
were previously
documented
in
NRC Inspection
Report 88-07.
No violations or deviations
were identified.
Inde endent
Ins ection
a.
S stem
En ineerin
5-37700-4
The licensee is in the formative stages
of establishing
a system
engineering function, and
has
conducted
information gathering
meetings with other Region
V utilities.
Discussions
with licensee
management
have not established
a projected completion date for the
establishment
and implementation of this program.
15
b.
Post-tri
Review
Events Evaluation/Root
Cause
Determination
5"92700-5
During the periods January
21-22 and April 20-22,
1988, the above
areas
were examined
by the Senior Reactor Engineer,
RV.
The scope
of findings are discussed
below:
Post-tri
Review - Plant Administrative Procedure
AP A-100 Sl,
Revision 3, dated July 29, 1985,
was examined
and records of
the implementation of this procedure for three reactor trips
were examined.
Discussions relating to AP A-100 Sl and related
plant records
were held with licensee
representatives
and the
NRC Resident Inspectors,
from which the following findings and
observations
resulted:
Administrative Procedure
AP A-100 Sl was judged to be adequate
in terms of the scope of post-trip review, evaluation
and
documentation.
The procedure
provides for review and
evaluation of plant and operator
response
as well as the
authorization of plant restart
(by the Plant Superintendent).
The procedure
includes the requirement that,
under
circumstances
where the cause of a reactor trip is not
adequately
explained or where the Shift Foreman
determines
additional analysis is necessary,
prior to restart the Plant
Staff Review Committee will review the associated
data
and will approve return to power operation.
Discussions
with the Resident Inspection staff revealed
instances
where thoroughness
of post-trip review was lacking in
the implementation of the
AP A-100 Sl.
These instances
are
documented
in recent
NRC Inspection Reports.
The Resident
Inspection staff has also expressed
concern regarding
a formal
process for defining and documenting specific actions required
prior to plant restart.
In response
to the Resident
Inspector's
concerns,
licensee
management
has
implemented
a
program for action plan development
and implementation.
(See
section 16.b of this report for licensee
management
commitments
in this regard).
2)
Events Evaluation
and Root Cause
Determination " In evaluating
the licensee's
programs in these
areas,
the following plant
Quality Assurance
and Administrative Procedures
(APs) were
examined
and discussions
relating thereto were held with
responsible
licensee
representatives.
Findings and
observations
resulting from the examination of procedures
and
discussions
held with licensee
representatives
are discussed
below.
QAP 15.8,
Nonconformances,
Revision dated
March 10,
1988
NPAP C-12/NPG-7. 1, Identification and Resolution of Problems
and Nonconformances,
Revision 13, dated
March 22,
1988
NPAP C-16/NPG-7.4,
Human Performance
Evalution
S stem,
Revision
0, dated
March 3,
1986
NPAP C-18/NPG-7.5,
Events Investi ations,
Revision 0, dated
July 14,
1987
NPAP C-23/NPG-7.6,
Technical
Review Grou s, Revision 0, dated
March 10,
1988
A review of the above procedures,
related plant records,
and
discussions
with responsible
plant managers
and supervisors
resulted in the following observations
and findings:
The licensee
has
implemented
a very effective
Human Performance
Evaluation
System
(HPES) program,
having been
an active
participant in this
INPO program from the time of its
initiation some two years
ago.
This program is intended to
focus
on human factor elements
of plant events,
and is aimed at
surfacing for evaluation
human factors concerns
at a low
threshold,
e. g., "near misses".
The program
has
an outreach
aspect,
wherein employees at the plant are encouraged
by direct
mailings, posters
(with associated
forms to submit written
concerns),
etc. in several
locations within the plant and
corporate offices.
During the year
1987,
a total of 39
HPES
root cause
evaluations
were performed relating to various
operational/maintenance
events.
Approximately 25 of these
were
in support of the dispositioning of Nonconformance
Reports
(NCRs).
The licensees
procedures
require formal root cause
determination for all
NCRs, of which there were approximately
135 during the year 1987.
When an additional approximately
15
HPES evaluations for root cause
determination
are
added to the
number of NCRs,
a total of approximately
150 events
were
subjected to formal root cause
determination in the year 1987.
In discussions
with the
NRC inspector,
the Plant Manager
expressed
his view that the threshold for formal root cause
determination
should be lowered to include
a larger population
of events
beyond those for which an
NCR would be initiated in
accordance
with current administrative procedures.
(See Exit
and Management
Meetings section of this report for licensee
management
commitments in this regard).
Desi
n Verification and Confi uration Control:
The Auxiliar
Saltwater
S stem
5-37700-1
37700-2
The inspector reviewed the Auxiliary Saltwater
(ASW) system with
respect to its design basis
and
how that design is implemented in
the operating plant.
The inspector identified the following
weaknesses:
o
The design basis
assumptions
for the
ASW system
have not been
fully implemented into plant procedures
and alarm setpoints.
17
As a result, plant operations
have
been conducted
outside
design basis
assumptions
requiring a review of the
ASW system's
o
The licensee
did not have
an adequate
program for design
setpoint control.
As a result,
the annunciator setpoint for
the differential pressure
(dP) high alarm across
the tube side
of'he Component Cooling Water
(CCW) heat exchanger
(Hx) was
raised without the appropriate
design basis
review.
These findings are mitigated by the licensee's
current efforts in
Configuration Management.
Although at the time of this report the
licensee's
program was in its development
stages,
the program,
as
described
by the licensee,
would establish
how design requirements
and assumptions
are to be implemented through plant operations,
maintenance,
and surveillance.
In addition, it would establish
procedural
guidance for setpoint control.
S stem Descri tion and Desi
n Basis
The
ASW system is the ultimate heat sink, designed to cool safety
related
loads during normal operations
and following a design basis
accident.
The system consists of two pumps
headered
at their
discharge
located at the intake structure.
They pump ocean water
through two trains of 24" piping,
up 85 feet over a distance of
approximately
1600 feet and through the tubes of the
CCW Hxs.
At
the discharge of the
Hxs the
ASW is discharged at 68 feet above
sea
level
and cascades
to the ocean.
The tube side of the
CCW Hx has
a
differential pressure
transmitter with a high and low annunciation
in the control
room.
The inspector
reviewed
and discussed
the
ASW design with the system
design engineers
at the licensee
s office in San Francisco.
The
licensee
could not provide the original design calculation.
Much of
the original design took place in the late
'60s
and early '70s
when
complete
records
were not kept.
The system
was assembled
around
1973 and tested in 1974 and 1975.
In 1982, during the design
verification program
(DVP), the licensee
performed calculations
based
on as-built conditions to verify the
ASW system could meet its
design basis.
The limiting parameter for the
ASW system
was determined to be
temperature
following a design basis
Loss of Coolant Accident
(LOCA).
The limiting component
was determined to be the centrifugal
charging
pump lube oil coolers which was rated at up to 132 degrees
F for 20 minutes.
It was determined that containment could be kept
below allowed temperature
and pressure limits during a
LOCA with two
of five containment
fan cooler units
(CFCUs).
Licensee calculations
M-305 Revision
3 assumes
the following:
o
An initial ASW temperature
of 64 degrees
F.
Above 64 degre'es
F
ocean temperature,
the Technical Specifications
require the use
of both Hx.
18
o
A pre-LOCA
CCW temperature
of 80 degrees
F.
This is based
on
the
maximum normal
CCW loads.
o
The use of five CFCUs.
All five CFCUs start
on a Safety
Injection System signal.
Operator action would be required to
shut
down a
CFCU at it's breaker.
o
ASM flow of 10,700
gpm which is ba ed on flow taken from the
manufacturers
pump curve assuming
"mean low-low water" level of
-2.6 .feet mean
sea level
(MSL) and the
Hx tube outlet at
atmospheric
pressure.
o
A fouling factor,
used in the heat transfer coefficient of
0.001.
The
can
the
for
results
concluded that given these conditions,
one train of ASW
remove the post-LOCA hea$
added to the
CCW system without having
CCM outlet exceeding
132
F.
The licensee did not take credit
any operator action.
Desi
n Basis
vs Plant Confi uration and Procedures
The
the
the
inspector
reviewed plant configuration
and procedures
against
above design basis
assumptions.
The following is a summary of
discrepancies
found:
o
The Hx dP HI alarm setpoint
was 167" water whereas
a clean
Hx
dP of 75" water was
assumed
in the design calculations.
The
following section discusses
this finding in more detail.
o
The Inlet bay low level alarm was set at -10'SL whereas
a
level of -2.6'as
assumed
in the design calculations.
The
effect of a lower inlet bay level would be to lower suction
head
and consequently
discharge
head resulting in less flow.
o
ASME Code Section
XI allows
pump performance to drop to lOX of
its reference
whereas
the design calculations
took pump
performance
from the
pump curve without allowing for
degradation.
o
The
CCW Hx shell side outlet temperature
high alarm setpoint
was set at 120 degrees
whereas
the highest
normal operating
temperature
was
assumed
to be 80 degrees.
If during normal
operations
CCW temperature
rose
above
80 degrees,
the unit
would be operating outside design assumptions.
o
Plant Procedures
address
actions to be taken if both
ASW pumps
fail (cross-tie with other unit) and if CCW pumps fail (reduce
system heat loads
such that
CCW temperature
is less than
95
degrees)
but not actions to be taken if one
ASW train does not
provide sufficient cooling.
0
o
Plant procedures
did not specifically state that operators
could remove from service
CFCUs during a
LOCA to remove heat
loads
from the
CCW system.
o
Annunciator Response
Procedure
PK-0101 in step
7a.
allows
operators
to throttle the
CCW Hx tube side outlet valve if ASW
pump
dP is less that the Section XI limit.
The procedure
did
not have operations notify engineering to evaluate
the
operability of the pump.
The first three findings listed raised questions
of the
ASW system's
ability to perform its function under conditions less conservative
than
assumed
in its design basis calculations.
The inspector discussed
these findings with the Project Engineer for
Diablo Canyon
who committed to provide
a written analysis of ASW
system operability to the
NRC by June 7, 1988.
Pending
a review of
the analysis this item is Unresolved
(Open Item 50-275/88-11-02).
These findings also
show that many design
assumptions
were not
incorporated into plant operations.
As corrective action for the
ASW system,
the licensee
plans to establish
what design assumptions
need to be implemented
and revise procedures,
alarm setpoints,
instrumentation
and documentation
as necessary.
To address
these
concerns
on a larger scale,
the licensee
had initiated a
Configuration Management
program in November 1987.
As described
by
the licensee,
this program would address
the issue of design basis
implementation in plant operations.
Although the significance of
these findings as related to general
design basis
understanding
and
implementation is mitigated by the Configuration Management
Program,
continued attention
needs to be focused
on this issue.
Set oint Control
The inspector
investigated
the basis for the annunciator
setpoint
for dP across
the
CCW Hx tubes,
pressure
switches
PS 45 and 46.
It
was determined that the setpoint of 167" of water had been
established
in March 1987 following a design
change to install
pressure
transmitters
and switches with a higher range.
The design
change
had been initiated in 1985 by the operations
department
since
Hx fouling dP across
the
Hxs was routinely above the existing
setpoint of 110" during normal operations.
The engineering
reviewers of the design
change erroneously
determined that the
change did not affect equipment important to safety or equipment
important to environmental quality.
In the general
notes contained
in the design
change
package Project Engineering
author ized
Operations to revise the setpoints for PS 45 and 46 but did not give
them specific guidance
except to state that Operations
should follow
up by revising drawing 101938 (Non-Safety Instrument Setpoints) with
a field change.
Operations
revised the setpoint
from 110" to 167" basing the
revision
on a calculation of only one limiting condition; the
maximum flow velocity through the tubes.
The flow velocity
0
20
according to the vendor should
be kept below 7 feet per second;
167"
correlates
to 6.8 fps.
Upon subsequent
investigation,
the inspector
found that safety
related
Drawing Nos.
060836 (for Unit 1) and 061236 (for Unit 2),
"Instrument Setpoint Requirements"
Table II lists the high alarm
setpoint for PS 45 and 46 to be 4 psid which corresponds
to 110.7".
The cover note to the drawing states
"Table II of this drawing lists
other non-instrument
Class
1A setpoints
which engineering
has
determined to be appropriate to meet various
FSAR commitments."
This design drawing was not reviewed or changed
when the setpoints
of PS 45 and 46 where changed.
This is a failure of Engineering not
to reevaluate
the basis for the original setpoint
and is an apparent
violation of Criterion III, "Design Control," of 10 CFR 50 Appendix
8 but will be treated
as unresolved until the significance of the
ASW/CCW systems
operating with a 167" differential pressure
setpoint
is resolved.
Following the meeting of the Technical
Review Group
for the
ASW system
Non Conformance
Report,
Operations
put an
administrative limit on
CCW Hx tube side
dP of 110" pending the
resolution of the basis for the 110" setpoint.
Subsequently, it was
determined that the
dP setpoints
in Drawing Nos.
060836
and 061236
to control the low alarm setpoint satisfied the
FSAR commitment for
a control
room alarm on
ASW piping failure.
Regardless,
system
performance is directly effected
by Hx fouling and requires setpoint
control.
The licensee
was in the final stages
of a comprehensive
revision to the setpoint control program at the time of this
finding.
These revisions
appear
adequate
to ensure that important
setpoints
are reviewed against the design basis.
Cleanliness
Control Problems
5-92700-4
In previous resident inspector report (Inspection Report
50-275/88-07),
two cleanliness
problems
were identified during the
performance of refueling outage work.
The two areas
examined
previously were the removal of thermocouple
connoseals
on March 21
and spare control rod drive mechanism
work on the removal of the
reactor vessel
head
on April 6, 1988.
During this reporting period the control of cleanliness
problems
continued.
On April 9, 1988, quality control
(gC) personnel
issued
a stop work on
CRDM cleanliness
requirements.
The stop work was
lifted later that day after corrective action was taken.
The action
consisted of erecting barriers
around the refueling cavity that were
shown later to be ineffective.
Additionally a memo was issued
by
engineering to the engineering task coordinators
regarding
cleanliness
controls.
Subsequent
events
showed that this memorandum
was ineffective in precluding further occurrences.
On April 12, 1988,
gC inspectors identified that cutting fluid and
chips were being allowed to enter crevice areas
on the reactor
vessel
head.
Accordingly, a stop work was issued.
Subsequently,
the licensee
implemented corrective actions.
These corrective
actions consisted of cleaning the crevices
and revising the
procedure for cutting to include
a gC holdpoint to verify barriers
21
were installed.
Corrective actions did not include personnel
reinstruction
even though the procedure
used
had
a specific caution
note requiring steps
be taken to preclude fluids from entering the
crevices.
On April 22, 1988, during the attempt to reinstall the upper
internals,
work was stopped
by the refueling crew due to the
sighting of debris
on the upper internals which was initially
reported
as tools (pliers, nuts,
and washers).
The debris
was
retrieved
and determined to be
a broken "tie wrap" (a plastic strap
ordinarily used to secure electrical
cable to cable trays)
and paint
chips.
The inspector attended
the licensee's
corrective action meeting
on
April 22, l988.
The inspector
entered
containment with the engineer
assigned
the responsibility to determine
the probable
source of the
debris
on the upper internals.
The engineers
in charge of the job did not "save the evidence"
upon
debris retrieval, but rather
had it placed in radioactive waste.
It
was retrieved
by the licensee
and the inspector
observed that the
tie wrap looked old (yellowing in color as
opposed to new white) and
the paint chips were yellow paint.
The conclusion
drawn was that
the tie wrap probably
came from the reactor vessel
head
and its
cable trays.
The inspector
then examined the work area
on top of
the reactor vessel
head
and noted several
unsatisfactory
conditions.
The removed
head
was stored
immediately adjacent to the, refueling
cavity; most of the components
on the
head
do not hang over the
cavity, but a portion of the cable tray area
does
hang over the
pool.
The tie wrap found on the internals
was directly under the
head area cable tray.
The inspector
found additional
broken tie
wraps in the cable tray area which had the potential to fall.
Additionally, on the upper area of the head
(where work had been
underway to remove
and replace digital rod position indicator (DRPI)
stacks for CROM weld repair access)
the inspector
found a great deal
of dirt (up to 1/4" thick) including broken microphone
ceramics
abandoned
in place since pre-operational
testing.
The engineer in
charge of that work explained that prior to removing any
DRPI coils,
the local area
around the
DRPI coil was vacuumed,
and that any dirt
dislodged would fall straight
down and not into the refueling
cavity.
However,
he further explained that one of the interlocking
steel plates in .that
same area
had been inadvertently kicked, fell,
bounced off a structure,
and ended
up in the refueling cavity pool,
and was yet to be retrieved.
Therefore,
the logic that dirt and
debris would only fall straight
down appeared
to be faulted.
The inspector discussed
the cleanliness
situation with the engineers
in containment
and with the outage
manager that evening.
All areas
were recleaned
and verified clean, prior to recommencing reactor
assembly.
22
On May 10, 1988, licensee
personnel
identified cleanliness
control
deficiencies in the Unit 1 Spent
Fuel
Pool including an incomplete
tool log.
Corrective actions consisted of completing the tool log.
Cleanliness
control problems
were identified by the
NRC from March
21 to April 22, 1988.
Additionally, gC personnel
issued
two stop
works on the
same subject
and licensee identification of problems
continue.
The licensee's
actions
up to the point of'he inspectors
involvement
were ineffective in that they did not identify additional debris
on
the reactor vessel
head which could be easily dislodged
and find its
way into the refueling cavity and possibly reactor vessel.
This is
a significant condition,
because
debris in the refueling cavity or
reactor vessel
could impact reactor operations
and fuel conditions.
This was true despite
memorandums
of instruction by the engineering
manager
and increased
gC surveillance.
The failure to take timely
effective corrective action to preclude
recurrences
of cleanliness
deficiencies
is an apparent violation of 10 CFR 50 Appendix
B
criterion XVI (Item 50-275/88-11-03).
e.
Pressurizer
Sur
e Line Movement
Trojan Nuclear Power Plant,
located in Region V, has experienced
movement of the pressurizer
surge line possibly
due to thermal
stratification.
The resident inspector contacted
the responsible
engineer at Diablo
Canyon to determine if evidence of movement or lack of it was
available for Diablo Canyon.
The licensee
had taken measurements
of
the pressurizer
surge line in Unit 1 relative to structure in 1983,
1986,
and during the current refueling outage.
Review of the
measurements
showed essentially
no movement of the pressurizer
surge
line relative to structure.
At the close of the inspection report
period the licensee
indicated that
some evidence
such
as pipe
burnishing indicated that in the hot condition the pressurizer
surge
line may be contacting pipe whip restraints.
The licensee
was
analyzing the findings, considering the addition of inservice
instrumentation to detect thermal stratification,
and planned to
pursue resolution with Westinghouse.
The licensee's
resolution will
be followed as
open item 50-275/88-11-04).
One violations and
no deviations
were identified
14.
Containment Inte rated
Leak Rate Test
70307
and 70313
a 0
Procedure
Review
The inspector
reviewed the Unit 1 and
2 ILRT procedures
as described
in the licensee's
Surveillance Test Procedure
STP M-7, Revision
7 of
May 5, 1988,
(and the Temporary
Change Notices issued during this
inspection) entitled,
"Containment Integrated
Leakage
Rate Test
ILRT), Type A."
This review was to ascertain
compliance with plant
23
Technical Specifications,
regulatory requirements,
and applicable
industrial standards
as stated in the following documents:
o
Diablo Canyon
Power Plant, Units 1 and 2, Updated Final Safety
Analysis Report
(FSAR), Sections
3.8. 1. 7. 2, 3. 8. 1. 7,4,
and
6. 2. 1.4.
o
Diablo Canyon
Power Plant, Units 1 and 2, Technical
Specifications,
Section 3/4.6. 1.2, "Containment Leakage",
and
3/4.6.1.6,
"Containment Structural Integrity."
o
Appendix J to 10 CFR 50, "Primary Reactor
Containment
Leakage
Testing for Mater Cooled
Power Reactors."
o
American National Standard,
"Leakage-Rate
Testing of
Containment Structures for Nuclear Reactors,"
o
Topical Report BN-TOP-1, Revision 1, "Testing Criteria for
Integrated
Leakage
Rate Testing of Primary Containment
Structures for Nuclear
Power Plants,"
Bechtel Corporation,
dated
November 1, 1972.
o
American National Standard,
"Containment
System
Leakage Testing
Requirements,"
ANSI/ANS-56. 8-1981.
o
IE Information Notice No. 85-71,
"Containment Integrated
Leak
Rate Tests."
During this procedure
review, the inspector
made the following
observations:
The procedure
requires
the containment. liner weld channels to be
vented. to the containment
atmosphere
during the test,
as is
required.
The inspector
noted that, at other plants,
these
channels
have not been vented during the test
and additional safety review by
the Office of Nuclear Reactor Regulation
(NRR) has
been required to
resolve this issue.
There is a discrepancy
in the procedure
concerning the test
acceptance
criteria.
Section 5.3.3 of the procedure
states that, in
accordance
with the provisions of BN-TOP-1,
Rev.
1, the end of test
95K upper confidence limit (UCL) for the calculated
leakage rate
shall
be less than
La.
However, in Appendix F; on the "Acceptance
Criteria Check Form-Data Sheet,"
the limit is 0.75 La, rather than
La.
The NRC's position is that the regulation,
Appendix J to 10 CFR 50, requires the acceptance
criterion to be 0.75 La,
as
does the
NRC's Topical Report Evaluation,
dated January
15, 1973, which
accepted
BN-TOP-1.
For the present test,
the acceptance
criterion
of 0.75
La was in fact satisfied.
Nevertheless,
the inspector
informed the licensee that section 5.3.3
was inconsistent with
acceptance
criteria requirements.
Section 5.4 and Appendix
F of the procedure
also specify that, for a
24-hour duration full pressure test according to 10 CFR 50, Appendix
24
J and ANSI N45.4-1972,
the calculated
leakage rate shall
be less
than 0. 75 La.
However, section III.A.3.(c) of Appendix J to 10 CFR 50 requires
the calculated
leakage rgte to be corrected for error.
Although no particular method is generally required,
many licensees
use
a 95K UCL, similar to the BN-TOP-1 procedure,
to account for
error.
For the present test,
the BN-TOP-1 procedure
was used.
The
licensee
has
marked
up the procedure with associated
clarifications
to be included in the next normal revision.
Review of Records
The inspector
reviewed calibration records for the instrumentation
used in the ILRT.
That is, the twenty-four resistance
temperature
detectors
(RTDs), six dew point temperature
sensors
(dew cells),
and
two pressure
used to measure
containment air mass,
and the
flow element
used to measure
the induced leak during the
verification portion of the ILRT.
All instruments
had been
calibrated within the last six months with NBS traceability.
In
situ checking of the instrumentation
had been performed within one
month of the test.
Although the procedure
did not provide instructions for containment
temperature
survey before the test to verify temperature
sensor
locations,
such
a survey was conducted,
as observed
by the inspector
and discussed
in the following section.
The inspector
requested
that the survey results
be included in the licensee's
test report to
the
NRC, which is due within three
months of ILRT completion.
Because
a temperature
survey will probably be performed
on Unit 2 in
preparation for the Unit 2 ILRT planned for Fall 1988, the licensee
should consider developing
a written procedure for this activity.
Observation of Work and Work Activities
Prior to the ILRT, the inspector
observed
a portion of the visual
inspection of the inner surface of the containment,
including the
containment liner.
No evidence of structural deterioration,
apparent
changes
in appearance,
or other abnormal
degradation
were
found.
The inspector
observed
the containment pressurization
equipment,
consisting of eight air compressors,
two after-coolers,
two air
dryers,
and connecting
hoses
and equipment.
During the containment
pressurization
phase,
two of the air compressors
were
out-of-service,
which somewhat
slowed containment pressurization.
Also, during most of the pressurization
phase,
one air dryer failed
to work.
The resulting higher moisture content of the air entering
containment
may have contributed to high relative humidity in the
containment,
which apparently
caused water condensation
on dew cell
No.
2 at the end of the test (during the verification phase).
This
was the apparent
cause of erratic readings
which resulted in removal
of the
dew cell from service.
This is discussed
further below.
The inspector witnessed
a portion of the pre-test
containment
temperature
survey.
Two surveys
were actually performed;
one with
25
the containment
fan cooler units running,
and one without.
This
information gave the licensee
the option to either run or not run
the fan coolers during the ILRT, as the validity of RTD placement
could be confirmed.
During this ILR1, the licensee
chose'to
not run
the fan coolers,
as running then introduces additional
heat sources
or heat sinks (depending
on cooling water flow and temperature)
which are difficult to control.
The licensee
stated that the
temperature
survey did confirm the validity of RTD positioning and
weighting factors.
The inspector requested that the survey data
be
included in the licensee's
report to the
NRC.
The inspector witnessed
selected
portions of the following ILRT
activities listed below and noted the time expended to perform each:
o
Initial pressurization
to 47 psig + 2/-0 psig', approximately
12
hours.
o
ILRT stabilization,
approximately 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
o
ILRT data acquisition.
o
Performance
of ILRT, approximately
42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br />, including a failed
initial test,
as discussed
below.
o
Leak rate verification test stabilization,
approximately
1
hour.
o
Leakage rate verification test,
approximately
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, with an
imposed leak rate of 7.5 standard
cubic feet per minute (SCFM),
which equals
La, which is 0.3X per day.
Various electrical
and mechanical
were inspected.
Because
the typical containment isolation valve was vented
and
drained both inside
and outside containment,
the licensee
was able
to fit balloons over the ends of the vent lines outside containment,
so that balloon inflation would indicate leakage
pasted
the
containment isolation valve seats.
The licensee
checked
these
balloons approximately every two hours during the test, for
excessive
leaks,
but did not find any through the use of this
device.
During the test stabilization period,
RTD No.
21 failed high,
suddenly reading
121 degrees
F where it and other
nearby
RTDs has
been reading in the 60s.
Dew cell
No.
3 exhibited erratic readings
during the
same period.
Both sensors
had their weighting factors
set to zero
and their original weighting factors were reassigned
to
other nearby sensors for the duration of the test.
A few hours after starting the ILRT itself, it became
apparent that
the containment
was leaking excessively.
After about seven hours,
the measured
leakage rate
(Lam) had stabilized at a value of
approximately
0. 118K per day, whereas
the acceptance
criterion, 0.75
La, equaled
0.075K per day (La=0.3X per day).
Licensee
personnel
searched
exhaustively for leaks using soap bubble solution (Snoop)
and other methods.
Eventually they found that at one of the 48-inch
purge line penetrations,
there
was
a pressure
of 47 psig (or current
containment pressure)
between the two. closed isolation valves.
This
indicated that the valve inside containment
(RCV-ll) was either not
closed completely or was leaking very badly.
However, during the
ILRT, the valves
had been locally (type C) leakage rate tested only
a few days earlier
and
had passed that test easily.
The valve
outside
containment
(RCV-12) was found to have significant packing
leakage
and
some seat
leakage.
Another purge isolation valve outside containment
(FCV-661) in a
different penetration
was also found to have significant packing
leakage,
which would indicate
a leaking inside containment isolation
valve on this penetration.
About 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> into the test,
the licensee
opened
a vent valve
(approximately
one inch in diameter)
between
RCV-11 and -12, in an
attempt to depressurize
the space
between
the valves.
After
approximately
15 minutes,
the vent valve was closed
and the attempt
abandoned,
because
the pressure
between the valves
had not decreased
more than
a few psi.
This confirmed that valve RCV-ll was indeed
not limiting leakage
in any substantial
way.
Subsequently,
the licensee
took actions to eliminate or reduce
known
leaks, primarily by tightening
down on valve packing.
When that did
not reduce
leakage sufficiently on valve RCV-12, the licensee
took
the unusual
step of adding
one or more additional packing rings
on
the valve stem and tightened
down on those.
This step nearly
eliminated packing leaks
on valve RCV-12.
When the licensee
took actions to reduce
containment
leakage rate
by
repairing, adjusting,
or altering the containment pressure
boundary,
this caused
the test to be considered
a failure, in accordance
with
section III.A.1.(a) of Appendix J to 10 CFR 50.
In other words, the
containment
was leaking in excess
of the allowable limit, and the
only way to pass
the
test
was to take steps to eliminate leaks.
The licensee's
procedure
STP M-7, Rev.
7, also refers to this
circumstance
as "the initial unacceptable
ILRT," which must then
be
followed by another,
successful
ILRT.
After reducing leaks,
the licensee restarted
the test (or started
a
new test) at 8:44 p.m.
on May 19, 1988, approximately
28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> after
the initial start of the test.
Using the methodology of BN-TOP-l,
the test
was successfully
completed
some
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> later.
There
was
then
some delay in establishing
the superimposed
leakage rate flow
out of the containment for the supplemental
or verification test.
The licensee
has run approximately
200 feet of small-diameter
(0.75
inch) plastic tubing from .a containment penetration to the two
Volumetrics thermal
mass flow meters installed in instrumentation
cabinet in the
DAS (data acquisition system)
shed.
This long,
narrow tubing could only pass
approximately
5 scfm, short of the
needed
7.5 scfm.
Therefore,
the licensee
resorted to a backup
mechanical
rotometer which was placed close to the containment
to allow the needed
flow.
With this delay and the
27
required (by BN-TOP-1) one hour stabilization period, the
verification test
was started at 11:29 a.m.
on May 20, 1988.
During
the verification test,
dew cell
No.
2, exhibited erratic behavior
which was appearing to cause
the test to fail to meet its acceptance
criteria.
Mhen the licensee
zeroed its weighting factor and
reassigned
the original weighting factor to other
dew cells, the
verification test passed.
The inspector
s preliminary conclusion
was that this action was acceptable,
but,
because it took place
after the inspector completed his inspection
and left the site,
NRC
review of the licensee's
justification for zeroing
dew cell
No. 2,
contained in the licensee
s report to the
NRC, will determine the
final acceptability of the action.
The inspector performed
an independent
computer calculation of
leakage
rates to verify that the licensee's
computer program
was
correctly calculating leakage
rates.
The inspector's
calculations
did indeed verify this.
The licensee's
preliminary results for the final 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Type A
test,
which did not include Type
C additions,
was
a total time
calculated
leakage rate of approximately 0.02K per day with 95K
upper confidence limit (UCL) of approximately 0.073K per day.
The
licensee's
maximum allowable leakage rate (0.75La) for this test
was
0.075K per day.
An approximately
8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> verification test
was
performed with an imposed leak rate of approximately 7.5
SCFM or
0.3X per
day of containment air mass.
The licensee
s verification
test produced
a total time calculated
leakage
rate that fell within
the test acceptance
criteria of approximately 0.095 to 0. 145K per
day.
These preliminary results
appear to be within the allowed
acceptance
criteria.
Conclusions
At the exit meeting held on March 20, 1988, the inspector stated
that the failed initial test would require, in accordance
with
section III.A. 6 of Appendix J to 10 CFR 50 and facility Technical Specification 4.6. 1.2.b., that the schedule for subsequent
Type
A
test
be reviewed
and approved
by the
NRC.
If two consecutive
Type
A
test failures should occur,
then
a Type
A test shall
be performed at
each plant refueling outage or every 18 months, whichever occurs
first, until two consecutive
Type A tests
pass,
whereupon the normal
test schedule
may be resumed.
However, the inspector
emphasized
that, in cases (like this test) where failure can be attributed to a
few specific penetrations,
the
NRC encourages
the licensee to
propose,
as
a formal exemption from the regulation,
a corrective
action plan which would address
the problem penetrations
in lieu of
increased
Type
A test frequency.
Such exemptions
are judged
on a
case-by-case
basis
and are not automatic; it is also unlikely that
the licensee
would be relieved from the first test
on the increased
frequency schedule,
and that
a test would likely have to be passed
successfully
before
an exemption would be granted.
28
e.
Subse
uent Information
After depressurizing
the containment, after completing the ILRT, the
licensee
conducted
a Type
C (local
le'akage rate) test
on RCV-11 and
-12, which passed with no repairs or adjustments
to the valves.
The
licensee
has preliminarily determined that RCV-ll (inside
containment)
may have
been installed,
maintained,
and or tested
improperly so that the valve leaks excessively
during an ILRT (and
so would during a LOCA), but not during the Type
C test,
which is
performed by pressurizing
the volume between
the two isolation
valves in the penetration.
Thus, the Type
C test measures
the
leakage rate through RCV-ll in a direction opposite to that which
would occur during
LOCA. It has
been thought that this
"reverse-direction" testing
was equivalent to testing in the
"forward" direction.
The licensee
also found that the inside
containment isolation in the second
purge line, FCV-660,
had the
same potential problem,
as did the congruent valves in Unit 2.
All
four valves were declared
and Technical Specifications
were satisfied.
Followup will be done under routine inspection.
No violations or deviations
were identified.
15.
Examination of Instrumentation
and Controls
I8C
A special
inspection
was conducted to examine the area of instrumentation
and controls.
The inspection
was performed by an
NRC contractor from
EG8G Idaho experienced
in the I8C area.
The results of the examination
are presented
in detail
as
an enclosure to
this report.
Areas for improvement identified by the inspector
and communicated
to the
licensee at an exit interview conducted
on May 19, 1988, included the
following:
The adequacy of procedures
was found to be mixed.
Repetively
performed surveillance test procedures
(STP's)
were generally found
to be detailed
and adequate.
There
was
one notable exception
and
that was
STP I-33B which is performed every refueling outage for
time response
testing.
STP I-33B was poorly prepared
despite
being
in preparation for several
months.
Loop test procedures
were not
addressed
since they were already
an issue which the licensee
has
laid out a plan to correct.
Corrective
and investigative
maintenance
procedures
in the form of work orders
were mixed in
thei~ quality from good to poor.
The licensee
was cautioned to ensure that procedure
review was
enhanced
to ensure
a critical review prior to issuance
and to ensure
a conformance to a uniform standard of detail.
The licensee
stated
that additional personnel
(5) had been hired to achieve procedure
improvements
and that plans were in place for revising writers
guides for future procedures
to satisfy both
NRC and
initiatives in this area.
29
The issue of poor procedures
in the
IBC area
and the untimely
correction of those
problems
has
been the subject of previous
inspections.
The recent licensee action to apply resources
to the problem is
encouraging.
The effectiveness
of and timeliness of the licensee's
future actions will continue to be monitored in future inspections.
16.
Exit
a.
Routine Exit
30703
On May 27, 1988,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph l.
The inspectors
summarized
the scope
and findings of the inspection
as described
in
this report.
b.
Exit and
Mana ement Meetin
s
30702
Additionally, in discussions
with senior plant management
on April
22, 1988, the Plant Manager committed to the following:
1)
An action plan will be developed
by May 6, 1988,
and will
address
the following:
The current practice for the development of event response
action plans,
including schedule for implementation, will
be incorporated
in new or revised plant administrative
procedure(s).
Criteria will be incorporated in revised or new
administrative procedure(s)
to lower the threshold for
events
which will be subjected to formal root cause
determination.
Specific consideration will be given to revising current
guality Control/Administrative Procedures
to require root
cause determination in the dispositioning of guality
Evaluation (gE) reports, of which there were
a total of
approximately
660 in the year 1987.
I&C MAINT NANCF.
VALU TION
OF THE
DIABLO CANYON POWER
PLANT
1. 0
INTRODUCTION
An evaluation of the Diablo Canyon
Power Plant
(DCPP) Instrumentation
and Control
(I&C) Maintenance
Department
was performed during the periods
of March 28 through April 8,
and
May 3 through
May 19,
1988.
The
guidelines
used for this evaluation
were the United States
Nuclear
Regulatory
Commission
(NRC) Inspection
Procedures
52051,
52053,
62704,
and
62705.
Some areas of concern with respect to the preparation
and planning
of procedures
and work orders
were identified.
Three primary areas of I&C maintenance activities were the focus of
this inspection:
I)
Are the
I&C technicians technically competent?
2)
Are the procedures
used
by the
I&C technicians
good
procedures?
3)
Do the technicians follow the procedures?
Another question
was raised during the inspection with regards to
Quality Control
(QC) involvement with the
I&C work activities.
Most of the inspection effort was directed at the
I&C maintenance
groups which dealt with the plant protection
systems
and other systems
important to safety.
Therefore,
the caliber of the technicians
and
quality of the work packages
were expected
to be the best representations
of the
I&C maintenance activities.
2.0
CAPABILITIES OF THE TECHNICIANS
The maintenance
and surveillance activities performed
by the
technicians,
for the most part,
were observed to be done in a satisfactory
manner with the technicians
displaying
an adequate
knowledge of the tasks
required within the work packages.
The technicians
spent time acquainting
themselves
with the proper background material
and systems
information to
gain
an understanding
of the tasks to be performed
and to obtain the
necessary
tools
and test equipment prior to beginning their work
activities.
The efforts of removing the device or system
from service,
0
the corrective maintenance
or surveillance activities,
and the task of
returning the device or system
back in service were all performed in an
acceptable
manner.
A few of the technicians
observed
were outstanding
in the skills they
possessed
or their work habits.
A few others
were observed
as either
somewhat lethargic or almost recklessly fast.
Overall however,
the
technicians
seemed
genuinely interested
in doing
a good job and were
conscientious
and professional
with their work.
No unsatisfactory
work
was observed
due to the skills of the technicians.
3.0
ADE(UACY OF THE PROCEDURES
During this inspection,
28 activities associated
with procedures
were
evaluated.
Nine of the activities were
Loop Tests,
11 of the activities
were Surveillance Tests
(STPs),five of the activities were for Corrective
Maintenance,
and three
procedures
were reviewed
as examples of what
some
I&C personnel
considered
good procedures.
For all but the three
example procedures,
the work activities of the technicians
as well as the
adequacy of the procedures
were evaluated.
No work activities were
observed with respect to the three
example procedures,
only the procedures
themselves
were reviewed.
3.1
Loo
Test Procedures
Since the
Loop Test Procedures
have received previous attention which
has identified them
as being inadequate,
and
a program to update
and
improve the
Loop Tests
has
been initiated, not much emphasis
was placed
on
these
procedures.
The work activities associated
with these
procedures
was the main interest of the
Loop Tests,
and the technicians
were able to
perform the tests
in spite of the poor procedures,
primarily due to their
familiarity with the system.
3.2
Surveillance Test Procedures
The adequacy of the
was found to vary.
Some of the
STPs,
such
as
those
performed
on
a frequent basis,
contain
adequate
detail
and
instructions to efficiently complete the task.
However,
even
personnel
have recognized
a deficiency in the quality of some of the
procedures
and
have
implemented
a program to update
them.
Examples of the
plant awareness
of the inadequacies
of the procedures
are the rewriting of
STP-I-8B for the Reactor Coolant Flow Transmitters
and STP-I-33B for Time
Response
Testing of the Reactor Trip and Engineered
Safety Features
(ESF)
Logic.
The
SB and
33B procedures
required rewriting because
of a lack of
'detail
and were confusing in giving direction to the technicians.
STP-I-8B is being rewritten to consolidate
several
procedures
and
make
the procedure
more concise.
The writing of this procedure is utilizing.
several
concepts,
such
as
human factors,
and will be used
as
a model for
r
procedures
rewritten in the future.
A review of the rough draft of this
procedure
indicates
a positive step toward standardizing
and improving the
procedures.
A considerable
amount of time was spent reviewing STP-I-33B and
observing the technicians activities while working on this task.
Because
this procedure
was
a new procedure
(approved 4/22/88)
and time response
testing of the safety
systems
is important, it was felt that this
procedure
should
be representative
of the type of procedure
DCPP plans to
produce in the future.
However, this
new procedure
(admittedly better
than the old 33B procedure)
had several
deficiencies
and the
I8C personnel
admit that the procedure is not
a good one despite
having spent
seven
months rewriting the procedure.
The most significant problems with the
new 33B procedure
were
a lack
of specifics
and clarity.
The prerequisites
were vague
and incomplete in
describing the equipment
needed
to set
up the test, (i.e.,"5.
Toggle
switch(s)." vs the actual
number of switches required).
The instructions
for setting
up the test equipment
were
so limited that
a technician
performing the test for the first time, probably couldn't set
up the
equipment without assistance.
Even technicians
that
had previously
performed the test
had difficulties and
had to make several
phone calls to
resolve questions.
The procedure
should contain
enough detail that the
technicians
can perform the tasks without requiring prior experience
with
that particular procedure.
An example of how a lack of adequate
research
and
a lack of detail in
the procedures
creates
problems
was observed
during the performance of
Part
10 of the
33B procedure
which measures
the time response for the
Overtemperature
Delta T Reactor Trip.
Initially, the technicians
could
not obtain repeatable
results for this test.
An on-the-spot tailboard
between
a supervising technician
and engineer
determined that the problem
was due to a module failure.
A Work Order was generated
to check the
module
and it was determined that the module
had not failed.
Further
investigation determined
the problem to be incorrect values given in the
procedure for simulating the hot leg and cold leg temperature
inputs.
For
a test
as important
as the safety
system time response
testing,
adequate
research
and systems
knowledge should ensure that the primary system
temperature
parameters
are correctly entered
in the procedure.
The research
required to write a detailed
procedure
might prevent
some
of this type of confusion
and delay.
Also, dry running
a new procedure
can sometimes
help in debugging the document
so that the final result is
a
procedure that is correct
and efficient to use.
The
ILC Manager indicated
that the
IKC policy is currently to dry run
new and revised
procedures
as
much as practicable.
The
I8C Department
agrees
that the
new STP-I-33B procedure
is not
a good model for future procedures
and was not intended to be.
However',
to spend
seven
months rewriting
a procedure that is known to be deficient
appears
Co be self defeating.
This effort indicates either
a lack of
commitment to having good procedures
or an only good enough to get by
approach.
A logical conclusion would be that the procedure
was not given
enough
emphasis
to complete properly and
when it came time to perform the
test,
the procedure
was signed off as good enough
so the task could
proceed.
3.3
Corrective Maintenance
Of the five Corrective Maintenance activities observed,
one of the
Work Orders represented
an excellent effort of planning
and procedural
preparation,
and one of the Work Orders contained
elements
which are
considered
inadequate
and unsatisfactory.
The other three
Work Orders
satisfactorily represent
something
in between
these other two extremes.
The Corrective Maintenance activity associated
with the Unit 2
Pressurizer
Pressure
Transmitter
(PT-474) contained detailed descriptions
not found in most of the other
DCPP maintenance
documents.
Perhaps this
was
due to the high visibility of the consequences
of not performing this
task in
a rigid manner.
However, the tasks
performed, i.e.,
opening
valves, returning to service, etc.,
were explained very explicitly in the
Work Order for this activity.
An example of a Corrective Maintenance
Work Order with virtually no
planning or direction for the technicians
was observed
during the work
performed
on the pressure
switches,
PS-45/PS-46,
for the
CCW Heat
Exchangers.
This Corrective Maintenance
was generated
by Engineering at
the request of Operations
to reduce
the number of nuisance
alarms in the
control
room.
When the request
to perform the work was denied
by
Operations
because it didn't fix their problem,
the engineers
changed
the
Work Order.
The module requiring the correction did not respond
as
expected
and
so another
Work Order was written to "GIVE DIRECTION TO
REPLACE 1PS-46A/46B"
and then the directions
were to
"REPLACE IPS-46A/46B
AS REQUIRED TO
ENSURE
PROPER
LOOP OPERATION."
When the technicians tried
to complete this task,
they discovered that the power supply was
common to
other systems.
The technicians
researched
drawings
and other
documentation
to determine the effects that disturbing the power supply
would have
on other systems
in the plant.
It was determined that the work
could not continue
and was scheduled for a later date.
Operations later
informed the technicians
that the system believed to be affected
was not
in service
anyway,
so the work could have
been
performed at the originally
scheduled
date.
This research
should have
been performed at the planning stage
by an
engineer,
a supervising technician,
or the planner.
The
I&C Technicians,
besides
performing their technical
tasks,
should not be totally
responsible for determining the effects their efforts have
on the overall
plant.
They should
be given direction through the use of detailed,
informative procedures
and work orders.
3.4
Exam le Procedures
The three procedures
reviewed
as examples of what responsible
ISC
personnel felt were good procedures
were maintenance
procedures.
Procedure
I5C MP 4,1-1A for checking the calibration
on an audio
oscillator and power amplifier is an example of an excellent procedure.
This procedure
contains specific prerequisites,
precautions,
and
instructions,
and
was approved
in 1982.
This indicates that the ability
to prepare
good procedures
has
been available at
DCPP in the past.
In
updating the other
ISC procedures,
some of the features of this procedure
should
be considered.
4.0
ADHERENCE TO
PROCEDURES
For most of the
Loop Tests,
STPs,
and Corrective Maintenance
Work
Orders,
the technicians
familiarized themselves
with the tasks to be
performed
and then performed the tasks
per the procedures.
In several
cases
the technicians
appeared
to be
so familiar with the procedure that
it was difficult to determine if the technicians
were actually following
the procedures
or simply filling in the test data.
The only instances
where the technicians
obviously did not follow the
procedures
involved transferring test data from strip chart recorders
to
the data blanks in the procedure.
This occurred during STP-I-338,
where
not only was the data not properly transcribed,
but the strip chart
recordings
were not kept with the work package
where the data could
be
reviewed.
On site follow-up showed this problem to be one of lax follow
through of administrative controls of data, i.e., this problem had
no
technical significance
however.
QUALITY CONTROL INVOLVEMENT WITH IBC WORK ACTIVITIES
While reviewing the
IBC work packages
and observing
I8C technicians
in
the field, an apparent
lack of QC involvement
was noted.
Several of the
IKC technicians
stated that they didn't feel that the
QC personnel
were
qualified to review I8C work anyway.
Therefore,
some time was spent
reviewing the process
by which
QC determines
which jobs are inspected,
and
how many they actually look at.
When the Work Orders
are generated
by the
IEC planners,
a
QC planner
reviews the package
using
a standard checklist.
If the package
contains
the information required
in the checklist then
QC may choose to perform an
inspection or surveillance
on the work activity.
This checklist method
seems to be
a reasonable
attempt at giving all work packages
the
same
level of review and ensuring inspections
are performed
on
a consistent
basis.
E
A computer search
was done to determine
6ow many Work Orders
were
reviewed
and
how many inspections
and surveillances
were performed
on
those
Work Orders.
Data was obtained for the time periods
from
Harch 28,
1988 through April 8,
1988.
and from Hay 2,
1988 through
Hay 13,
1988
During the Harch
28 through April 8 time period,
58 packages
were reviewed with nine inspections
and
10 surveillances
performed.
For
the time period from Hay 2 through
Hay 13,
74 packages
were reviewed with
15 inspections
and five surveillances
performed.
Both of these
samples
indicate that
gC is involved with approximately 30/ of the jobs in the
field.
No attempts
were
made to determine
how intense or effective these
inspections
and surveillances
were,
but it appears
that the
same
amount of
involvement occurred during both time periods.
If inspections
were
required,
then not as
many surveillances
were performed.
When there
were
few inspections,
then more surveillances
were performed.
This amount of involvement
(30%) appears
to be
a reasonable
amount of
review.
6. 0
CONCLUSIONS
The evaluation of the
IKC Haintenance
Department
was performed to
determine if the organization
was operating
in an effective manner
and in
the best
way possible.
The technicians,
both
DCPP and contractors,
performed their tasks with
an average
level of ability and professionalism.
The procedures
used
by the
IEC Haintenance
Department consist of both
good
and
bad procedures.
Some of the
and maintenance
procedures
represent
adequate,
detailed procedures.
However,
some of the
procedures
and
Loop Tests,
and
some of the Work Orders for Corrective
Haintenance,
lack detail
and direction.
Good procedures
and proper
planning
can not only give instructions
and directions for performing
a
task, they can also prevent the work activities from being performed out
of control.
DCPP agrees
that
some of the procedures
require attention
and
have
implemented
several
programs to update
and improve the procedures.
However, there
are
no strong perceptions
that these
pr'ograms
have
a total
commitment
by the plant staff and that the procedures will be updated
in a
timely manner.
The technicians
adequately
followed the procedures,
especially
when
critical functions or sensitive tasks
were being performed.
v
0
APPENDIX A
The following people were the primary contacts while performing this
evaluation.
lk. G. Crockett
C. A. 'Hetter
J. J.
McCann
A. G. Moore
J.
R. Tinlin
l<. L. Brown
D. 0. Malone
L. Kase
J.
Hickman
D.
R.
Geske
R. S. Fairchild
S.
V. Noe
I8C Haintenance
Manager
IKC Maintenance
General
Foreman
Instrument Haintenance
Foreman
Instrument Haintenance
Foreman
Instrument Maintenance
Foreman
Supervising Technician
Compliance
Engineer
I8C Planner
IKC Planner
gC Specialist
QC Specialist
gC Specialist
Other persons
interviewed were the
IKC Maintenance
Technicians
and the
management
personnel
attending
the entrance
and exit meetings.
V
I
APPENDIX B.
or
Order
Unit
~Activit
~Sstem
iR0039357
C0013865
R0005365
R0004749
R0004703
R0004798
RQQ10540
R0022494
R0021550
R0022508
R0020429
2
STP- I-16A
1
Corrective Maintenance
1
STP- I-54
1
STP-I-8B3
1
STP- I-8B3
1
STP- I-8B3
1
STP-I-91B
1
LC-21-13B
1
LT-21-18F
1
LT-21-18G
1
STP- I -6B3
R0021791
-
2
LC-10-4
C0030212
R0024828
'0022327
R0022328
R0022329
R0022295
R0005035
R0005034
R0025281
ROQ10982
2
Corrective Maintenance
1
LCV-110 (3-109)
1
LC-7-221A
1
LC-7-221B
1
LC-7-221C
1
LC-7-221D
1
STP-I-72B
1
STP- I-72B
1
STP-I-72B
1
STP- I-33B1
SSPS
Logic Train
B
PS-46A
CCM
PT-506
Hain Turbine
FT-444
FT-445
FT-446
Thermocouple Monitoring System
LS-207
DG 1-2
TS-96
DG 1-2
TS-97
DG 1-2
PT-474
Pressurizer
FIG-641B
RHR 2-2
PT-474
Pressurizer
PC-86
Aux Feed
TH-411D
Delta T Deviation
TH-421D
Delta T Deviation
TM-431D
Delta T Deviation
TM-441D
Delta T Deviation
ENST-1
Seismic Trip
ENST-2
Seismic Trip
ENST-3 Seismic Trip
Reactor Trip & ESF Logic.
F',
}lork Ord er ..gnit.....~Activit
~Sstem
C0032061
C0032191
C0026709
1
Corrective Haintenance
Support for STP-1-3381
1
Corrective Haintenance
TC-411A
Nodule Check
1
Corrective Maintenance
Lead/Lag Hodules
N/A
N/A
N/A
N/A
IKC MP 4.1-1A
N/A
MP I-2.28-1
N/A
MP I-2.14-2
Test Equipment Calibration
RVRLIS Calibration
r,
~