ML16341E346
| ML16341E346 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 07/08/1987 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E345 | List: |
| References | |
| 50-275-87-23, 50-323-87-22, IEB-85-003, IEB-85-3, NUDOCS 8707240051 | |
| Download: ML16341E346 (38) | |
See also: IR 05000275/1987023
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report
Nos:
50-275/87-23
and 50-323/87-22
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:
May 31 through
L.
M. Padovan,
Resident
June
27,
1987
Inspector
M~c~
Approved by:
K.
E. Johnston,
Resident Inspector
~
~
P.
P. Narbut, Senior Resident Inspector
M.
M. Mendonca,
Chief, Reactor Projects
Section
1
Date Signed
7i8/P~
Date Signed
g/z-Pd
Date Signed
Date Signed
Summary:
Ins ection from Ma
31
1987 throu
h June
27
1987
Re ort Nos.
50-275/87-23
and 50-323/87-22
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.
Inspection
Procedures
25573,
30703,
61726,
62703,
71707,
73051,
73753,
90712,
92700,
92701,
92710,
93702,
and 94703
were applied duiing this inspection.
Results of Ins ection:
One violation regarding procedural
compliance
was
identified (Paragraph
3.c).
8707240051
870709
ADOCK 05000275
8
0
~
~
DETAILS
Persons
Contacted
"R.
C.
"J.
A.
"J.
M.
AJ
D
C
L
"K. C.
R.
G.
"D. B.
"D. A..
"M. G.
~J.
V.
"L
F
~T.
L.
S.
R.
R.
S.
D.
A.
B.
D.
M. J.
Thornberry, Plant Manager
Sexton, Assistant Plant Manager,
Plant Superintendent
Gisclon, Assistant Plant Manager for Technical
Services
Townsend, Assistant Plant Manager for Support Services
Eldridge, guality Control Manager
Doss, On-site Safety Review Group
Todaro, Security Supervisor
Miklush, Maintenance
Manager
Taggert, Director equality Support
Crockett, Instrumentation
and Control Maintenance
Manager
Boots, Chemistry and Radiation Protection
Manager
Momack, Operations
Manager
Grebel,
Regulatory
Compliance Supervisor
Fridley, Senior Operations
Supervisor
Meinberg,
News Service Representative
Malone, Senior I8C Supervisor
Guilbeault,
PSG Supervisor
Angus,
Mork Planning Manager
The inspectors
interviewed several
other .licensee
employees
including
shift foreman
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general construction/startup
personnel.
2.
Denotes
those attending the exit interview.
0 erational
Safet
Yerification
'a 0
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)
(d)
Radiation protection controls.
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
secur ity 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 other
plant personnel.
The discussions
centered
on pertinent topics of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
Seismic Interaction - 4 and 12 Kilovolt
KV
Switch ear
Room
While observing
12KV switchgear
on Unit 1, the inspector identified
a heavy metal three shelf cart which I8C technicians left unsecured
next to the 12KV switchgear.
In the event of an earthquake,
the
cart could have potentially impacted switchgear,
relay board panels
or other electrical cabinets.
This situation
was discussed
with the
I8C personnel
responsible for the oversight,
and was brought to the
attention of I8C management.
The cart was subsequently
properly
stored.
Unit 1 Containment
S ra
S stem Walkdown
En ineered Safet
Features
S stem Walkdown
The inspector performed
a walkdown of physically accessible
portions
of the Unit 1 containment
spray system.
Small
amounts of boron
crystal
accumulation
were observed
on the packing of three valves
and
on the outboard mechanical
seal of containment
spray
pump
(CSP)
1-1.
Additionally, a larger deposit of boron was identified on
1-1 discharge outlet valve,9001A.
This information was provided to
the licensee for resolution.
Overdue calibration stickers
were found on a level indicator and
a
pressure
indicator.
The licensee anticipates initiating a program
to remove overdue cal'ibration stickers
on this type of
instrumentation
which is not required for performance of
surveillance test procedures.
A "special calibration" sticker on
rotameter
F1929
(CSP test flow indicator used for STP P-4B)
indicated calibration was
due August 1984.
In discussion with
instrumentation
and controls personnel,
the inspector
was informed
that other instrument records indicated the calibration
was
due
August 1987.
However, since the required calibration
was designated
"special," the licensee
agreed to investigate
the adequacy of the
instrument's calibration.
No violations or deviations
were identified.
3.
Onsite Event Follow-u
'a ~
Inadvertent
Boron In ection
At 0330 a.m.
(PDT) on June 7, 1987, while Unit I was at 885 power,
the licensee
declared
a unusual
event
due to the inadvertent
injection of about
200 gallons of 20,000
ppm borated water from the
boron injection tank (BIT), which resulted
in a reduction of Tavg to
less
than
541 degrees
F.
Tavg was recovered
by a turbine load
reduction to 60$ power.
The cause of the event
was initially stated to be leaking BIT outlet
valves.
This was subsequently
determined to be in error,
and the
cause
was determined to be equalizing of pressure
across
the double
disc of the valves creating
improper valve seating.
Operators
were performing
(STP)
M-16B "Operation of Slave Relays
K604A and
K604B (Safety Injection)."
Concurrently,
STP M-21C
"Weekly Main Turbine Valve Exercising"
was in progress.
The senior
control operator
(SCO) actuated
slave relay K604A from the
SSPS
room, causing
valve 8803A, the BIT inlet valve, to open.
The
SCO
then returned to the control
room to verify proper
component
actuations,
and complete that portion of'he test.
When he arrived
he was
summoned to the control console to assist
the control
operator
(who was experiencing
problems with turbine stop valve
number 4) in performing
STP M-21C.
While assisting with the turbine
valve testing,
operators
noted that
RCS Tavg was rapidly decreasing.
Properly assuming that the BIT outlet valves were leaking through,
the operators
closed
8803A and
ramped turbine load to about 60'l to
recover
RCS temperature
to within limits.
RCS Tavg reached
a
minimum value of 536 F, which was below the technical specifications
minimum of 541
F for 8 minutes.
Analysis indicated about
150
gallons of 12% boric acid were injected into the
RCS during this
incident.
The BIT inlet and outlet valves are the "double disc with equalizing
line" type, motor operated
gate valves.
The BIT is designed to have
low pressure
inside of the inlet and outlet isolation valve
boundary,
and high pressure
outside that boundary for proper valve
sealing.
With the conditions set
up by STP M-16B, the outlet valves
lost their sealing capability.
As corrective action to prevent recurrence,
the licensee
planned to
revise
STP M-16B to include
a step to close the equalizing valve on
valves
8801A 5
B prior to pressurizing
the BIT for this test.
Unit
2 BIT valves are of different type and require
no changes.
Also,
plant engineering
was to review the surveillance test program for
other instances
of this problem with the boron injection path
valves,
and correct the
as necessary.
Unit 2
S ill of Borated Mater from Boric Acid Stora
e Tank 2-2 to
the Auxiliar Buildin
On June
20, 1987, at 2059 hours0.0238 days <br />0.572 hours <br />0.0034 weeks <br />7.834495e-4 months <br />,
approximately thirty gallons of
borated water spilled from boric acid storage
tank (BAST) 2-2
through
a drain valve downstream of boric acid transfer
pump
(BATP) .
2-2 to the Unit.2 auxiliary building.
Chemical
and radiation
protection
(CHIRP) personnel
surveyed
the spill and roped off the
area,
but did not identify any contamination.
Prior to the event,
two clearance
requests
(CRs) were simultaneously
issued to the field.
The first,
CR 6464, required the isolation of
BAST 2-2 for the installation of a new level transmitter
(LT) 102.
The second,
CR 6262, required the draining of BAST 2-2 as well as
its isolation for inspection of the tank and maintenance
on valves
associated
with it.
One of these valves,
CVCS-2-8488B (the
BAST 2-2
drain) was clogged.
CR 6262 established
an alternate
drain path
through
BATP 2-2 and out drain valve CVCS-2-194.
The drain path
included
BATP 2-2 suction valve CVCS-2-8761B.
However, since this
valve is normally open, it was not included
on
CR 6262.
However, it
was included
on
CR 6464 as
a boundary valve to be closed.
This sequence
of events is as follows:
1535 hours0.0178 days <br />0.426 hours <br />0.00254 weeks <br />5.840675e-4 months <br />
CVCS-2-8461B
was closed isolating
BAST 2-2 from BATP
2-2 as required
by
CR 6464.
1910 hours0.0221 days <br />0.531 hours <br />0.00316 weeks <br />7.26755e-4 months <br />
With al-1 clearance
points established
on
CR 6464 and
all boundary valves closed
as required
by
CR 6262,
CVCS-2-194 was opened draining the volume downstream
of CVCS-2"8461B.
2059 hours0.0238 days <br />0.572 hours <br />0.0034 weeks <br />7.834495e-4 months <br />
CVCS-2-8461B
was opened
when operations
reported off
CR 6464.
The volume of borated water remaining in
BAST 2-2 and upstream of CVCS-2-8461B drained through
CVCS-2-194 and to the auxiliary building floor.
2117 hours0.0245 days <br />0.588 hours <br />0.0035 weeks <br />8.055185e-4 months <br />
The spill was reported to the control
room and
CVCS-2-8461B
was shut.
It appears
that the spill resulted
from the practice of those
writing clearances
to assume that a normally open valve does not
need to be addressed
on a clearance if it is to remain open.
While
this may be
a valid assumption
during normal operation, it would
appear that during a refueling outage,
with the overlap of
clearances,
there is the possibil'ity that
a missing clearance
point
could affect plant safety or cause
serious injury.
This is a second
example during the Unit 2 refueling outage that confusion
on
a
"
clearance
point has resulted in a spill (see Inspection
Report
50-323/87-20
paragraph 3.i.).
The licensee
has committed to review
these
events for actions
necessary
to prevent recurrence.
The
action taken by the licensee will be tracked with the issues
related
to Open Item 50-323/87-20-05.
Load Reduction
Due to Partial
Loss of Solid State Protection
S stem
SSPS
Train A
On June
15,
1987, Unit 1 was operating at lOOX power with I8C
technicians
performing
STP I-9A "Trip Actuating Device Operational
Test 12kv Undervoltage,
Underfrequency"
on 12kv Bus
D reactor
coolant
pump
(uv) and underfrequency
(uf) relays.
At 2213 hours0.0256 days <br />0.615 hours <br />0.00366 weeks <br />8.420465e-4 months <br /> the control
room received
a
SSPS general
warning
"Train A" alarm and
a "protection channel
activated"
alarm.
Protection set II bistables for RCP
uv and uf,
RCP breaker
open,
low
auto stop oil pressure,'nd
turbine stop valve 04 simultaneously
began flashing on and off.
Control
room personnel
paged the
IEC
technician located at the 12kv switchgear relay board,
and
ascertained
that the technician
had accidentally partially closed
the metal
panel
door on instrumentation test leads,
causing
an
electrical short in Train A of the
SSPS.
This short blew the Train
A input excitation fuse,
and accordingly the shift foreman
(SFM)
conservatively
determined Train A of the
SSPS to be inoperable.
The
ILC technician in the control
room placed the Train A multiplexer in
normal
and the previously identified bistable lights stayed lighted,
indicating the bistables
were tripped.
The
SFM declared
a
Notification of Unusual
Event,
and required notifications were made.
A turbine
rampdown
was also initiated at 2227 hours0.0258 days <br />0.619 hours <br />0.00368 weeks <br />8.473735e-4 months <br />,
as required
by
plant Technical Specifications.
The
SSPS input excitation fuse was
replaced,
and
STPs I-16 A1, A2, and
A3 were performed to verify SSPS
Train A operability.
At 0015 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />, Train A was returned to
service,
the unusual
event
was exited,
and the load rampdown
was
terminated.
Unit 1 was stabilized at 76K reactor
power before
turbine load was
vamped
back to lOOX power.
During performance of the
STP, the I8C technician positioned the
undervoltage test switch to the off positi'on and proceeded
to the
back of the switchgear relay panel to remove the test leads.
The
technician
moved the door, pinching the leads,
and caused
the
electrical short.
However steps 3.g.4)
and 3.g.5) of STP I-9A
specify the general
purpose multimeter test leads
are to be removed
and then the
RCP undervoltage test switch is to be returned to the
off position.
Had the technician followed the procedure
(and
accidentally pinched the test leads with the test switch in the test
position) the bistables
would not have tripped.
Failure to follow
the steps of the
STP is an apparent
procedure violation (Open Item
50-275/87"23-01).
The inspector attended
the licensee's
Technical
Review Group
(TRG)
session to observe
the licensee's
determination of root cause of the
incident.
TRG participants
concluded
"personnel
error
due to
failure to follow procedures"
was the root cause.
A lack of
procedural
emphasis
on the steps of returning the system to service
was identified as
a contributory cause.
As corrective action to
prevent recurrence,
the technician
was counselled
on the need to
adhere to procedures,
and licensee
management
is considering other
~
(
~
actions.
Additionally, STP I-9A is to be revised to clarify removal
from service
and return to service steps.
Recently,
I8C technicians
have
been responsible for creating several
events involving failure to comply with procedures.
On April 19,
1987,
a
RCP uf relay was determined to be inoperable,
but the
channel
was not tripped due to I8C technician failure to follow a
procedure.
On May 14,
1987,
an emergency diesel
generator
was
inadvertently started
when
an I8C technician did not log a "jumper
wire" as required,
and went beyond his loop test instructions.
PG8E's
June
15, 1987, letter (number DCL-87-136) to the
NRC
delineated corrective actions
taken to assure
procedural
compliance.
Considering this June 15th incident, apparently additional
management
attention to this subject area
may be warranted.
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 ~
Circuit Breaker Corrective Maintenance
On April 12, 1987,
RHR pump 2-2 would not start.
.The problem was
identified on action request
(AR) 0068952,
non-conformance
report
(NCR) DC2-87-EM-N043,
and work was performed
on work order C0012513,
The problem was identified as
a bent bracket
on the closing coil of
the
pump circuit breaker.
The bent bracket allowed spacer
washers
to slip and bind the solenoid plunger which pushes
a lever to close
contacts to energize
the closing spring charging motor.
Repairs
were
made
and the breaker tested satisfactorily
on test power.
Subsequent
operations
of the breaker
were satisfactory.
The
licensee
also
examined
29 additional circuit breakers
to determine
if the problem was isolated:
All 29 breakers
were found to be
satisfactory.
On June 2, 1987, in preparation for reactor vessel
pump down,
pump 2-2 was shutdown
and
pump 2-1 was started to maintain
cooling in accordance
with operating procedure
(OP) A-2-II.
pump 2-2 was to be used to transfer water to the refueling water
storage
tank
(RWST).
When an attempt to start
pump 2-2 was
made,
the
pump would not start
due to malfunction of the pump's electrical
breaker.
The inspector
examined the
pump breaker with licensee
maintenance
management.
It was noted that the solenoid plunger did not operate
smoothly and did, not close the spring charging motor contact.
The mechanics
who performed the corrective action were assembled
at
the breaker
and the corrective action taken in April discussed.
They verified that the plunger (as left) had moved freely after the
bracket repair in April and was not acting freely (differently)
during this examination.
The licensee
prepared
an investigative plan prior to disassembly
of
the plunger solenoid.
The results of that investigation
showed that
the washer pack had slipped laterally, partially binding the
solenoid.
The washer'pack
sl.ipped because
was not fully engaged
in a depression
machined in the surface of the
coil mounting bracket for this purpose.
The inspector
examined the vendor technical
manual for the breaker.
It was noted that there
was
a lack of assembly detail provided by
the vendor.
The licensee
stated that they had, during the previous
year,
purchased further detail drawings
from the vendor but that
these did not provide details of the solenoid assembly,
either.
The licensee
has resolved the breaker
solenoid problem by adjusting
the bracket to ensure
the copper sleeve is fully retained in its
machined
grooves.
Additionally, a licensee
maintenance
engineer
stated that the breaker overhaul
procedure will be revised to
include
a dimensional
requirement for the bracket
and spacer to
preclude
recurrence.
The licensee's
investigative
and corrective
actions
appeared
acceptable.
Leakin
On June 2, 1987,
leakage
was noted from a residual
heat
removal
(RHR) system line while
RHR was in service.
The licensee
made 'a 4
hour reportable
event notification to the
NRC.
The weepage
was from
a weld on a 3/4" vent line on the hot leg recirculation
RHR piping
in containment
(high point vent 2-932).
The weepage
was located at
a sockolet fitting weld to the 3/4" piping.
The licensee
elected to do a thorough root cause
analysis
and
removed (by sawing) the entire weld and
a portion of the sockolet
fitting below it and a portion of the 3/4" pipe above it.
The
removed section
has
been sent off site for analysis for root cause.
The piping was refit to the remaining sockolet
and rewelded.
The inspector
examined the repair weld and found it met visual weld
acceptance
standards.
The license's
investigative
and corrective
actions
appeared
acceptable.
Re air of Incore Instrumentation
Seal
Table
Leaks
The inspector
observed repairs
made to two leaking incore
instrumentation
seals.
The maintenance
was performed in MODE 5,
cold shutdown, with the level in the pressurizer
at approximately
50K.
Since in this condition
a static
head exists at the seal
tabl'e,
the disassembly
and replacement
of the seals
required the
use
of a freeze
seal
on the incore instrumentation
guide. tubes.
The freeze
seal
was accomplished
in accordance
with Maintenance
Procedure
M-89, "Freeze Sealing of Piping."
The coolant
used in
this application
was carbon dioxide.
The inspector
noted that
precautions
were observed.
The precautions
require the freeze
zone
to be in an area free of stress
risers
(welds,
bends, fittings,
etc.).
The. inspector also observed
the replacement
of two seals.
This was
accomplished
according to a contractor procedure
which had been
reviewed
and approved
by the Plant Safety Review Committee.
The
seal
replacement
was
done
by site Mechanical
Maintenance with the
guidance of the contractor.
Mechanical
Maintenance
and the job'
quality control inspector received training from the contractor
which include the use of a guide tube seal
mock up.
The inspector
noted that a quality control inspector
observed
the maintenance
and
gC hold points were met.
In addition,
a special
work permit was
issued for the work and
a radiation technician assisted
in the
operation.
No violations or deviations
were identified.
5.
Surveillance
By direct observati'on
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.
Calibration of the
K3 Constant for the Pressurizer
Pressure
In ut to
the Over
Tem erature Delta Tem erature
Set oint
The inspector
observed portions of a partial performance of
Surveillance Test Procedure
(STP) I-6B2, "Calibration of Pressurizer
Pressure
Protection
and Safeguards
Functions,"
performed
on Unit 2
pressurizer
pressure
channel
PC-457.
The calibration was to
summator
PM-457C which is the channel's
input to the
OTDT setpoint
calculator.
The summator
module was recalibrated to reflect
Amendment
13 changes
to the Unit 2 Technical Specifications
(TS)
regarding the
OTDT setpoint
K3 constant.
The
TS change reflects
an
increase
in the Unit 2 enthalpy hot channel factor for its second
cycle.
A change in the safety limit allows the licensee to reduce
the reactor coolant system pressure
input to the
OTDT setpoint.
The inspector
noted that as found data
was taken
on the summator
module prior to its calibration.
It was also noted that an approved
procedure
was
used
and was followed by the technician.
In addition,
calibrated instrumentation
was
used
and the work was performed with
the knowledge of the shift foreman.
The inspector
independently
verified that the values the summator
module was recalibrated
to
were consistent with the
TS revision.
A
9
b.
Licensee Surveillance
Ins ections
Re uired b
The inspector
examined licensee
surveillances
performed in
accordance
with the ISI program
as detailed in section
6. of this
report.
c.
En ineered
Safe
uards
Valve Interlocks
The inspectors
observed
power production. personnel
perform a portion
of STP V-7B "Test of Engineered
Safequards,
Valve Interlocks
and
Pump Trip from RWST Level Channels."
Interlocks
on various
valves were verified to perform correctly,
by attempting to open
valves
once they had been aligned to pretest positions specified in
the procedure.
Interlock operability was then determined,
based
on
whether or not the valves
moved.
Prerequisites,
specified in the
procedure,
were verified by the inspectors
to have
been
met prior to
performing the test.
Pretest
alignments
were also reviewed.
During testing,
the inspectors
observed
procedural
steps
wer'e being
complied with.
However, the inspectors identified test personnel
had failed to .list initial positions of 13 valves
on Table
DS-4A as
required
by the procedure.
In discussion with the test personnel,
the inspector ascertained
that the valve positions
had
been
verified, but erroneously
not documented
on the table.
The table
was updated to include the information.
A post test review of the
procedure
would most likely have identified this omission.
From
discussions
with the test personnel,
the inspector determined the
individuals were trained
and familiar with the procedure.
No violations or deviations
were identified.
6.
Inservice Ins ection
The inspector
examined three areas'f
ISI in Unit 2 to verify the
inspections
were performed in accordance
with applicable
codes
and
standards.
This examination
was performed
subsequent
to an intensive examination of
the ISI area
conducted in a special
inspection
by Region I personnel
and
independent
measurements
by a
NRC non-destructive
examiner to confirm the
licensee results.
The special
inspection
included
a review of
non-destructive
examination
(NDE) procedures,
the ISI program
(and
changes
and exceptions),
personnel
qualifications,
and completed
data.
The special
inspection also included the performance of non-destructive
examination
by
NRC personnel
using
NRC equipment.
The special
NRC
inspection will be reported separately
(reference
NRC report
50-323/87"16).
For this inspection
however, the resident inspector
observed
the
performance of three ISI examinations
as follows:
1)
An ultrasonic volumetric examination of weld joint WIB-291 on
accumulator injection loop 4 (one inch thick stainless
steel
piping).
The inspector
observed
the calibration process
and the
10
,
inspection
process
and examined the records
generated
as
a result.
All work observed
was performed properly by qualified
NDE examiners;
The examiners
properly recorded
the areas
which were inaccessible
for examination
(due to pipe restraint crush blocks)
and recorded
an
indication believed to be geometric in nature.
2)
A magnetic particle surface examination of longitudinal weld joint
l<ICG 3-1LS on Hain Steam outlet piping on Steam Generator
2-1 was
observed
in part.
Due to a lack of adequate
cleaning,
the licensee
examiners
did not perform the formal examination of record,
but did
perform their calibration
and demonstrated
their inspection
technique for the inspector.
No indications
were observed.
3)
A visual examination of pipe support 412-166SL for
pressurizer
power operated relief valve PCV-455C was observed.
The ISI visual
includes examinations for damage,
debris, corrosion,
wear, bolt
tightness,
snubber settings,
presence
of necessary
washers,
and snubber
alignment.
All inspection results
were satisfactory.
Additionally, the inspector
examined available
code repair/replacement
activities.
For this outage,
the activities included the removal
and
replacement of two accumulator fill fittings which had
a history of
weepage
during operation.
They were cut out for analysis
and replaced
with new material.
Additionally, the RHR'sockolet weld repair was
observed
as described
in the maintenance
section of this report.
No violations or deviations
were identified.
Inde endent
Ins ection
a.
Unit 2 Enhanced
0 erational
Safet
Verification
During its first year of operation,
the Unit 2 operational
aspects
were subjected
to enhanced
operational verification by the resident
and regional staff and supplemented
by team inspection
and the
Augmented Inspection
Team (AIT) involved in the April 10, 1987,
"Loss of RHR" event.
However, since the operation of Unit 2 is
controlled by essentially
the
same procedures,
personnel
and quality
systems
as Unit I, no attempt to separate
the Units has
been
made.
The findings of the enhanced
view of Unit 2 have
been discussed
in
previously issued reports
and will be reviewed in summary fashion
shortly in the upcoming Systematic
Assessment of Licensee
Performance
(SALP).
Since Unit 2 is in its first refueling cycle, the required
enhanced
safety verification period is considered
complete.
The key lessons
derived from the enhanced verification were:
o
Greater
adherence
to the precepts of procedure
compliance is
required.
NRC findings have noted the
need for improved
quality of procedures;
that is, procedures
should
be specific
where specifics
are desired
and general
in areas
where only
general
guidance is required.
Secondly,
procedure
compliance
needs to be emphasized.
On shift operational
personnel
have
the authority to change
the. procedure
but not the authority to
deviate
from it.
Greater formality o'f commun'ications
between the departments
is
required.
NRC findings have
shown problems arising from verbal
transmission of work completion status
between
departments.
Examples
included completion status
work on the containment
door by maintenance
and work planning,
completion status of
work on the rod control system
by I8C, and failure to notify
operations
of an inoperable
underfrequency trip found during an
I8C surveillance test.
Improved operator
awareness
of reportability requirements
is
required.
Throughout the first year of operation of. Unit 2, the
licensee
has
made several
late reports to the
NRC, apparently
due to the need for increased
operator
knowledge in the area of
reporting.
o
Improved formal action plans
subsequent
to events to gather
facts, chart actions
necessary
to fully resolve
problems
identified, and to develop meaningful root causes
are required.
b.
Secondar
Pi
e Wall Thinnin
Pro
ram
As a result of the feedwater pipe rupture incident at the Surry Unit
2 site
on December
9, 1986, the resident inspector inquired into the
Diablo Canyon a'ctions to monitor secondary
pipe wall thinning.
Several
meetings
were held and the following information obtained:
Prior to the Surry event,
Diablo had a secondary wall thinning
program in place.
This program dealt primarily with monitoring wall
thickness
in areas of two phase
flow such
as extraction
steam lines.
This program accounted for such problems
as described
in IE Notice
82-22 and
The program sampled
29 locations for
examination in the first and third refueling outages.
The
examination
done during the first Unit 1 refueling showed
no erosion
evident.
Subsequent
to the Surry event the licensee
established
an Action
Plan
and Task Force to examine potential single phase
flow erosion.
The licensee
prepared
an inspection plan for the Unit 2 first
refueling outage
based
on information obtained
from IE
Notice 86-106, industry guidance
and their
own experience
in fossil
plants.
The licensee
examine
67 locations in the Unit 2 outage including
single phase
and two phase flow locations.
The purpose
was to
obtain baseline
information for future examinations.
Two areas of concern were identified on branch connections
on the
H.P. Turbine Exhaust Line.
Approximately one-third of the pipe wall
'a
~
was eroded in a relatively local area.
Projected
wear rates
indicate
minimum wall thickness
could be achieved prior to the next
refueling outage.
Therefore,
the licensee
performed
a weld repair.
Because of the Unit 2 finding, Unit 1 was examined
and
had
a similar
finding.
The licensee
intends to monitor the Unit 1 location and
develop
a permanent correction for both Units.
An additional erosion location in Unit 2 was identified in an
extraction
steam line to feedwater
heater
81.
The licensee
determined the cause to be a malfunctioning moisture separator.
There
was
a through wall leak at one branch, significant thinning at
another,
but no evidence of erosion at the remaining 4 branch
connections.
Unit 1:locations did not show erosion.
The Unit 2
through wall leak was repaired.
The licensee
task force will continue to monitor developments
in the
erosion area per the licensee
correspondence
examined.
The licensee
management
was queried regarding the secondary
complications of the Surry event, specifically inadvertent fire
protection discharges
and malfunctioning security devices
(due to
the steam environment).
The licensee
stated that these
complications
had been considered
but are not of credible concern at
Diablo.
No violations or deviations
were identified.
8.
Radiolo ical Controls
~
~
~
The inspector
observed radiological controls exercised
in the containment
work described
in this report.
Aspects
observed
included access
control,
radiation protection personnel
monitoring of work areas,
and examination
of the applicable radiation work permits.
The inspector discussed
job
coverage with involved workers
and Health Physics
(HP) technicians.
Individual radiation workers were observed
donning protective clothing,
undressing
and frisking.
Response
to one skin contamination
was
observed,
and health physics actions
were immediate
and proper.
0
The licensee initiated a hot particle program which required special
training on the part of radiation workers
and health physics technicians.
Although fission product particles
have not been
a problem at Diablo,
events at other facilities prompted licensee
management
to initiate the
training program to prepare
personnel
to recognize
and deal with the
problem should it occur.
The residents
attended
both the worker and
health physics training and found it well presented
and informative.
No violations or deviations
were identified.
9.
Licensee
Event
Re ort Follow-u
a.
Status of LERs
Based
on an in-office review, the foll'owing LERs were closed out by
the resident inspectors:
13
Unit .1:
87-06, 87-07,
87-08
Unit 2:
87-07, 87-08,. 87-09
The
LERs were reviewed for event description,
root cause,
corrective
actions taken,
generic applicability and timeliness of reporting.
b.
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.
6/15/87 - Unit 1
NRC DC1"87"TI"N075. 10 CFR 50.73
Initiation of plant report
required for completion
shutdown
due to
SSPS of plant
.
shutdown,
only.
Unit Train A
inoperability was stabilized at
76K power.
No violations or deviations
were identified.
10.
0 en Item Follow-u
Follow-u
Item on Missin
Washers
0 en Item
50-323/86-30-01
Closed
During the Unit 1 refueling outage
(September
through
December,
1986) the licensee identified a wide spread
problem with missing
washers
on piping snubbers.
Washers
are required
between the
paddle
and its brackets to allow + 5 degrees
of
misalignment.
The licensee identified the cause to include
inadequate
snubber reinstallation instructions
and procedures,
the
difficulty of installing washers
in radiation areas
which required
anti-contamination clothing and the failure to recognize that the
deletion or change of washers
is
a design
change.
The licensee
took the following actions to prevent recurrence:
1)
Revision of the testing procedures
(Maintenance
Procedures
M-55. 1,.2,8.4) for Anchor Darling, Pacific Scientific,
and
Grinnel Hydraulic snubbers.
The revision included specific
requirements
for the installation of snubbers.
2)
Revision of Surveillance Test Procedure
Visual Inspection," to provide specific criteria for spacer
washer inspection.
'J
14
b.
c ~
d.
3)
Training of maintenance
personnel,
involved in Unit 2 refueling
outage
snubber work, based
on the revised procedures.
The inspector reviewed the revised
procedures
and found the washer
guidance
included in each to be adequate.
The inspector also
reviewed the snubber training lesson
plan and noted it included
specific training on washer inspection
versus
the washer
installation criteria.
In addition,
the. inspector attended
Technical
Review Group
(TRG) meetings
which discussed
root cause
and
corrective .actions
needed to address
the snubber washer issues.
The
inspector
found these
meetings
thorough in identifying root cause
and establishing
corrective'actions, to prevent recurrence.
Based
on
the above, this item is closed
(Closed 50-323/87-30-01).
Notice of Violation Re ardin
Potentiall
Distractin
Activities in
t e Contro
Room
en Item 50-323/87-12-02
C osed
NRC Inspection
Report 50-323/87-12 identified
a violation of AP
A-103 "Control
Room Access,"
where inappropriate
wording (a form of
distraction)
was put on an annoying,
unused,
flashing annunciator
window located
on
a Unit 2 control
room panel.
PGSE letter number
DCL-87-134 contained
a response
to this violation, and identified
corrective steps
taken to avoid
a repetition of this type of
situation.
These corrective actions,
also identified in IR
50-323/87-12,
have
been
completed
and were found to be appropriate
for the situation.
Accordingly, this item is closed.
Notice of Violation on Timeliness of Problem Resolution
0 en Item
86-18-01,
C osed
NRC Inspection
R'eport 50-275/86-18 cited
a concern
regarding failure
of the licensee to correct
a condition adverse
to quality in a
timely fashion.
In response
to the Notice of Violation, the
li.censee
issued letter DCL-86-241 specifying corrective actions
taken,
and an additional action required to prevent recurrence.
This action
was to ensure that an independent
walkdown or dry run of
a revised
procedure is performed,
as applicable,
as part of the
procedure's
independent verification process.
The inspector verified AP-C3S1 "Surveillance Testing
and Inspection"
was revised to add the statement:
"procedure
changes
that affect the
testing
sequence,
the testing requirements,
or add
new components
should
be walked down in the field to verify workability."
Accordingly, this item is closed.
Notice of Violation Re ardin
Ino erable
Bus
Underfre uenc
Tri
Channe
Returned to Service
0 en Item
50-275/87-13-02
C osed
On April 19, 1987,
one underfrequency
channel
on Unit
1 was not
tripped within six hours of the discovery of its inoperability as
required
by the Technical Specifications.
The event
was caused
by
personnel
error, in that guidance
provided in the "Precautions"
section of the Surveillance Test Procedure
(STP) being performed
was
15
overlooked
and not followed.
Inadequate
communications
between the
plant technician performing the
STP and the control
room operators;
was
a contributing factor to this event.
The inspector
has reviewed the licensee's
June 11, 1987,
response
to
the Notice of Violation contained in inspection report 50-275/87-13
in addition to attending site Technical
Review Group
(TRG) meetings
regarding this subject.
The licensee's
corrective actions
are
as
follows:
o
The individuals involved have
been counseled
on the importance
of procedural
compliance,
including observance
of all
procedural
sections.
o
Surveillance Test Procedure
STP I-9A, "Trip Actuating Devise
Operational
Test,
12 kv Undervoltage,
Underfrequency" will be
revised
by July 15,
1987, to provide additional detail
on the
steps to be taken if a relay is found inoperable.
o
An Incident Summary Report, which is required reading
by
control
room operators,
was prepared
stressing
the importance
of good communications.
o
Administrative Procedure
C-6S4, "Control of Equipment
Required
by the Plant Technical Specifications" will be revised
.by July 15, 1987, to require that the operability of equipment
being returned to service;be verified by the organization
performing the post maintenance
operability check by signing
the technical specification action tracking sheet prior to a
return to operable
status.
The inspector
finds that the corrective actions identified to
address
the issue of miscommunications
between plant personnel
and
the control
room when returning equipment to service to be
acceptable.
However, the issues
of procedural
compliance
and timely
revision to
STP I-9A will be addressed
in conjunction with the
Notice of Violation contained in this report regarding
a June
15,
1987, incident where
an I8C technicians failed to follow STP I-9A.
Based
on the above,
enforcement
item 50-275/87-13-02 is closed.
Follow-u
on the Pro er Im lementation of Vendor Installation
Information Received with Re lacement
Parts
0 en Items
50-275/87-08-01
50"323/87-07-01)
This item was
open
because
the inspector
had insufficient time to
establish
the flow path that ensured
occasional
vendor installation
information reviewed with spare parts
was properly translated
into
installation instructions.
The inspector
met with the Procurement Specialist
Group and
warehouse
personnel
and determined that the intended control process
flowed as follows:
C
16
Parts
received with special
instructions
are noted by warehouse
personnel
and the special
documents
forwarded to
PSG personnel
in
accordance
with "PSG Notebook Entry 850" which is an in house
instruction.
The inspector verified warehouse
receivers
were aware
and
had been trained
on the subject.
The
PSG group receiving such information forwards
such vendor
documentation
to the plant engineering
manager
who in turn is
required to log the document
and send
an information copy to the
appropriate plant department
and to the Nuclear Operations
Support
(NOS) department
in the general office which is responsible
to track
necessary
actions including vendor manuals
changes
through to
completion.
The system is described
in Procedure
NPAP E-14
"Supplier Documentation
and would appear
to eventually provide the
necessary
undated
procedures
to insure satisfactory installation
instructions.
There may be
a problem however during the time this process is
occurring.
Specifically (in the case of the replacement
connecting
rod for the control
room refrigeration compressor originally
questioned
by the inspector)
the part was "dedicated" for use in
August of 1986
by RPE H-0008.
The vendor technical
manual
was in
process of being updated providing the
new installation torque
values in June of 1987.
IIf the part had to be used in the intervening
10 months the part
would be available for use without updated instructions
being
available.
This matter
was discussed
with the manager of NOS and
he
committed to investigate
and determine if corrective action such
as
a "hold" on such
par ts is warranted until such time as the
instructions
are issued.
Secondly the engineer in NECS responsible for the system
was
questioned
whether
he had followed the instructions of procedure
E-14 for notifying NOS of the vendor information received
and
specifica'fly whether
he had initiated the notification form of
procedure
E-14.
In both cases
he stated
he had not and was not
aware of the procedure
E-14 but worked to Engineering
Department
procedures
instead.
This was discussed
with the manager of NOS who
committed to examine the situation
and determine if a problem
existed.
No
This item remains
open pending resolution of the above
conmitments
of the
NOS manager
and the determination
by
WPC whether the part was
installed to the proper torque.
violations or deviations
were identified.
ll.
Im lementation of Securit
Force Strike Plans
On June
16, 1987,
a vote by the bargaining unit members of the United
Plant Guard Workers of America
(UPGWA) failed to ratify a labor agreement
between
UPGWA and American Protective Services
(APS).
Accordingly,
UPGWA
sanctioned
a strike of APS bargaining unit employees
which began at 0400
hours
on June
17, 1987.
Security personnel
employed
by APS predominately
perform non-security plan functions outside the protected
area,
but also
17
fill selected
security plan required positions.
The inspector
reviewed
the licensee's
activities in preparation for the impending strike.
Staffing of all security plan required positions
(by non-striking General
Construction
(GC) security officers,
PGKE armed responders,
and security
supervisory
personnel')
was reviewed,
and found to be adequate.
Upon
strike implementation,
various audits
and security system status
assessments
were
made
by the licensee.
Approximately 200 badge
packets
were identified as having been
placed in incorrect
badge rack locations.
This was the only apparent
attempt
by striking security personnel
to
disrupt security activities during the strike.
Picketing of the job site
entrances
began at 0400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br />
on June
17, 1987,
and continued for the
duration of the strike, without disrupting entering or exiting vehicles.
For informational purposes,
this event
was reported to the NRC's
Operations
Center at 0940 hours0.0109 days <br />0.261 hours <br />0.00155 weeks <br />3.5767e-4 months <br />.
The licensee
informed the inspector all
GC security officers had been
"Appendix B" certified.
Selected
security functions were observed
during
the strike duration,
and were found to be satisfactory.
At approximately
1230 hours0.0142 days <br />0.342 hours <br />0.00203 weeks <br />4.68015e-4 months <br />
on June
19, 1987, the contract
was ratified and normal
security staffing was obtained at 2230 hours0.0258 days <br />0.619 hours <br />0.00369 weeks <br />8.48515e-4 months <br />.
The return to work was
without incident.
.
Detailed descriptions
on this event are withheld due to its designation
as security safeguards
information.
No violations or deviations
were identified.
Licensee
Res
onse to IE Bulletin 85-03, "Motor-0 crated
Valve Common Mode
Far ures...
In response
to portions of NRC Temporary Instruction 2515/73,
the
inspector
observed
technicians setting valve operator limit switches
and
torque switches
on motor operated
valves
(MOVs) SI-2-8804B and
RHR-2-9003B.
Adjustments to MOV SI-2-8804B were previously described
in
section 4.b of NRC Inspection
Report 50-323/87-20.
Work on .RHR-2-9003B
was performed in accordance
with Action Request
A75289 and Work Order
C14370.
Torque switch adjustments
were performed utilizing Maintenance
Procedure
(HP)
E 53.10B "Limitorque Operator Torque Switch Adjustment"
and
E 53.10D "Limitorque Operator Limit Switch Adjustment."
Operator
housings
were found to be free of rust and moisture,
and contacts
wert
clean
and free of corrosion.
Where possible,
the inspector also verified
correct lubricants were being used.
In total,
17
MOVs had their limit
and torque switches adjusted.
The licensee
indicated
as found limit and
torque switch settings
(with the valves not necessarily
under full delta
p) were within tolerance.
HP M-51.13 was also reviewed to verify the procedure
required staking of
the lock nut for the operator
stem nut.
Documentation
regarding
use of
Durez, Melamine,
and Fibrite material in the switches
was also reviewed
by the inspector.
No violations or deviations
were identified.
r
18
13.
Exit
On June
26,
1987,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph I.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.