ML16341E494
| ML16341E494 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/24/1987 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E492 | List: |
| References | |
| 50-275-87-38, 50-323-87-38, NUDOCS 8801130038 | |
| Download: ML16341E494 (76) | |
See also: IR 05000275/1987038
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
. REGION V
Report Nos:
50-275/87-38
and 50-323/87-38
Docket Nos:
50-275
and 50-323
License
Nos:
DPR-80 and
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:
October
4 through
November 14,
1987
Inspectors:
L.
M. Padovan,
Resident
Inspector
K.
E. Johnston,
Resident Inspector
P.
P.
Narbut, Senior Resident
Inspector
Date Signed
r+ vga'7
Date Signed
y wgz y/~p
Date Signed
Approved by:
P?-/z. r/P 7
M.
M. Mendonca,
Chief, Reactor Projects
Section
1 Date Signed
Summary:
Ins ection from October
4 throu
h November
14
1987
Re ort Nos.
50-275/87-38
and 50-323/87-38)
Areas
Ins ected:
The inspection
included routine inspections
of plant
operations,
maintenance
and surveillance activities, follow-up of on-site
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities'nspection
Procedures
25019,
30702,
30703,
50095,
61720,
61726,
62702,
62703,
71707,
71710,
90712,
92701,
92702,
92703,93702,
and 94703 were applied during this inspection.
Results of Ins ection:
One violation was identified regarding insufficient
acceptance criteria
Paragraph
2.b.).
One deviation
was identified regarding
the radiation monitoring system
(Paragraph 9.a.).
DETAILS
1.
Persons
Contacted
- J.
D. Townsend,
Acting Plant Manager
- J.
A. Sexton, Assistant Plant Manager,
Plant Superintendent
J.
M. Gisclon, Acting Assistant Plant Manager for Support Services
C.
L. Eldridge, guality Control Manager
- K. C.
Doss, On-site Safety Review Group
R.
G. Todaro, Security Supervisor
D.
B. Miklush, Maintenance
Manager
D.
A. Taggert, Director guality Support
M. J.
Angus,
Work Planning Manager
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
D.
A. Malone, Senior
I8C Supervisor
"W.
B. McLane, Acting.Assistant Plant Manager/Technical
Services
The inspectors
interviewed several
other licensee
employees
including
shift foremen
(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 December
7, 1987.
2.
0 erational
Safet
Verification
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).
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 pressurized
gas bottles.
The inspectors
talked with operators
in the control
room, and'ther
plant personnel.
The discussions
centered
on pertin'ent topics of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
blhile touring the Unit 1 "pipe racks," the inspector
observed that
a
rope
had been
passed
over a vital electrical conduit to the operator
on a main steam isolation valve.
Apparently, the vital conduit had
been
used
as
a fixed point from which the rope was
used to raise
scaffolding material
from the ground to the pipe rack elevation.
This situation
was discussed
with General
Construction
(GC)
management,
and accordingly,
GC personnel
conducted tailboard
sessions
with all civil craft and discussed
approved rigging
techniques.
An analysis
performed
by Engineering verified no
conduit damage
occurred.
S stem
Leaka
e Detection
S stem
Licensee
TS 3.4.6. 1 "Reactor
Coolant System
Leakage Detection
Systems" lists three
leakage detection
systems that shall
be
operable:
1)
The containment
atmosphere
particulate radioactivity monitoring
system.
This system
employs radiation monitor (RM) 11.
2)
The containment structure
and the reactor cavity sump
level
and flow monitoring system.
3)
Either the containment
fan cooler collection monitoring system
or the containment
atmosphere
gaseous
radioactivity monitoring
system.
RM-12 monitors containment
atmosphere
gaseous
radioactivity.
RM-ll and
RM-12 employ the
same
sample
sump.
The licensee
normally
relies
on RM-11,
RM-12 and the containment
sump to fulfillthe
requirements
of TS 3.4.6. 1.
During a routine control
room
PS
inspection,
the inspector
noted that both RM-ll and
RM-12 were out
of service for sample
pump maintenance
and the operators
were
monitoring containment
fan cooler unit (CFCU) condensation.
Condensation
from each
CFCU collects in individual standpipes.
Each
standpipe
has
a drain valve,
a hi level alarm,
a hi-hi level alarm,
and
a volume of 7 liters.
The inspector
observed
than when the hi-hi level alarm is reached,
the operators
opened
the drain valve and logged the time.
As the
condensation
drained,
the alarms cleared,
and operators
then close
the drain valve.
The inspector
asked the shift foreman if there
existed
any quantitative criteria for evaluating drain valve cycling
frequency.
The shift foreman could not identify a quantitative
criteria,
however
he noted that qualitatively, if a significant
decrease
in the drain valve cycling frequency occurred,
actions
would be taken to identify possible
leakage.
As an example,
at one
point prior to the inspection,
the drain valve cycling frequency
was
at six minutes.
The licensee identified and repaired
a secondary
side leak in containment
and the cycling frequency
was reduced to
sixteen minutes.
The inspector
reviewed the licensee's
FSAR Section 5.2.7.4 which
states:
"The sensitivity and response
time of RCPB (Reactor Coolant
Pressure
Boundary)
leakage detection
systems
vary for different
methods of detection.
However, the diverse
systems
available
have the capability to detect continuous
leakage
rates
as
low
as
1 gpm within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for unidentifiIed leaks
and
10
gpm for
identified leaks,
as required
FSAR Table 5.2-16 indicated that the
CFCU leakage detection
system
can identify RCS leaks of 1 gpm in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
states
that leakage detection
systems
should
be adequate
to detect
a
leakage rate,
or its equivalent,
of 1 gpm in less
than
1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
(Section C.5)
and procedures
for converting various indications to a
common leakage equivalent
should
be available to the operators
(Section C.7).
The inspector
discussed
this issue with the operations
manager.
The
licensee
has
a procedure for the periodic evaluation of RCS leakage
(STP R-10).
STP R-10 provide instructions
and acceptance
criteria
for the surveillance
requirements
related to TS 3.4.6.2 "Operational
Leakage."
Although STP R-10 provides
acceptance
criteria for RM-11,
RM-12, and containment
sump monitoring, it does
not for the
CFCU
monitoring system since it is not specified in the surveillance
requirements
related
to
STP R-10 does provide
some
instruction for the
use of the
CFCU monitoring system,
but none that
would lead to the identification of a 1 gpm leak in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The
surveillance
procedure related to TS 3.4.6. 1 is for the calibration
of the
CFCU monitoring system
and does
not include operational
instructions
and acceptance
criteria.
Following discussions
with
the inspector,
the licensee
committed to include appropriate
instructions
and acceptance
criteria in the
RCS leakage detection
program.
The lack of appropriate
instructions
and acceptance
criteria for the
operation of the
CFCU collection monitoring system is an apparent
violation of the requirements
of 10 CFR Part 50, Appendix B,
Criterion V, which states,
in part, that activities affecting
quality shall
be prescribed
by documented
instructions
which shall
include appropriate quantitative or qualitative acceptance
criteria
(Open Item 50-323/87-38-01).
Residual
Meat Removal
Pum
Test
Gau
es
On October
28, 1987,
on a routine walkdown of the Unit 2 residual
heat
removal
(RHR) system,
the inspector
discovered
what appeared
to
be temporary instrumentation installed
on the suction
and discharge
instrumentation
lines of RHR pumps 2-1 and 2-2.
Two of the
instruments, differential pressure
(DP) gauges,
had tags identifying
installation for startup testing
on April ll, 1985 for RHR 2-1,
and
April 1,
1985 for
RHR pump 2-2.
These
two gauges,
numbers
709.5. 1
and 709.5.2 respectively,
were installed between
taps off the
suction pressure
(PI 631 and PI 632) instrument lines and the
discharge
pressure
transmitter
(PT 635 and
PT 647) instrument lines.
The
RHR pump 2-1
DP gauge
was installed to the instrument lines by
pressure
hoses
and
was supported
by plastic tie wrap to the
structure.
Two temporary suction pressure
on
RHR pump 2-2 were installed
and supported
in the
same
manner.
The
RHR pump 2-2
DP gauge
was
installed directly to and supported
by a 1/4 inch
discharge
instrument line and attached
to the suction instrument line by a
pressure
hose.
The inspector discussed
these findings with the
RHR system engineer
and the engineering
manager.
The gauges
were removed
and the
pump inservice testing procedure,
STP P-38, for which the gauges
are
primarily used,
was revised
on November
12,
1987, to include
direction that test
are to be installed
and
removed for the
test.
However, in review of this item the inspector
addressed
a
number of questions
to the licensee:
1)
Was there
a design
change
package
or any form of procedural
control for the installation of DP gauges
709.5. 1 and 709.5.2
to the
RHR system
instrument lines?
2)
Was there
a design
change
package
or any form of procedural
control for the installation of DPI-635X and
DPR-647X for Unit
1 other than Nuclear Plant Problem Report
(NPPR)
DCI-79-TN-P0106?
The gauges
appear to be permanently
installed,
however the inspector could only identify a NPPR,
which is not a design
document, that refers to the installation
of these
In addition, the Unit 1 design drawing are in
conflict since the
OVIDs indicate installation ~hereas
the
P8IDs
do not.
0
3)
The as
found installation of 709.5. 1 and 709.5.2 raises
a
seismic qualification question.
Could the gauges
have
caused
.
the instrument lines to fail during a seismic event,
and if so
what would have
been the consequences?
4)
What is the appropriate calibration frequency for these
and are they out of calibration if the due date
has expired?
A
review of the calibration records of gauges
709.5. 1 and 709.5.2
shows that their last calibration was performed in October
1985.
The calibration records
indicate the gauges
needed to be
calibrated
by April 1986,
a six month frequency.
The
calibration stickers also indicated that the last calibration
was performed in October 1985, but indicated
a due date of
October 1988,
a three year frequency.
The inspector did not
find any documentation for this discrepancy.
5)
Are there test
installed
on other plant safety related
systems
which have not had the appropriate
design
review?
Finally, on November 18, the inspector
noted that two temporary
were installed
on
RHR pump 2-2.
The inspector brought this
to the attention of the shift foreman
who had the gauges
removed.
The gauges
appear to have
been left following the November
13
performance of STP P-3B.
The revision of the procedure in use
had
a
step to remove temporary test gauges.
This step
was marked "N/A"
for not applicable with a note in the shift foreman's
log that the
Instrumentation
and Control department
had been
requested
to remove
the gauges.
This issue
and the five previous questions
are currently unresolved
(Open Item 50-323/87-38-02).
3.
Onsite
Event Follow-u
a 0
Performance of Maintenance Activities on the Wron
Com onent
On October 8, 1987,
an electrician performed portions of a
preventive maintenance
procedure
on the wrong Unit 1 containment
spray
(CS) system valve.
The electrician
had begun work on valve
CS-1-9001B,
the train
B
CS discharge isolation valve instead of
CS-1-9001A,
the train A discharge isolation valve.
The electrical
breaker for the motor operator
on CS-1-9001A
had been cleared at
5:22 a.m.
and the valve was declared
During the motor
operator termination inspection portion of the maintenance
procedure,
the electrician discovered
a loose termination in the
Limitorque operator
torque switch which could not be tightened.
When
the electrician
informed his foreman,
the foreman realized the
electrician
was
on the wrong valve and reported it to the control
room at ll:30 a.m..
The shift foreman declared
CS train
B
Since the train A valve was inoperable
because
power to
the actuator
was
removed,
the valve actuator
breaker
was racked
back
in.
Train
B was declared
operable at ll:55 a.m..
At 12:05 p.m.,
the licensee
reported to the
NRC operatiqns
center,
in accordance
with 10 CFR 50.72, that both
CS trains were inoperable
between ll:30
a.m.
and ll:55 a.m..
Prior to repairing the loose termination
on CS-1-9001B,
the licensee
performed
an operability check and discovered
the valve to be
In addition the licensee
determined,
through procedure
review and discussions
with the electrician,
the electrician
had not
done anything to the valve that would have rendered it inoperable.
As a result,
the licensee
determined that they had conservatively
declared
CS train
and at 3:34 p.m. called the
NRC
operations
center to rescind
the l2:05 p.m. report.
The electrician stated that
he mentally transposed
valve numbers
prior to working on the CS-1-9001B.
.He had previously consolidated
electrical prints associated
with his work at the electrical
shop,
filled out maintenance
data sheets,
obtained
a clearance,
and
had
hung
a maintenance
reg tag on the correct breaker.
All of these
items referenced
the correct valve identification.
The electrician
indicated that in this case
he failed to double check his
maintenance
work package
against the valve located in the field.
Valve identification was verified by the inspector to be
satisfactory.
However,
CS-1-9001A
and
B are identical valves
located next to each other.
As an immediate corrective action, the operations,
I&C, and
maintenance
departments
issued instructions to their staffs
on the
subject of "wrong unit-itis."
Examples of previous experiences
were
highlighted,
and existing features
(such
as labeling, color coding,
component identification numbers,
work order designations,
and other
work practices)
were reviewed.
In determining root cause of this event,
and in response
to
NRC
Information Notice 87-25 "Potentially Significant Problems
Resulting
form Human Error Involving Wrong Unit, Wrong Train, or Wrong
Component Events," the licensee
appropriately enlarged
the scope of
their review to encompass
previous other wrong unit/wrong component
experiences.
A generic evaluation of these
types of events
experienced
at Diablo Canyon during 1986 and 1987 was undertaken
by
OSRG members.
Eleven events
were evaluated utilizing Human
Performance
Evaluation System
(HPES) techniques.
HPES Report 87-033
was issued
on November 18,
1987.
Six general
causal
categories
were
identified which encompassed
the primary, secondary,
and tertiary
causes
for the subject events.
The primary causal
factor for 9 of
the ll events
was
a lack of an independent/self
verification prior
to the incorrect equipment
being affected.
The recommended
corrective actions
included "1) the inclusion in
work documentation nf a verification requirement to ensure
the
correct unit, and component
are affected;
2) to establish
a plant
policy for a mental self verification to be performed for equipment
not realistically verifiable via the preceding
recommendation;
and
3) periodic training and management
reinforcement of the two
previous
recommendations."
In a discussion
of this subject with the plant manager,
the
'nspector
was informed of additional actions
taken or under
consideration.
These
included:
o
Discussions with other nuclear utilities to determine
how the
generic problem was being addressed
at their facility.
o
Evaluation of color coding of procedures/clearances/work
packages.
o
Investigating the effect of painting floors and railing
different colors in the two units.
Having the worker develop check off sheets for each job
assignment.
The individual at the work station must then
indicate
on the sheets
that
he is at the correct location,
including independent verification and routine changing of the
check off sheets.
0
Use of a contract
human factors specialist.
o
Lower threshold of onsite reporting
and to disseminate
near
miss information rather than reportable
information only.
Follow-up of generic corrective actions
on this subject will be
performed
by the
NRC staff.
(Open Item 50-275/87-38-01).
b.
Unit 1 Containment Ventilation Isolation
At 9:14 a.m.
on October 22,
1987, with Unit 1 at 100 percent
power,
an automatic initiation of the CVI system occurred.
The sample line
isolation valves for containment air radiation monitors
(RMs) Rll
and
R12 closed
as designed.
All other
CVI system valves that
received isolation signals
were already closed
when the event
occurred.
As required by 10 CFR 50.72 (b) (2) (ii), a 4-hour
non-emergency
event report was
made at 9:45 that morning.
This event occurred
when
an Instrumentation
and Controls (I8C)
technician replaced
a blown fuse while troubleshooting
control
room air particulate radiation monitor RM21.
After
replacing
a fuse,
the technician
energized
RM21.
Due to a seized
paper drive motor
o'n
RM21, the fuse blew, resulting in a voltage
spike
and
a CVI.
Operators verified that other containment
parameters
(temperature,
pressure,
sump levels,
area radiation) were
normal,
then reset the
CVI signal, reset the alarm, placed
RMll and
RM12 back in service,
and verified that
a high radiation condition
did not exist.
The licensee's
investigation revealed
the CVI initiation resulted
from noise susceptibility problems of the CVI initiation circuitry.
The source of electrical
noise
was the voltage spike produced
by the
fuse blowing on
RM21.
As corrective action,
the paper drive motor
on
RM21 was replaced.
A design
change
was initiated to add time
delay circuitry 'to radiation monitors RMll, RM12,
RM14A,
RM14B,
'1
0
RM28A, and
RM28B, which have
been
known to cause
CVIs from an
electrical
noise signal.
Once installed, this circuitry should
prevent these radiation monitors from initiating a CVI on a short
burst of electrical
noise,
but will allow them to function on a
valid signal.
Ino erable Unit 1 Rod Position Deviation Monitor
Technical Specification
(TS) surveillance
requirement 4.1.3.1.1
required that full length rod group positions
be verified to be
within group
demand limit at least
once every four hours
when the
rod position deviation monitor
(RPDM) was inoperable.
At 1: 12 a.m.
on October 20, 1987, with Unit 1 at 40 percent
power, the-time
interval requirement specified
by TS 4. 1.3. 1. 1 was exceeded,
including the
25 percent
allowed extension of TS 4.0.2.
The
RPDM
remained
inoperable for 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />
and 40 minutes,
during which time no
verification of rod positions
was logged.
An explanation of the
development of this situation is provided below.
At 8: 12 p.m.
on October 19, 1987, while reducing unit power in order
to clean the condenser,
the plant process
computer
(P-250) failed
and the assistant
control operator
(ACO) "rebooted" the P-250.
After rebooting the P-250,
the
ACO updated
the rod bank positions
for the
RPDM program.
During this update,
he incorrectly transposed
control
rod bank
D position with shutdown
bank
D position.
At approximately 8: 17 p.m.
the control
room received
the "P-250
RX
ALM AXIAL FLUX /
ROD
POS" annunciator
alarm due to the transposed
rod bank positions.
The control operator
(CO) verified the digital
rod position indications
(DRPI) agreed with demand
step counters
and
continued the power reduction.
The P-250 alarm typewriter displayed
a
"ROD BANK SE(UENCE" alarm and the annunciator printer indicated
a
"P-250
COMPUTER
ROD
POS
DEVIATION ALARM."
The
ACO checked
the alarm
typewriter printout but did not notice the transposed
rod bank
positions.
At approximately 8:30 p.m.
on October 19,
1987, the
"P"250
RX ALM AXIAL FLUX /
ROD
POS" alarm window cleared.
When the
alarm cleared,
the operators
concluded that the P-250
RPDM was
At 5:06 a.m.
on October
20,
1987,
a routine test of the
RPDM determined that the
RPDM was inoperable
and that the rod bank
positions
had been erroneously
updated.
The operators correctly
updated
the rod bank positions
and successfully
re-tested
rod
position deviation
and rod bank sequence
alarms.
The incorrect rod bank positions resulted in the rod sequence
alarm
received in the control
room at 8: 17 p.m.
on October 19,
1987.
Once
the P-250 rod supervision
program initiated this alarm, it then
suspended
the
RPDM calculation
(as designed).
The licensee
determined
the root cause of this event
was personal
error in'hat after rebooting the P-250,
the
ACO incorrectly updated
the rod bank positions for the
RPDM program when
he transposed
control rod bank
D position with shutdown
bank
D position.
Additionally, when the
ACO was in the process
of checking for the
cause of the alarm, the alarm cleared
even though the P-250
RPDM was
J.
0
Since there did not appear to be
a problem with the
P-250,
the
ACO suspended
his search for the cause of the alarm.
After further review, the licensee still could not determine
the
cause of the annunciator
window clearing.
Accordingly on October
20, 1987, at about 12:57 p.m. the
RPDM was again declared
pending further investigation
and P-250 test results.
The four hour
rod bank verifications required
by TSs were initiated at that time.
Root cause
determination of the window
clearing is considered
an
followup item.
(Open Item 50-275/87-38-02).
The Operations
Department
issued
an Operations
Summary Report
covering this event.
This summary
emphasized
the need to properly
update the rod position data following the P-250 reboot.
This
summary
was to be reviewed with all operations
personnel.
Unit 1 Fuel Handlin
Buildin Ventilation
S stem
On October 26, 1987, at 2:00 p.m., with Unit 1 at 100 percent
power,
the fuel handling building (FHB) ventilation system shifted into the
iodine removal
mode when
FHB area radiation monitor RE-59 lost
electrical
power.
Power was momentarily interrupted
when General
Construction
(GC) electricians lifted a lead to RE-59 when
installing a design
change
on monitors
RE-32 and RE-33.
This mode transfer constitutes
an actuation of an engineered
safety
feature
(ESF), which was reported to the
NRC at 2:55 p.m..
The
FHB
ventilation system
was shifted back to the normal
mode of operation
at 2:05 p.m..
The licensee's
investigation revealed that
GC electricians
were in
the process
of installing time delay relays in the circuitry to
radiation monitors
RE-32 and RE-33 in accordance
with design
change
notice
(DCN) DCl-EE-33354
RO.
The
DCN specified
AC power was to be
obtained
from an
AC terminal strip at the location where
RE-59
received its
AC power.
Discussions
were held with the responsible
IEC foreman to see if
there would be any adverse effects if the
lifted.
After referring to electrical circui
diagrams
and the
58/59 removal
from service
STP I-119Bl, the foreman determined
no
adverse effects would occur if the channel
was
removed from service.
In accordance
with the STP,
removal
from service
was accomplished
by
jumpering terminals in post accident monitoring panel
2 to prevent
the receipt of "LO" and "HI" radiation alarms in the control
room.
However,
when
a power lead to RE-59 was lifted, the
FHB ventilation
shifted to the iodine removal
mode.
Further investigation revealed
that the jumpers,
which were
installed
as called out in the procedure,
jumpered the
AC power to
the relays
and not the relay contacts,
as
assumed
by the
I8C
foreman.
Accordingly, when the
AC power was lost, the relay
de-energized,
causing the
ESF actuation.
Had the contacts
been
jumpered,
an
ESF actuation
would not have occurred
from lifting the
10
The licensee
determined
the root cause to be personnel
error, in
that the plant I8C foreman reviewing the work instruction for the
design
change did not perform a sufficient enough review of the
circuit diagrams to determine
the effects of using
STP I-1119Bl for
installation of this design
change.
Licensee corrective actions
included:
o
the individual involved in this event
was counseled;
o
lessons
learned
from this event were to be reviewed with all
instrumentation
and controls
foremen through
a tailboard;" and
o
lessons
learned
from this event were to be incorporated into an
instrumentation
and controls technician quarterly training
seminar.
Ino erable
uadrant
Power Tilt Ratio
PTR
Alarm
TS surveillance
requirement 4.2.4.1 required calculation of gPTR
every
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
when the Unit 1 gPTR alarm was inoperable.
At 4:00
p.m.
on October
27,
1987, the
gPTR alarm became
when one
of four nuclear instrumentation
system
(NIS) upper
and lower
detector
current comparators,
that provide input to the alarm,
was
disabled.
These detector
comparators
were disabled for 17.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />,
during which time the
gPTR was not calculated
once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
as
required, by the TS.
At 4:00 p.m.
on October 27, 1987, during calibration of NIS channels
N-41, N-42, N-43,
and N-44,
numerous
power range flux deviation
alarms
were received.
It was determined that NIS
channel
N-44 was causing
the annunciator
alarms since it had not
been calibrated yet.
Because
of the alarms,
the shift foreman
ordered
the upper and lower comparators
for NIS channel
N-44
defeated.
The shift foreman did not realize that defeating
these
comparators
caused
the
gPTR alarm to become
which
required the
gPTR to be calculated
every
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
as specified
by TS
4. 2. 4. l.
On October 28, 1987, the
I&C technician,
who defeated
the
comparators
on October 27, noted the comparators
were still
defeated.
He notified the shift foreman
who, then declared
the
gPTR
alarm inoperable.
At 9:29 a.m.
October 28, 1987,
NIS channel
N-44 comparators
were
reinstated
and Surveillance Test Procedure
(STP)
R-25 "Calculation
of quadrant
Power Tilt Ratio" was successfully
performed.
The licensee's
analysis
determined
the root causes
to be 1)
personnel
error in that the shift foreman
had the compar ators
defeated without realizing that this would make the
gPTR alarm
2) training deficiency in that there
was
a lack of
emphasis
on the specific function of the comparators
channel
defeat
11
switch's relation to TS 4.2.4.1,
and 3) labeling on the switch was
misleading
and did not specify gPTR.
The following corrective actions
were taken
by the licensee:
o
The comparators
channel
defeat switches for Units 1 and
2 and
the simulator were relabeled to indicate that operation of this
switch defeats
the
gPTR alarm.
o
The annunciator
alarm windows will be relabeled
from "PWR
RNG
FLUX DEVIATION" to a legend that indicates
a gPTR alarm.
o
The Operations
Department will write an Operations
Incident
Summary report which will be reviewed with all operations
personnel.
o
The Operations
Department will institute
a policy that requires
logging instrumentation into a log when
no applicable procedure
is available to record the defeat of the instrument.
Entr
Into Technical
S ecification
TS
3'.3 - More Than
One Shut-
down Bank Control
Rod Not Full
Withdrawn
On October
S,
1987, at 4:05 p.m. with Unit 1 at 100 percent
power,
a
slow plant shutdown
was initiated in accordance
with TS 3.0.3 when
four shutdown
bank control rods,
which had been inserted
one step,
were not able to be fully withdrawn within one hour as required
by
TS 3. 1.3.5 "Shutdown
Rod Insertion Limit."
An Unusual
Event was
declared
by the licensee.
At 5:30 p.m.
the shutdown
bank rods were
fully withdrawn,
was exited,
and at 5:43 p.m. the Unusual
Event was terminated.
During the performance of monthly surveillance test
STP R-1A
"Exercising Full-Length Control Rods,"
a rod control urgent failure
alarm was received
when shutdown
bank
A group
2 control rods were
inserted
one step.
The indicator fuses for both shutdown,
and
control,
bank
A group
2 control rods failed, preventing withdrawal
of the rods.
I8C shift technicians
placed
shutdown
bank
A on
hold power, replaced
the fuses,
and the urgent failure alarm was
reset locally.
As control rod
DC hold power was removed,
another
urgent failure alarm was received
when one of the fuses
(A65) blew a
second
time.
After further engineering
eval.uations,
the fuse was.
again replaced
and the urgent failure alarm was reset
from the
control
room.
Shutdown
bank
A was then fully withdrawn to 228
steps,
normal
rod control
was verified to be operable,
and
was exited.
The event did not affect the ability of the rods to
drop into the core if required in response
to a reactor trip signal.
Root cause analysis of the fuse fai lures
was continuing at the time
this report was issued.
The inspector
observed that soldering
on
one
end of one of the power fuses
was of poor quality.
Since the
root cause
was under investigation,
I8C implemented monthly optical
pryometry (heat) inspection of control rod drive fuses until
corrective actions
have
been determined
and implemented.
Resolution
e
12
of this issue is considered
an open item (Open Item
50-275/87-38-03).
Failure of the Unit 2 Iso hase
Bus
C Phase
Motor 0 crated Disconnect
Re uirin
a Unit Tri
On November 7, 1987, at 1: 15 p.m.
a unit trip of Diablo Canyon Unit
2 was manually initiated due to the apparent failure of a motor
operated
disconnect
(MOD) in the main generator
25 kv isophase
Bus
"C".
At 1: 10 p.m.
a fire watch on rounds noticed green
and white light
emitting from the isophase
bus
room.
The fire watch notified the
control
room which dispatched
two operators.
The operators
confirmed the finding and deduced that arcing was occurring on one
of the buses.
They informed the control
room which initiated an
emergency
shutdown.
Following a brief discussion,
a manual unit
trip was initiated.
The unit trip was initiated by the operators
since, -in addition to initiating a turbine trip which initiates
a
reactor trip, it opens
the generator
output breakers
and transfers
electrical
loads to the startup transformers,
eliminating load on
the isophase
buses.
The licensee
made
a non-emergency
report in
accordance
with 10 CFR 50.72.
The licensee's initial inspection of the isophase
buses
determined
that the
MOD for Phase
C had caused
the arching.
The
MODs are
used
to isolate the generator
from the main transform to allow it to
supply plant loads
from 500kv offsite power during shutdown.
An MOD
is comprised of two sets of 62 stationary contact fingers arranged
in a cylinder,
one joined by flex link to the transformer side of
the bus, the other joined similarly to the generator
side of the
bus.
These sets of contacts
are separated.
Sliding over the
stationary contacts
is a cylinder of 62 copper shunt bars with
silver contact plates at both ends of each bar.
In the closed
position the contacts
of the stationary cylinders
make
up with the
contacts
on movable cylinder.
In the open position the movable
cylinder is retracted
over the transformer contacts.
The movable
cylinder is motor operated with control in the control
room.
The
licensee's initial inspection discovered
contacts
and shut bars
damaged
and discolored.
It was determined that the
MOD could not be
reused.
The licensee
did not have
an extra
MOD in plant stock.
In addition,
the vendor
no longer manufactures
that model
MOD.
A potential
replacement
was located at Cleveland Electric Company's
Perry Unit 2
on November 8.
An engineer
was sent to inspect the Perry
MOD to
ensure compatibility and to arrange for purchase
and transportation.
In response
to the event,
on November 10, the Vice President,
Nuclear
Power Generation,
invoked
AP C-18 "Event Investigation,"
.
which requires
the establishment
of an event investigation
team
(EIT).
The purpose of the team is to perform an in depth
investigation of significant events,
determine
probable
cause,
and
"achieve complete technical
understanding
of an event in a manner
13
that is timely, objective,
systematic,
thorough,
and technically
sound."
This was the first time AP C-18, issued July 1987,
was
invoked.
The EIT established
an action plan to determine
the root cause of
the failure.
The action plan was based
on the precepts
that switch
failure could only be caused
by increased
ambient temperatures
due
to inadequate
cooling', degraded
switch contact,
increased
load on
the switch,
and contact misalignment.
The action plan included
a
review of the bus cooling system
and temperature
data,
an inspection
of the adjacent
MODS, interviews of plant personnel
and the switch
representative,
and reviews of historical data, electrical
maintenance
records
and vendor drawings.
The licensee identified that the
MOD failure resulted
from a number
of contributory factors.
Specifically, the licensee
determined that
high abient temperatures
occurring five weeks prior to the failure
combined with degraded
switch contact resulted in increased
switch
resistance.
The increased
resistance
increased
heat which in
addition to increasing resistance
also
may have degraded
switch
contact.
This situation escalated
until the MOD's condition
produced arcing which was identified by operators.
The high abient temperatures
five weeks prior to the event were
caused
by a local heat wave.
The degraded
contacts
was attributed
to the hardening of lubrication grease,
possible contact
misalignment,
and
an accumulation of dust
on the contacts.
As corrective action,
the licensee
plans to develop
a comprehensive
preventive maintenance
procedure for the
MODs.
In addition,
the
licensee will develop
a surveillance
program which will address
isophase
bus cooling and the alignment of the isophase
bus contacts.
The licensee will also evaluate
the switch design to determine if
larger silver insert contacts will improve switch alignment.
In
addition, the licensee will evaluate
the desirability of different
MOD altogether.
Section
4.
c. discusses
maintenance activities related to
installation of the replacement
MOD.
In addition to the work
performed
on the Phase
"C" MOD, the licensee
inspected,
cleaned
and
lubricated, with guidance
from the manufacturer,
the
Phase
"A" and
"B" MODs.
The licensee
also visually inspected
the Unit 1 MOOS.
The
MODs were declared
on November
13 and the licensee
started
up November
13 and 14.
The inspector will follow-up the
licensee's
corrective actions
in the normal course of future
inspections.
Seismic Plates
Missin
from Containment
H dro en Monitor Panels
On October 20, 1987,
an Instrumentation
and Control (I8C) technician
discovered
seismic support plates missing from all four containment
hydrogen monitors (two for each unit).
A search of the surrounding
area turned
up only one plate.
This was reported to operations
which declared
the hydrogen monitors inoperable.
In accordance
with
TS 3.6.4. 1 "Hydrogen Analyzers/Monitors"
a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement.
was entered.
The licensee's offsite engineering
analyzed
the effects of the
support plates
on the operability of the containment
monitors.
The plates
were required to support isolation modules for
the following:
a)
Indication and recording
on Containment
Hydrogen concentration
on the post accident monitoring panel in control
room.
b)
c)
d)
Signal input to the emergency
response facility data
system for
containment
hydrogen concentration.
Cell failure alarm.
High and low hydrogen concentration
alarms.
The licensee
determined that
a seismic event would not cause
the
loss of the ability to analyze
containment
hydrogen concentration
and that indication would be available at the
100 foot auxiliary
building panel
and the remote Post
LOCA sampling
room.
Based
on
this evaluation the licensee
determined that the hydrogen monitors
had never
been inoperable.
The licensee's
Instrumentation
and Controls (I8C) department
performed
an unsuccessful
search
to identify when the plates
had
been
removed.
At the end of this report period, the
I8C department
had
an open quality evaluation to determine action to prevent
recurrence.
This will be followed by the inspector during routine
inspection.
In addition,
an open non-confofmance
report related to
seismic bracing for control
room recorders
dealt with the
same
issue
of not restoring equipment to its design configuration following
maintenance
or surveillance, will be followed as
a related
item.
Unit 2 Fuel Handlin
Buildin Ventilation
S stem
S urious Shift to
Iodine Removal
Mode
On October
12, 1987, at 1:47 a.m., with Unit 2 at 97K power,
the
fuel handling building ventilation system
(FHBVS) shifted into the
iodine removal
mode.
This mode change constituted
an actuation of
an engineered
safety feature.
The operators,
were able to shift the
FHBVS to the normal
mode at 2:20 a.m.
In its normal
mode,
the
FHBVS exhausts
through exhaust
fan E-4 which
does not have charcoal filters.
In the iodine removal
mode,
the
FHBVS exhausts
through charcoal filters on the suction of exhaust
fans
E-5 and E-6.
The system is designed
to switch to iodine
removal
mode
on either
a failure of E-4 or high radiation in the
fuel handling building.
The licensee
experienced
similar shift to the. iodine removal
mode
on
July 7, 1987,
and November 18,
1987.
The licensee
has not
identified the cause
for spurious sh'ifts to iodine removal
mode.
15
There
have
been
no printouts
on the annunciator typewriter
indicating fan failure or a radiation monitor signal.
The licensee.
has investigated digital circuitry logic diagrams
and logic states
to determine possible
causes.
The licensee
has installed
a
multi-point data recorder to gather data if this event recurs.
This
was
a corrective action planned
as
a result of the October
12 event
and was staged for installation but not installed for the November
18 event.
These
events
and
a number of other
FHBVS and auxiliary building
ventilation system problems
are being followed up by the inspector.
One violation and
no deviations
were identified.
4.
Maintenance
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.
Unit 2 Auxiliar Buildin Ventilation
S stem Exhaust
Fan E-2
Periodic Maintenance
Ins ection
The inspector observed
the performance of a periodic maintenance
inspection of the auxiliary building ventilation system exhaust
fan
ABVS-2-E-2.
The inspection included the cleaning,
meggering,
and
general
inspection of the fan motor,
a belt tightness
check,
and
an
inspection
and greasing of the fan inlet vanes.
The inspection
was
being conducted
in accordance
with a work order.
The inspector
noted that the belt tightness
check was being
performed with a tensioner
supplied
by the belt manufacturer.
The
mechanic
was performing the test in accordance
with instructions
supplied
by the vendor.
The instructions cited tolerances
for the
belts.
The maintenance
work order did not specify the
use of the
tensioner.
It instructed the mechanic to "slap" the belts
and note
whether they were "springy."
In following up this maintenance activity, the inspector attended
the Technical
Review Group
(TRG) dispositioning of a nonconformance
report
(NCR) regarding the fan belts
on ABVS-2-E-1 coming off the
belt sheaves.
The root cause
was established
to include
inconsistent
maintenance activity regarding belt installation, belt
tightening and belt and
sheave
inspection.
The
TRG determined that
corrective action should include
a maintenance
procedure to deal
specifically with belt installation.
The inspector
found the
corrective actions to be acceptable
to address
ventilation fan belt
problems including the inconsistencies
witnessed
during the
maintenance
of ABVS-2-E-2.
16
Unit 2 Motor 0 crated Disconnect
Re lacement
On November 7, 1987, Unit 2 was shut
down due to arcing of the
isophase
bus
C motor operated
disconnect
(MOD) (See Section
3. g.).
The
MOD had degraded
beyond recovery
and the licensee,
without a
replacement
part was forced to investigate other alternatives.
The
licensee
found a suitable
replacement part of Cleveland Electric
Company's
Perry plant.
However,
the replacement
was not identical
and required modifications to the plant prior to installation.
The inspector
reviewed the design
change
(DCN) associated
with the
MOD replacement.
The Perry
MOD was designed to be installed to a
16" square
bus whereas
the Diablo Canyon isophase
buses
are 21"
square at the
MOD.
To install the
MOD at Diablo, the flex links to
the bus
had to be placed together rather than 3" apart.
This
required the drilling of 64 holes in each
bus (transformer
and
generator
sides).
The licensee
evaluated
reduced contact area
between the flex links, due to the unused bolt holes.
The licensee
and the determined that contact area would be reduced
by
approximately 5.5X and found this acceptable
since the bus capacity
rating is approximately
15X above the actual
bus current.
The
inspector
independently calculated that contact surface
area would
be reduced
by approximately 6.0X.
The inspector reviewed the work order for the
MOD installation
and
found it referenced
the
DCN.
In addition the work order addressed
actions
necessary
to comply with TS 3.8. l.l.
The action statement
related to TS 3.8. 1. 1 allows offsite power supplied
from 1 of 2
sources
to be unavailable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The inspector discussed
the work with the electrician performing the
job and noted that the replacement
was being performed in accordance
with the work order and
DCN.
On November 4, 1987,
a leak from the bonnet of Unit 1 boric acid
evaporator recirculation valve FCV-739 occurred, resulting in about
125 gallons of borated water spillage onto the auxiliary building
floor and into the auxiliary building sump.
The leak was isolated,
and
a contamination
survey (number 13049) indicated
no contamination
was created
by the leaking component.
Action Request
(AR) A0089605
and Work Order
(WO) C0024356 were issued to remove the valve's air
actuator
and replace
the ruptured valve diaphragm.
WO C0024359
was
also issued to investigate
the cause of the diaphragm rupture at the
time the valve was disassembled.
The inspector
observed
the
disassembly,
which was performed
by qualified individuals in
accordance
with the work order.
Maintenance
personnel
concluded
the
diaphragm rupture
was caused
by over-stroking the stem and old age
of the diaphragm.
Additionally, a hole was found in the bonnet of
the valve, which was the source of the leakage.
The hole in the
carbon steel
was caused
by boric acid corrosion.
Both the
and bonnet were replaced.
17
As another
diaphragm valve (CVCS-1-547 "emergency borate flow to the
volume control tank outlet isolation valve" ) had recently also
leaked,
the inspector questioned
whether the elastomer
diahpragm
material
was qualified for post accident conditions.
In discussion with onsite project engineering staff members,
the
inspector
concluded
documentation
was available to demonstrate
the
diaphragm material
was qualified for 40 years considering
normal
plus loss of coolant accident
(LOCA) radiation exposure.
However,
this time interval
was based
upon
a normal
diaphragm temperature
of
120 to 150 degrees
F.
Since
many diaphragm valves are
used in heat
traced
systems (at 165 degrees
F) or otherwise hot systems,
the
expected life of the diaphragms
decreases
dramatically.
In
particular, ITT-Grinnell Maintenance
and Instruction Manual
OC-663263-117-1
on page
33 specified
a diaphragm replacement
program
of:
o
inspect diaphragms
every six months, if accessible
(using
V
notched vent plug)
o
replace
every five years - more frequently if
extreme (temperature)
service
o
for inaccessible
valves,
replace
the diaphragms
every plant
maintenance
shutdown or at least every two years.
The manual also specified
a maximum six year shelf life for valve
The inspector's
evaluation of the licensee's
preventative
maintenance
(PM) program to systematically
replace
exposed
to elevated
temperatures
concluded that for about
29 percent
(187) of these valves,
the diaphragms
had not been replaced
every
five years,
as specified in the
PM program.
issued
on
July 15, 1986,
documented that the diaphragm
inspections/replacements
were not done
due to difficulties in
clearing the valves
and
due to ALARA considerations.
However,
no
licensee
action was taken to effectively resolve the identified
concerns.
In discussions
with licensee
maintenance
management,
the licensee
agreed to evaluate corrective actions to assure
periodic
preventative
maintenance
of valve diaphragms.
Additionally, the
inspector identified concerns
regarding the licensee's
procedures
for valve stroke adjustment.
With the
numerous
types of diaphragm
valves
and operators
used at Oiablo Canyon,
the stroke adjustment
procedures
were not specific
enough to provide necessary
vendor
recommended
adjustment
information for each diaphragm/valve
combination in use at the plant.
In summary,
several
issues
remain outstanding
regarding this
subject.
They include
18
o
corrective actions to assure periodic diaphragm
replacement
(including valve clearance
problems)
o
diaphragm shelf life
o
diaphragm valve stroke adjustment
(manual
and operated
valves)
o
status
(open or closed) of vent plugs
on valve bodies in the
plant,
and need for vent lines to drains.
These
items are considered
unresolved
(Item 50-275/87-38-04).
No violations or deviations
were identified.
5.
Surveillance
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.
a.
Functional Test of Area Radiation Monitor RM-10
b.
The inspector
observed
I8C surveillance testing of auxiliary
building control board area radiation monitor RM-10.
Thi s quarterly
testing
was conducted in accordance
with Work Order number
R0029327
and SfP I-107A.
The test verified the channel
responded
to its
check source,
high voltage
was within operating limits, local
and
remote alarm conditions were annunciated,
and the recorder
and
computer
outputs
were generated.
Appropriate authorizations
to
perform the test
had been obtained prior to beginning the test.
Data sheets
were verified to be correctly filled out and data
obtained
met acceptance
criteria.
Through discussions
with the
technician,
the inspector
concluded the technician
was qualified to
perform the test.
Solid State Protection
S stem
SSPS
Slave Rela
Testin
The inspector witnessed control operators
perform portions of
Surveillance Test Procedure
(STP) M-16P3 and M-16P4, continuity
testing of slave relays.
The inspector
noted that the two operators
performed the testing in accordance
with the, procedure,
reviewing
the procedure prior to performing it and establishing
communication
between
the
SSPS
room and the control
room during its performance.
No findings were identified.
No violations or deviations
were identified.
6.
En ineerin
Safet
Feature Verification
Auxiliar
Buildin
and Control
Room Ventilation
S stems
The inspector performed
a walkdown of the physically accessible
portions of the Units 1 and
2 auxiliary building ventilation system
f
19
(ABVS) and control
room ventilation system
(CRVS).
The inspector
looked at damper positions,
control
room and local indication,
breaker position,
and general
equipment condition.
The inspector
identified empty radiation waste
drums resting against
26-A.
This was brought to the licensee's
attention
as
a possible
seismic interaction problem (see section 9.d.).
No violations or deviations
were identified.
TI 2500/19 - Low Tem er ature
Over ressure
Protection
LTOP)
Unresolved Safety
Ussue
(USI) A-26:
Reactor Vessel
Pressure
Protection for Pressurized
Water Reactors
was concerned with the
installation of an effective mitigation system for low temperature
overpressure
transient conditions.
The inspector verified that
systems
were installed
on Units 1 and 2,
as described
below.
The
LTOP system at Diablo Canyon
uses
two pressurizer
power operated
relief valves
(PORVs)
as relief devices to protect the reactor coolant
system
(RCS) from brittle fracture at low temperatures.
The
LTOP system
inserts
a low-temperature
pressure
setpoint of 450 psig into the control
circuits of PORVs
PCV-455C and
PCV-456.
The normal setpoint of'he
is 2335 psig.
The
LTOP system continuously
compares
actual
loop pressure
to the fixed pressure
setpoint of 450 psig.
When armed,
the
LTOP system
will open
PCV-455C
and
PCV-456 at 450 psig as
sensed
by
RCS loop,
wide-range
pressure
transmitters
PT-403 and PT-405, respectively.
Two conditions must be met to arm the
LTOP system:
The
LTOP circuits
must be enabled
by means of toggle switches,
and
RCS cold leg temperature
must be at or below 330 degrees
F.
Pressure
comparison,
arming of the
LTOP circuits,
and
PORV actuation
are all accomplished
in two separate,
mutually redundant
and independent
LTOP trains,
one each for PCV-455C and
PCV-456
'he
LTOP system is disabled during normal (at-power) plant operation.
During plant cooldown,
the system is enabled
in accordance
with Operating
Procedure
(OP) L-5 "Plant Cooldown from tIinimum Load to Cold Shutdown."
A separate
toggle switch is provided to enable
each train.
The enable
toggle switches
are located next to the control switches for PCV-455C
and
PCV-456 in the control
room.
When the switch is in the "cut in"
position,
a fixed setpoint of 450 psig is inserted into the automatic
control circuit for opening the>associated
PORV.. However,
the
PORV will
not open unless
cold leg, wide-range
temperature
is equal to or less
than
330 degrees
F.
When
LTOP is armed,
the normal
PORV setpoint of 2335 spig
remains operative but any pressure
excursions
should
be terminated
by the
PORVs at the
LTOP setpoint.
When the switch is in the "cut out"
position, the 450 psig setpoint is removed from the control circuit for
the associated
PORV.
A "PORV Low Setpoint Cut Out" annunciator installed in control
room
window PK05-10 indicates that
RCS temperature
has
decreased
to 330 degrees
F or less while one or both
LTOP enable
switches
remain in
cut out position.
This annunciator will actuate
on either of the
following conditions:
20
o
RCS loop 3, cold leg, wide range temperature
(TE-433B) less than or
equal to 300 degrees
F,
and the
PCV 455C low setpoint protection cut
out switch not in the cut in position.
o
RCS loop 2, cold leg, wide range temperature
(TE-423B) less
than or
equal to 330 degrees
F, and the
PCY-456 low setpoint protection cut
out switch not in the cut out position.
Additionally, annunciator
window PK05-20 "Pzr Relief/Safety Vlvs Open"
indicates,
via
PORV position switches,
when
PCY-455C
and
PCV"456
open.
The design of the licensee's
LTOP system
was reviewed by the NRC's Office
of Nuclear Reactor Regulation
as indicated in Diablo Canyon Supplemental
Safety Evaluation Report
(SSER)
Number 27.
Item 14 of that
SSER
specified that the
LTOP systems
"provided for Diablo Canyon, Units 1 and
2, meet the requirements
of RSB 5-2 and are acceptable...."
NRC Branch
Technical Position
RSB 5-2 considered
items
such
as the following:
o
10 CFR 50 Appendix
G limits for the
RCS while operating at low
temperatures
o
single active component failures
o
use of IEEE Standard
279 in the design
o
need for annunciation
o
testability
o
system "guality Group Classification" in accordance
with NRC
o
seismic design classification
o
electrical
power source
The inspector
reviewed Unit 2 electrical
schematic
number 441306
and
verified the
LTOP system
was designed with redundant electrical
channels.
From a review of the design
change
package
used to instal,l the
system,
the licensee re-verified the system
was installed
as
an
instrument Class lA (seismic)
system.
LTOP operating
procedures
(OPs)
and administrative controls were reviewed
by the inspector.
Technical Specification
(TS)
LCOs 3.4. 1.3 "Reactor
Coolant System - Hot Shutdown"
and 3.4. 1.4. 1 "Reactor Coolant System-
Cold Shutdown - Loops Filled" specified:
pump shall not be started with one or more of the
Reactor Coolant System cold leg temperatures
less
than or equal to
323 degrees
F unless:
(1) the pressurizer
water level is less than
50K, or (2) secondary
water temperature
of each
is
less than
50 degrees
F above
each of the Reactor Coolant System cold
leg temperatures."
c
21
OP L-1 "Plant Heatup
from Cold Shutdown to Hot Standby"
incorporated this
TS statement
in the Precautions
and Limitations section of the procedure.
However, the inspector
noted the
TS statement
was not included in OP L-5
"Plant Cooldown from Minimum Load to Cold Shutdown.'"
This situation
was
discussed
with operations
management
and action request
A0090871
was
issued
by the licensee to include the statement
in L-5 to enhance
the
procedure.
OP L-5 did include specific steps to (1) disable both SI
pumps,
(2) disable all but one centrifugal charging
pump,
and (3) cut in
LTOP when Tavg was less
than
350 degrees
F and
T cold was greater
than
323 degrees
F.
Step ll.d of OP L-5 also specified that with a solid
condition, all pressurizer
heaters
were to be turned off and
a caution
tag be attached
to the heater controls in the control
room.
OP L-6
"Refueling" indicated the
RCS low pressure
protection
system
was to be
cut in as
a initial plant condition for that mode of plant operation.
Another statement,
existing in OPs L-5, L-l, and A-6: I "Reactor Coolant
Pump's - Place in Service,"
was
as follows:
"With the
RCS in the solid condition, if all
RCPs are shutdown for
more than
5 minutes
and the seal injection water temperature
is less
than the coolant temperature,
do not start
an
RCP until the primary
system
has
been cooled to the temperature
of the seal injection
water, or a steam bubble is drawn in the PZR."
The purpose of this statement
in the
OPs
was to caution against
low
temperature
overpressurization
of the
RCS.
Operator training on the
LTOP system
was reviewed
by the inspector,
also.
Training of licensed operators
was conducted
by the licensee utilizing
Instructor
Lesson
Guides
LA-1 "Reactor Coolant System
and Auxiliaries"
and LA-4a "Pressurizer
and Pressure/Level
Control."
Lesson
number
LA-1
discussed
LTOP features
such
as annunciation,
setpoints,
source of
pressure
signal, enabling circuits, pressure
transient conditions,
and
vessel brittle fracture
and neutron embrittlement.
This training was
provided'uring the first week of training classes.
Ouring the sixth
week,
LA-4a presented
the specifics of the
LTOP design
and operation
once
again.
Several
simulator scenarios
were also observed to contain
shutdown operations with the
LTOP feature cut-in.
In particular,
lesson
LS-4-3B "Cold Shutdown/Loss of Cooling" involved shutdown operations with
a failure of PT-403,
causing
an inadvertent initiation of a
PORV.
Training attendance
records
were also
sampled
by the inspector.
Surveillance
records pertaining to
LTOP components
were also reviewed.
STPs I-68A and I-69A required functional testing of the
PORV overpressure
protection channels
(excluding
PORV operation) within 31 days prior to
entering
a plant condition in which
PORVs are required to be operable.
This testing verified proper operation of temperature
and pressure
inputs
to the overpressurization
actuation logic.
I-68B and I-69B required
calibration of PORV overpressure
protection channels
403 and 405 at least
once per 18 months.
I-68C and I-69C were also performed to measure
the reaction time timing of the
PORV actuation circuitry.
No violations or deviations
were identified.
22
8.
Radiolo ical Protection
~
~
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.
~0ee
Items
as
Unit 2
S ent Fuel
Pool Area Radiation Monitor
0 en Item
50-323/87-34-01
Closed
In inspection report 50-323/87-34, it was noted
by the inspector
that from April 1985 to October
1987
no apparent capability existed
for recording the atmospheric radioactivity in the spent fuel and
new fuel storage
areas of Unit 2.
FSAR table 11.4-1, "Radiation
Monitors and Readouts"
shows that both the spent fuel pool area
monitor (RE-58) and the
new fuel storage
area monitor (RE-59) are
recorded
by RR-58 and
RR-59 respectively,
at the radiation
monitoring rack-A.
For Unit 1 and Unit 2, this feature
has
never been
implemented.
When RE-58 and RE-59 were installed
on both units, the wrong
interface
between
the monitor and existing recorder
was installed.
The design
change to install
a new interface
was delayed
when plans
were
made to install
a
new recorder
design.
At the time of this
report,
a
new recorder
had not been installed.
The absence
of a
recording device
was
more notable for Unit 2 until October 1987,
since the inputs to the P-250 plant computer from RE-58 and RE-59
were processed
by the wrong computer routine until that time.
Failure to have
a recording device installed for RE-58 and
RE-59 for
both Units is an apparent
deviation from the commitments of FSAR
Table 11.4-1 (Item 50-323/87-38-03).
Section ll of this report discusses
problems. identified with the
containment
temperature
monitors for Unit 2.
There appear to be
a
number of long standing
problems with other radiation monitoring
systems.
While the licensee is addressing
the large backlog of
items in a methodical
fashion,
they do not appear to be in a
position of addressing
new problems with the monitoring systems
as
they occur unless
required
by technical specifications.
In the
cases
of RE 58 and
59 and the containment
temperature
monitors, the
problems
have existed since startup.
b.
Grade
8 Bolts (0 en Item 50-275/87-04-05
Closed
0
23
In November 1986, in response
to concerns of counterfeit bolts, the
Vender Program Branch of the then Division of Inspection
and
Enforcement
requested
the licensee
to supply a sample of SAE J429
Grade
8 bolts for chemical
analysis
and tensile testing.
In a
letter dated February 13,
1987, the Vender Program Branch informed
the 'licensee that one of the licensee
supplied bolts
had failed the
tensile test
by approximately
10K.
In response,
the licensee
placed all Grade
8 bolts from the affected
vendor .on hold.
The licensee
also identified that
no Grade
8 bolts
had been
issued for safety-related
use.
The licensee
tested
32
bolts from 15 heat
codes
and found only 2 did not pass
the wedge
tensile
load test.
Based
on the test results,
the licensee lifted
the hold on all bolts for safety related applications
except for the
two heat
codes which failed the wedge tensile
load test.
Subsequently,
on September
16,
1987,
the Office of Nuclear Reactor
Regulation
(NRR) informed the licensee that the original testing
had
been performed incorrectly.
Based
on the licensee's
actions
and the
findings of NRR, this item is closed
(Open Item 50-275/87-04-05,
closed).
Boron In ection Tank
BIT
Relief Valve
0 en Item 59-323/87-34-02
~0en
By letter dated
November 6, 1987, the licensee
provided information
to the
NRC regarding
leakage
from the Unit 2 BIT relief valve.
The
letter specifically addressed:
o
Clarification of the
FSAR update description of the BIT thermal
relief valve installation.
o
Potential
valve leakage
rates
and doses
from radioactivity
associated
with postulated
post-LOCA conditions.
o
The licensee's
leak reduction program,
including pending
revisions to STP M-86 "Leak Reduction of Systems
Outside
Containment Likely to Contain Radioactive Materials Following
an Accident (NUREG-0578, TMI-9)."
The letter responds
to the questions
posed in Inspection
Report
50-323/87-34
(unresolved
item 50-323/87-34-02).
The licensee's
response will be addressed
by the Office of Nuclear Reactor
Regulation.
The commitments
made in the letter wi 11
be followed up
in the course of routine inspection.
The inspectors
discussed
with
the licensee
two concerns
regarding this issue.
Specifically:
1)
Has the licensee initiated a corrective action/root
cause
evaluation of why FSAR leakage limits for post
recirculation were not incorporated into STP M-86, and,
2)
what consideration
is being given to leakage
evaluation
between
refueling outages?
24
This item remains
unresolved.
d.
Licensee Action Re ardin
Seismic
Hazard Sensitivit
50-275/87-26-02
Closed
This open item dealt with the recurring examples of transient
items
which were found by the inspectors
to represent
a hazard to
important safety equipment if an earthquake
occurred.
Such items
included heavy I8C mobile test carts next to safety related control
cabinets
and not in active use.
During the current reporting period the inspectors identified
additional
examples
on seismic
hazards
which indicated that the
licensee's
actions to sensitize plant staff to seismic
hazards
had
not been sufficient to preclude recurrence.
Specifically,
on October 23,
1987,
the inspectors
noted
55 gallon
waste
drum stacked
two high and leaning against controls for safety
related ventilation damper
E-22B.
Additionally, a nitrogen bottle
was observed tied to structure in the Unit 2 containment penetration
area at elevation
115 feet.
Additionally, on October 13,
1987, the
inspector
noted
10 to 12 pieces of turbine cowling parts,
estimated
to weigh several
hundred
pounds
each,
temporarily stored
on
electrical conduit for and on the ventilation duct for the Unit 2
control
room pressurization
system.
The licensee's
housekeeping
procedure
(NPAP-C-10) requires that
ancillary items
be stored
so that they will not impact and
damage
safety related
equipment.
The licensee is currently evaluating the
impact of the observed
items
on the related
equipment.
The failure
to comply with the procedural
requirement to protect safety related
equipment will be followed as
an unresolved
item pending the
licensee's
evaluation.
(Item 50-323/87-38-04).
No violations or deviations
were identified.
10.
Ph sical Securit
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,
compensator'y
measures,
and protected
and vital area integrity.
Exterior lighting was
checked during backshift inspections.
No violations or deviations
were identified.
11.
Licensee
Event
Re ort Follow-u
a.
Status of LERs
Based
on an in-office review, the following LERs were closed out by
the resident
inspector:
0
J
25
Unit 2:
87-15,
87-15
Rev
1
87-05
Rev 1
b
r
The
LERs were reviewed for event description,
root cause,
corrective
actions taken,
generic applicability and timeliness of reporting.
Red Tele
hone
vs
LER Trackin
The licensee
has evaluated
the following 10 CFR 50.72 events for
reportability under 50.73
and has determined that 50.73 report is
not required.
The resident inspectors
have
examined the licensee's
rationale
and determined that regulatory requirements
have
been
met.
50.72 Report
Date/Unit
Event
Reference
etc.
10/8/87/Unit 1
REN 10245
NCR 8 DCI-87-EM-112
Maintenance activity on wrong
component
and entry into TS 3.0.3
due to inoperable
redundant trains.
One train
later determined to have not
been inoperable.
No violations or deviations
were identified.
~
~
12.
Containment
Local
Leak Rate Testin
The inspector
reviewed the licensee's
containment
)ocal leak rate testing
program through direct observation,
record review,
and procedure
review
for compliance with 10 CFR 50 Appendix J "Primary Reactor
Containment
Leakage Testing for Water-Cooled
Power Reactors,"
and the licensee's
Technical Specifications.
The inspector
reviewed the licensee's
programs for Type
B leak rate
testing,
which includes the testing of electrical penetrations
and
containment air lock doors,
and for Type
C leak rate testing which
includes
the testing of containment isolation valves.
The inspector
found that all applicable penetrations
were addressed
by approved
Type
B
and Type
C test procedures.
The procedures
for
were found to be in
accordance
with the requirements
The procedures
require testing to be performed at or above the containment
design
pressure
of 47 psig with leakage
rates
determined
using the maximum
pathway leakage.
The procedures
also provided clear acceptance criteria
and appropriate
action consistent with the Technical Specifications.
The inspector witnessed
the performance of two Type
C tests
and
determined that the engineer performing the tests
complied with the
procedures
using test equipment with calibration.
The inspector
reviewed the licensee's
procedure for the combined
Type
B
and Type
C leakage evaluation.
The procedure
requires
an evaluation
be
26
performed
on a nominal
24 month frequency
and to be updated
whenever
an
individual test is performed.
The inspector reviewed the licensee's
total leakage calculation
and tracking and found them to be acceptable.
No violations or deviations
were identified.
13.
Inde endent
Ins ection
a.
Review of Annual
Re ort of Chan
es
Tests
and
Ex eriments
The licensee
submitted
PG8E letter
NO: DCL-87-270 to the
NRC on
November 9, 1987.
The letter is the required annual
report of
changes,
tests
and experiments
conducted
under the licensee's
cognizance
in accordance
with the requirements
of 10 CFR 50.59.
The
licensee's
report was reviewed by the inspector.
No violations were
identified.
b.
Technical
Review Grou
Effectiveness
The inspector
reviewed the effectiveness
of the licensee's
technical
review group (TRG) over the past year.
The purpose of the
TRG is to
evaluate
nonconformances
for cause
and establish
the corrective
actions required to prevent recurrence.
The procedural
requirements
for the
TRG are contained
in licensee administrative
procedure
(AP)
C-12 "Identification and Resolution of Problems
and
Nonconformances."
In general,
the inspectors
have noted
improvement in the conduct of
TRG.
The areas of improvement
has
been in:
o
The identification of root cause.
o
The identification of effective corrective actions.
These
improvements
can
be attributed in part to a
TRG chairman
training program.
The program teaches
techniques
which can
be
'employed to determine root cause
and corrective actions.
Some areas
of weakness
have
been:
o
A tendency of addressing
too narrow a scope.
o
Not having appropriate
persons
attend, specifically those with
first hand
knowledge of nonconformance.
o
Participants without first hand knowledge making decisions
based
on assumptions.
The inspectors will continue to monitor the effectiveness
of the
during routine inspection
and event follow-up.
No violations or deviations
were identified.
14.
Follow-u
of Re ional
Re uests
0
27
Containment
Tem erature Honitorin
The licensee for Arkansas
Nuclear Unit 1 reported to the
NRC that
average
containment
environment temperatures
at the time of the
report exceed
those
used
as
bases for environmental qualification
and post-accident
analysis.
Therefore,
the inspector
performed
an
examination to determine
the adequacy of Diablo Canyon's
containment
temperature
monitoring system,
including the following questions:
o
What containment
temperatures
are the bases for environmental
qualification (Eg) and loss of coolant accidents
(LOCA)?
o
Do the licensee's
TSs include temperature
limits for the
and, if so, what are they?
o
How are the temperatures
measured
and recorded?
o
Has the licensee
had difficulty keeping containment
temperatures
within limits?
The licensee
assumed
120 degrees
.F as
an average
containment
temperature for both the initial conditions for the peak containment
pressure
analysis following a
LOCA and-environmental
qualification.
The plant TS 3.6. 1.5 establishes
an average
containment temperature
f 120 degree
F as
a limiting condition for operation.
TS 4.6. 1.5
requires that containment
temperature
be determined
by averaging
4
of 8 containment temperature
monitors every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The TS action requires
temperature
be reduced
below 120 degrees
F in
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
or
shutdown.
Both units were originally designed with 30 containment
temperature
monitors.
Four monitors measure
vessel
shield wal 1 (at the
same
elevation) at four corners.
These monitors feed the P-250 computer
and annunciate
at 130 degrees
F.
The purpose of the four monitors
is to monitor concrete
temperature.
In addition,
two wide range
monitors were installed in each unit to meet the requirements
of
The final 24 monitor containment
temperature
in various areas
and input to the containment air temperature
measuring
system panel.
Eight of these
are
used to fulfillTS
4.6. 1.5 requirements.
The final sixteen monitors were installed to
monitor temperatures
during the containment .integrated
leak rate
test
(CILRT).
On Unit 1,
12 of the CILRT monitors can
be selected
individually or
as
an average for input to the control
room.
The control
room input
feeds
a chart recorder,
the safety parameter display system
(SPDS),
the P-250 computer,
and an annunciator.
The P-250 computer inputs
to an annunciator
which alarms at 120 degrees
F.
On Unit 2, the CILRT temperature
monitors
have
been
spared
in place
at the containment air temperature
monitor system
panel
in
accordance
with a design
change
since the contractor
used for the
CILRT does their own containment
temperature
monitoring.
The eight
28
TS 4.6. 1.5 monitors were designed
to input an average of the
selected
monitors to the control
room (the chart recorder,
SPDS,
and P-250).
However, the individual select
switches
do not remain depressed
after selection
and
a signal
does
not reach the control
room.
This condition has existed since Unit 2
startup.
As a result, the only direct containment
temperature
monitors in the control
room are the containment hi-range monitors.
At the time of the inspection,
the licensee
had identified the
select switch deficiencies
and
a design
change
was being initiated.
The inspector
reviewed the annunciator
response
manual
and found
some
inadequacies.
Firstly, the selected
containment air
temperature
monitor system monitors were not listed as possible
inputs to the
"CONTMT ENVIRONMENT P-250" annunciator.
Secondly,
the
list of "operator actions"
was incomplete.
In response
to the
inspector's
findings, the licensee initiated an action request to
revise the annunciator
response
procedure.
The revised procedure
will be reviewed during routine inspection.
The licensee
has
had
no problems
keeping the containment
below 120
degrees
F due to a large design margin in the component cooling
water
(CCW) system which cools the containment
fan cooler units.
The licensee
generally maintains
average
containment
temperature
around
95 degrees
F.
No violations or deviations
were identified.
~
~
~
~
~
15.
Alle ation Follow-u
a.
Alle ation No:
ATS RV-87-0034
Characterization
During the public comment portion of the Atomic Safety Licensing
'oard
hearing
on spent fuel racks held at Avila Beach
on June
15,
1987
an individual announced
to the board that
he had
a previously
undisclosed allegation that unqualified weld joints were used at
Diablo Canyon.
Subsequently,
discussions
with the individual and
the resident inspector revealed that the concern
was specifically
the joining tube steel
shapes
in a "tee" configuration
on pipe
supports.
The individual stated that the joint configuration wasn'
qualified to
AWS Dl. 1, the American Welding Society's Structural
Welding Code.
Im lied Si nificance to Plant Desi
n
Construction
or 0 eration
. The inspector
examined the previous history of allegations at Diablo
Canyon for the subject of the welding of tube steel
and examined
AWS
D1. 1-82, the Structural
Welding Code.
The results of that examination
show that the individuals concerns
had
been previously examined
and found acceptable
by the
NRC as
summarized
below.
29
AWS 01. 1-82 has
some special
requirements
for the weld joint
configuration which is formed when tube steel is used.
The joint
configuration is called
a flare-bevel
groove weld and refers to the
geometry obtained
when
a round bar is placed against
a flat plate.
AWS Dl-l limits the amount of effective weld throat that can
be
assumed
by the designer
using such
a configuration and requires
tests to verify the effective throat is achieved.
The licensee,
however, did not perform pipe support welding in
accordance
with AWS D. 1.1 but rather qualified welders
and welding
procedures
to the
ASME Boiler and Pressure
Vessel
Code.
This fact
was the subject of the Diablo Canyon Allegation Management
Program
(Allegation ¹110)
and was addressed
and found to be satisfactory in
the
NRC Safety Evaluation report,
NUREG 0675 Supplement
No.
22
(SSER
22).
It should
be noted parenthetically
here that the issue of proper
flare bevel welding was explored extensively at Diablo Canyon in
response
to allegations
and inspection findings.
Below is
a partial
list of allegations
and the safety evaluation reports that evaluated
the stated situations
as satisfactory:
o
Allegation 92
Flare bevel welds were undersize
and not
per code
(SSER 22)
o
All,egation 94
o
Allegation 103
o
Allegation 105
Pipe welding procedures
were
used for
structural
welding
(SSER 21)
Structural
shapes
are not specified
on Weld
Procedure
Specifications
(SSER 22)
Weld joint 'geometry not specified
on Weld
Procedure
Specifications
(SSER 22)
The safety evaluations
describe
the
NRC staff's evaluations
and
concluded that the flare bevel welds comply with AWS D. l. 1 and the
quality was good.
The
NRC staff performed
independent
inspections
and
had independent
inspections
performed for the
NRC by Lawrence
Livermore National Laboratory (LLNL) personnel
(under contract).
Further,
the
NRC staff had Pullman
Power provide an evaluation of
flare bevel
welded joints for tube steel.
The evaluation
showed
that all welds
made
on various sizes of tube steel
met or exceeded
AWS Dl. 1 effective throat requirement.
Additionally NRC Inspection
Report 50-275/84-11
and 50-323/84-11
states
that
LLNL performed independent
inspection of tube steel
radius of curvature
and
NRC reviewed the w'eld tests
performed by the
licensee
to show that the proper effective throat
had been achieved.
The
NRC inspectors
also
examined
samples
cut from various sizes of
tube steel.
The inspectors
stated that they had
a high degree of
confidence that the weld throat thickness
assumed
by the designer
had been effectively implemented.
30
The inspector therefore
concluded that the question of flare bevel
as
used at Diablo Canyon for joining tube steel
members in
pipe supports
had been fully addressed
in previous allegations.
In regards
to the specific concern stated,
specifically tube steel
joined to tube steel
in a "tee" configuration,
the inspector
reviewed the applicable welding procedure
(weld procedure 7/8), the
specification for installation and inspection of pipe supports
(Pullman
Power Products Specification
ESD 223
AWS D. l. 1), the
allegations,
and
PG8E responses
to the allegations.
These
documents
show an evolution of improving specifications,
requirements,
and actions.to
demonstrate
that the pipe support
welding was adequate.
The "tee" configuration is addressed
in PGCE
letter DCL-84-40 of February 7, 1984 (to the NRC), Attachment 3, in
regard to the proper welding symbols to be used for the
configuration.
AWS Dl. 1 allows for partial penetration
welds without backing bars
and with root openings of various amounts.
The flare bevel weld
being questioned
is a partial penetration
weld being welded with a
root opening.
The licensee's
actions to perform production/qualification tests
for
the flare bevel configuration were not performed until after
a great
deal of welding had already
been performed but that subject
was
fully covered in the resolution of allegations previously discussed
and it was adequately
demonstrated
that the design engineers
assumption of good weld metal for 5/8 of the tube steel
thickness
was achieved.
Staff Position
The staff position is that the welding of tube steel
had not indeed
been qualified per
AWS Dl. 1 literal requirements
but that this
subject
had been thoroughly examined
and found acceptable
by the
NRC
in the examination of previous allegations.
Action Re uired
None.'lle
ation
No:
ATS RV-87-0033
Characterization
The alleger
stated that guality Assurance
(gA) had done
an audit on
measuring
and test equipment
and
had found that the equipment
was
seriously out of calibration and
had been for several
years.
The
alleger stat'ed
these conditions
had been reported to upper
management
who did nothing and that workers
had then
gone
anonymously to the gA manager
who then performed
an audit.
The
alleger stated that upper management
"got the man". who had given
~4'i
31
information to gA, they denied
him raises,
gave
him a pay cut and
took him off the overtime list.
Im lied Si nificance to Desi
n
Construction or 0 erations
Measuring
and testing equipment, if seriously out of calibration,
could lead to plant equipment operability verification tests
being
inaccurately performed
and verifications of performance
parameters
invalid.
If upper
management
had been unresponsive
to correcting equipment
seriously out of calibration,
then the licensee's
responsiveness'o
safety issues
would be in question.
If the person identifying the safety concern
was the object of
retribution for raising those concerns,
then the licensee's
actions
would have
a chilling effect on other personnel
who might have
safety concerns.
Assessment
of Safet
Si nificance
The inspector
examined
records of the audit, actions
taken
as result
of the audit,
and discussed
those actions with involved plant
personnel
including gA, gC,
and IIC.
The inspector
examined the audit report
(PG&E audit report 87134P)
dealing with the measuring
and test equipment
(M&TE) area.
The
audit was performed by PG&E gA personnel
from May 7 to June 3, 1987.
The audit report found the
M&TE programs for mechanical
maintenance
and electrical
maintenance
adequately
implemented.
For the
Instrumentation
and Controls department,
the audit revealed
several
findings.
The most significant finding was that
some permanently installed
M&TE (such
as pressure
gages)
had not been included in all the
administrative
programs.
More specifically, industry standards
and
the licensee's
procedures
require that when measuring
and test
equipment is sent back for periodic recalibration,
and if the item
found to be out-of-calibration,
then
an evaluation
must be made of
all equipment
on which the
M&TE item was used,
to ensure
whatever
test was
done
and its results
were still acceptable.
The licensee's
procedures
did this for portable
M&TE.
The audit finding points out
that
some test procedures utilize installed plant equipment,
such
as
gages,
for reading of test acceptance
values
and,
as such, that
installed equipment is "M&TE" which, although it is periodically
recalibrated,
should also trigger an evaluation of test data if it
is found out-of-calibration.
The specific audit findings and licensee
actions
taken were:
o
Nonconformance
Report
NCR DCO-87-TI-N072 documented that
out-of-tolerance plant equipment
(used
as
M&TE) did not have
'/
~L'
A
32
adequate
actions taken to evaluate
the situations
where the
equipment
was
used for performance tests.
The licensee initiated a review to determine
the impact of
previously performed tests
done with plant installed
NOTTE.
Nonconformance
Report
NCR DCO-87-TI-N050 documented that
history searches
for out-of-tolerance test equipment were not
completed in a timely manner.
The licensee's
corrective action was to revise the
appropriate
procedures
to provide
a time limit for the
history searches
and to conduct training.
The licensee
also determined that
a contributory cause
was having more
stringent than necessary
tolerance
requirements.
Note:
The nonconformance
was written by plant staff.
Plant management
personnel
stated to the inspector that
the
NCR was defined
and in process
of issuance prior to
the audit and was not a result of the gA audit.
However,
it was further observed that the issue of untimely action
on history searches
was identified by plant gC in quality
evaluation written on June
27,
1986
(gE 003235).
o
Nonconformance
Report DCO-87-gA-N001 documented that
calibration accuracy ratios between calibration standards
and
H8TE had not, in all cases,
been
documented'.
The licensee's
action includes the forming of a task group
to provide corrective action.
'I
Audit Finding Report
AFR 87-110 described
the condition that
radiation protection
and environmental
monitoring equipment
which was being maintained
by ICC did not have
a list which
specified which equipment, if any, should
be under the quality
assurance
program.
The licensee's
action was
was to perform an initial
assessment
that indicated
no adverse
impact on plant
conditions.
Radiation protection equipment in use
had
been calibrated.
The Chemistry
and Radiation P'rotection
manager stated that action
had been initiated to define
which radiation protection equipment should
be designated
as
under
the quality assurance
program but that the
methods of calibration
need not be changed
since they had
not been found faulted by the audit.
The
NRC had
performed
a team inspection,
in October 1987, of the
chemistry
and radiochemistry laboratory standards.
The, inspection
found the calibration methodology to be
sound (Reference
Inspection
Report 50-275/87-24.
o
Audit Finding Report AFR-111 de'scribed
twelve items of
NOTTE
which had been
logged out for long periods of time and which
0
33
could not be located during the audit and did not have adequate
traceablity of use through the usage
logs.
Licensee corrective actions
include procedure
revisions to
strengthen
logout controls, training of personnel
and the
missing equipment
was resolved.
r
o
Audit Finding Report
AFR 87-112 reported that
no list 'or
procedure existed to identify which I8C equipment required
calibration stickers.
The licensee's
corrective action was to revise the
applicable
procedure to include
a list of I8C equipment
requiring calibration stickers.
o
Audit Finding Report AFR-87-113 reported several
related
concerns,
specifically:
that procedures
had not been
used for all calibrations
performed
by I8C.
Four cases
were observed
where
a shop work
follower or work order was used.
that the electronic calibration lab procedure
manual did not
contain copies of seven procedures
used
by I8C to calibrate
chemistry and radiation protection equipment.
that the procedure
used
had not been
documented
on the records
for 29 devices.
that six procedures
did not have documentation of review for
completeness
by I8C technicians.
Licensee actions
include correcting the calibration lab
procedure
book, eliminating work order based instructions
and using only approved procedures,
developing
a procedure
review checklist, correcting procedure errors,
and
including an entry (to indicate the procedure
used)
on
calibration data sheets.
o
Audit Finding Report
AFR 87-114 stated that the Master
Calibration Schedules
(MCS) was outdated
and incomplete.
Temporary procedure
changes
had not been
documented.
Four sets
of duplicate
equipment identification numbers
were noted.
Six
out-of-tolerance
notices did not have all information recorded.
Two pressure
gages
did not meet
a transfer standard
accuracy
requirement of 4: 1 and did not have
a documented
authorization
permitting this.
The licensee's
actions
included deleting the
MCS and
utilizing an electronic data
base
equipment list and
calibration schedule
(which had been in formative and
concurrent use), eliminating all duplicate identification
numbers,
resolving the missing information on
out-of-tolerance notifications,
and including the transfer
34
standard
accuracy
requirement in a procedure
development
checklist.
o
Audit Finding Report
AFR 87-115 reported that the
I8C
electronic calibration lab did not meet the requirements
for
cleanliness,
controlled access
or environmental
monitoring.
The licensee's
corrective action including temporary
utilization of the general
construction facilities
calibration laboratory and plans to upgrade
the plants
calibration facility.
Discussion
The
sum of audit findings and nonconformance
reports discovered
by
the licensee
and documented for corrective actions indicate that
indeed the control of measuring
and test equipment,
and installed
plant indication used for test data,
was not totally adequate.
It
is to the licensee's
credit that the the problems
were identified
through the licensee's
quality assurance
process.
It is somewhat
to the licensee's
detriment that the problems
were not more promptly
identified and corrected
by line management
responsible for the
activities.
The key to identifying the problems in the
t4hTE area
appeared
to be
the advent of a senior technician,
experienced
in calibration
laboratory procedures
and practices,
on the plant staff.
The
technician properly identified perceived
problems to his supervision
and management
in early 1987 but no comprehensive
actions
were
initiated at that time (based
on the lack of documented
problem
identification).
gA personnel
in conducting
an audit of t4hTE in the general
construction
area
became
aware of the perceived
problems in the
plant calibration facility and both contacted
the senior technician
and focused their audit efforts in the plant area.
The senior technician
was properly forthright with the auditors in
identifying perceived
weakness
and areas
requiring correction.
The inspector
discussed
the MTE situation with the senior
technician
subsequent
to the receipt of an anonymous allegation.
The senior technician indicated that
he
had discussed
his opinions
regarding the NTE area with his supervision
and management
and the
gA auditors.
He indicated that
he
had not been adversely treated
and was comfortable in bringing up the matters.
He indicated that
he personally did not like overtime
and that the lack of overtime
was his choice.
The inspector concluded that there
was
no evidence
that the senior technician
had been "gotten" by upper management.
The inspectors
review of licensee
corrective actions
was conducted
in November 1987.
The inspector
noted that much of the corrective
action was not complete
and was scheduled for completion in December
1987 and later in 1988.
35
The major corrective actions
are to utilize the better calibration
facility at General
Construction until such time as the funded I8C
.
shop
and calibration lab is constructed,
to revise procedures
extensively,
and to perform history searches
on installed plant
equipment which has
been
used to measure
plant performance
parameters.
In this regard,
the licensee first generated
a list of
all plant equipment
used to measure plant performance
parameters
in
safety related (technical specification)
uses.
This list identified
445 applicable
items.
Of these,
the licensee
began to evaluate
which items
had been
found out of calibration at the time of
recalibration.
The licensee
sampled
119 items
and found 79 were
found out of calibration, that is, not within the accuracy stated
for the instrument.
The licensee
then evaluated
a sample of 39 of
the 79 for effect on the plant parameter
measured
and found that
accounting for instrument inaccuracy the plant parameter
was
satisfactory for the safety analysis
required value.
The licensee
has put further analysis
on a hold based
on these results
and is
evaluating the sufficiency of the sample size.
Further,
the
licensee's
rationale for not doing further historical review is that
the'nstruments
being questioned
are in current calibration and the
tests
were reperformed during the Unit 1 and Unit 2 refueling
outages
and therefore further research
would not identify a plant
parameter currently out of specification,
only those that were, if
any.
However, the inspector observed that the licensee's
sample results
showed
79 of 119 items of installed plant measuring
equipment
was
out of calibration at the time of recalibration.
The
FSAR section
17.2 and
IEEE 498 both indicate the recalibration intervals
should
be adjusted
to provide assurance
that measurements
are taken with
instruments with adequate
accuracy.
Responsible
licensee
personnel
stated that consideration
of calibration interval adjustments
have
not been
made
and that the data
base for such considerations
is
being developed
through the recalibration program.
The inspector
was informed that responsibilitjes
and methodologies for evaluating
calibration frequencies for installed plant measuring
equipment
would be included in the procedure
revisions being written to
implement 'measuring
and test equipment requirements
on installed
plant measuring
equipment.
Staff Position
The staff position is that the allegation is partially substantiated
but was overstated
in its severity.
The licensee's
guality
Assurance
department
did perform an audit of SEE
and
had identified
findings requiring corrective action.
The findings demonstrate
that
the plants measuring
and test equipment
programs
lack controls in
some areas
(e.g.
lack of evaluative history searches
for installed
plant equipment
found out of calibration)
and poor execution of
existing administrative
requirements
in some areas
(e.g.
lack of
cleanliness
in the calibration facility, lack of procedures
for some
calibrations,
lack of timely evaluative history searches
for
portable ATE found out of calibration).
0
~,
36
The staff-found the licensee's
sampling of the effect of
out-of-tolerance
measuring
and test equipment
found druing
recalibration
on important plant performance
parameters
measured
with that equipment
has not identified instances
of
plant operation
with performance
parameters
outside of safety analysis limits.
The staff found that since the plant parameters
have
been recently
satisfactorily remeasured
during the Unit 1 and Unit 2 refueling
outages
with instruments still within their calibration period.
The staff found problems with the
M&TE program were identified by an
experienced
senior technician to his supervision
and managemnt
and
that no significant actions
were taken until the
gA audit was
performed.
The staff found that the senior technician
who identified M&TE
problems did not consider himself "gotten by management."
Action Re uired
No further action is considered
required for the resolution of the
allegation.
Follow-up of M&TE problems identified by the
gA audit
will be performed in the normal course of future inspections.
Follow-up of the apparent
lack of timely and aggressive
problem
identification and resolution
by plant staff, both before
and after
the gA, audit is a item concern which parallels
the concern raised
in inspection report 50-275/87-08 regarding the timely
identification and resolution of procurement
issues.
Follow-up of
this concern will be performed in a future insepection
and is
considered
an unresolved
item (Item 50-275/87-38-05).
Unit 1
S ent Fuel
Pool Rerackin
As a result of the September ll, 1987, Initial Decision of the NRC's
Atomic Safety
and Licensing Board,
on October 20,
1987, the
NRC issued
Ammendment
numbers
22 and 21 to the Facility Operating
License for Unit 1
and Unit 2, respectively.
These
amendments
authorized
PG&E to rerack the
spent fuel pools,
arid reinstated
the effectiveness
of Amendment
No.
8
(Unit 1 ) and Amendment
No.
6 (Unit 2) which were issued
on May 30,
1986.
The effectiveness
of these
amendments
was stayed
by the U.S.
Court of
Appeals for the Ninth Circuit until the completion of a prior NRC
hearing,
which has
now been completed
and
an Initial Decision issued.
The amendments
allowed the expansion of the spent fuel storage
capacity
of each spent fuel pool
(SFP)
from 270 spaces
to 1324 spaces.
The
amendment
also provided for storage
in the present
racks or the
new racks
(or both) until the installation of the
new racks
was complete.
Accordingly, during October 1987, the licensee
began preliminary
preparations
for wet reracking of the Unit 1 SFP.
Work Order C0023076
and design
change
package
(QCP) 35810 were issued to accomplish this
task.
Previously,
the existing low density racks were welded to
embedment plates
in the
SFP steel liner.
DCP 35810 specified accessible
attachment
on the low density racks were to be cut by divers
0
pi
k
37
utilizing a hand held hydraulic cut off tool.
Remote operated
cut off
tools will be used to cut welds unaccessible
to the divers.
Remaining
weld material
on the pool floor would then
be ground where installation
of bearing plates for the feet of the
new high denisty racks are
required.
As of the ending date of the report period, preparations
for
grinding of the attachment
weld on the feet of existing low denisty rack
number
5 were in process.
Previous
NRC inspection of high density rack procurement
documents,
receipt inspection procedures,
storage
procedures,
welding
qualifications,
vendor supplied records,
and direct observation of
ongoing installation activities was documented
in NRC Inspection
Reports
50-275/86-04,
86-13, 86-18,
and 86-23.
No violations or deviaitons
were identified.
17.
Unresolved
Item
Unresolved
items are matters
about which more information is required to
determine whether they are acceptable
or may involve
violations or
deviations.
Three unresolved
items were identified during this
inspection
and are discussed
in paragraphs
2.c., 4.c., 9.d.
and 15.b..
18.
Exit
In addition to weekly exits,
on December
7, 1987,
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.