ML16341E326
| ML16341E326 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 06/22/1987 |
| From: | Johnston K, Mendonca M, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E327 | List: |
| References | |
| 50-275-87-20, 50-323-87-20, NUDOCS 8707140394 | |
| Download: ML16341E326 (46) | |
See also: IR 05000275/1987020
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report
Nos:
50-275/87-20
and 50-323/87-20
Docket Nos:
50-275
and 50-323
License
Nos:
Licensee:
Pacific Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Diablo Canyon Units 1 and
2
Inspection at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
April 26 through
May 30,
1987
L.
M. Padovan,
Acting Senior Reside t Inspector
K.
E. Johnston,
Resident Inspector
Approved by:
M.
M. Mendonca,
Chief, Reactor Projects
Section
1
p/z- ~/P w
Date Signed
Date Signed
g /z.~pi ~
Date Signed
Summary:
Ins ection from A ril 26 throu
h Ma
30
1987
Re ort Nos.
50-275/87-20
and
Areas Ins ected:
The inspection
included routine inspections
of plant
operations,
maintenance
and surveillance activities, follow-up of on-site
events,
open items,
and 1'icensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
30703,
60710,
61720,
61726,
62703,
71707,
90712,
92700,
92701,
92702,
and 93702 were applied during
this inspection.
Results of Ins ection:
Three violations and
no deviations
were identified.
8707140394
870h22
ADQCK 05000275
8
DETAILS
1.
Persons
Contacted
2.
J.
D. Shiffer, Vice President
Nuclear
Power Generation
"R.
C. Thornberry, Plant Manager
R. Lieber, Construction Superintendent
"J.
A. Sexton, Assista'nt Plant Manager,
Plant Superintendent
"J.
M. Gisclon, Assistant Plant Manager for Technical
Services
J.
D. Townsend, 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
M. J.
Angus,
Work Planning Manager
D.
A. Taggert, Director guality Support
T. J. Martin, Training Manager
W.
G. Crockett, Instrumentation
and Control Maintenance
Manager
J.
V. Boots, Chemistry and Radiation Protection
Manager
~L.
F.
Womack, Operations
Manager
"T. L. Grebel,
Regulatory Compliance Supervisor
S.
R. Fridley, Senior Operations
Supervisor
R.
S. Weinberg,
News Service Representative
D.
A. Malone, Senior I8C Supervisor
"M. W. Stephens,
I8C General
Maintenance
Foreman
The inspectors
interviewed several
other licensee
employees
including
shift foreman
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
- Denotes those attending the exit interview.
0 erational
Safet
Verification
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)
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 other
plant personnel.
The discussions
centered
on pertinent topics of
general plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
Unit 2 Restoration of Mid-Loo
0 eration
As described in Section 3.d. of NRC Inspection
Report 50-323/87-12,
on April 10, 1987, while Unit 2 was in cold shutdown with the hot
legs at mid-loop, both residual
heat
removal
(RHR) pumps were shut
off due to unanticipated
vortexing.
To preclude future interruption
of RHR flow while the plant was at mid-loop operation,
the licensee
submitted
an action plan to the
NRC (PG&E May 4, 1987, letter
DCL-87-099) for items to be completed prior to resumption of
mid-loop operation.
Via confirmatory action letter EA-87-67, dated
May 6, 1987,
NRC Region
V documented
the understanding
that Unit 2
would not be returned to mid-loop operation until the
NRC staff
concurred in the appropriateness
and adequacy of the actions
described in the licensee's
May 4, 1987, letter.
On May 18, 1987,
the licensee
forwarded
a supplemental
letter (DCL-87-113) indicating
a second charging
pump would be available for operation during the
upcoming mid-loop operations.
In order to assess
the status of completion of the licensee's
actions,
the inspectors
reviewed licensee
documents
and hardware
installations for compliance with the "Actions Completed or to be
Completed Prior to Resumption of Mid-Loop Operation" section of
Modifications to Reactor Vessel
Refueling Level
Indication Systems
(RVRLIS) were observed
in the field, and stated
enhancements
to Operating
Procedures
(OPs)
AP-16 and A-2:II
(including availability of a second charging
pump)
and control of
work activities were verified to have
been
completed.
The
inspectors
also observed
a presentation
(given to each operating
crew) by J.
D. Shiffer, Vice President
Nuclear
Power Generation,
on
the subject of PG8E's policy regarding compliance
and adherence
to
procedures.
Regarding the "Additional Training" commitment (Item 8 of
OCL-87-099), the inspector verified operations
personnel
had
received training on the
OPs.
However, the inspector identified the
training provided
on
RHR half-loop operations utilized a training
guide which was roughly equivalent to revision
0 of the
OPs.
In
response
to commitments provided in the licensee's
May', 1987,
letter,
OPs A-2:II and AP-16 had both been
updated
through revision
number
2 to incorporate
changes
in plant operational
requirements
and emergency
response
actions.
It was not clear that training had
been provided to the operating
crews
on the revised
OPs.
In discussing
the matter with the operation
s manager,
he indicated
the differences
between
the original procedures
and later revisions
would be discussed
at the tailboard conducted
by the
SFM during
shift briefings.
Subsequent
discussions
between the
NRC and
PG8E
management
resulted in a commitment from the licensee to have
operations
management
personnel
review each step of the revised
procedures
with each operating
crew and specifically discuss
the
revised steps, prior to permitting the crew to operate
the unit at
mid-loop conditions.
The inspector witnessed
one session
of this
training,
and found the commitment was complied with.
Accordingly,
via letter dated
May 30, 1987, the
NRC rescinded its May 6, 1987,
confirmatory action letter and granted concurrence for Unit 2 to
return to mid-loop operation for the current outage.
No violations or deviations
were identified.
3.
Onsite Event Follow-u
ao
S ill of a Small
uantit
of Radioactive Water
On May 23, 1987, after replacement
of Unit 2 'post-loca
sampling
panel
PM-80, four mechanical
maintenance
personnel
conducted
a
hydrostatic test
on the Nuclear Steam Supply System
(NSSS) primary
water sample
system in the Unit 2 post-accident
sampling
room.
While walking down the system,
personnel
observed water dripping
above the
PM 80 panel
from a stainless
steel
tubing compression
fitting.
A 12 inch puddle of water had formed under the panel.
The
hydrostatic test was stopped,
the line was depressurized
and
Radiation Protection
(RP) technicians
were notified of the
situation.
Upon reaching the scene,
the
RP technician
observed
about
one cup of
water
on the floor under the panel
and sent
a maintenance
worker to
get more decontamination
supplies.
The
RP technician
surveyed
a rag
used to soak
up
some of the water and found it reading
more than
50,000 counts per minute
(CPM) (about
20 millirads beta)
on his
fisker.
A foot print was observed
next to a tygon drain line going
to the floor drain,
and accordingly, the technician
suspected
shoe
contamination.
The water apparently
had run along the underside of
the tygon hose
and had gone unnoticed.
The technician
stopped
the
work and kept personnel
from spreading
the contamination.
Access
control
was notified of possible contamination of the 85 foot
elevation level,
and access
to this area
was stopped until the
extent of the contamination
could be determined.
One of the workers
was stationed to keep personnel
out of the area,
while the
technician went to get an air sampler
and radiological contamination
posting supplies".
The results of the air sample
were 0.02 Maximum
Permissible
Concentration
(MPC).
Plastic booties
were issued to
personnel
in the area.
Surveys of the four worker's
shoes
were
negative,
except for one which indicated contamination of 500 net
CPM on the left sole
and 1500 net
CPM right sole.
The shoes
were
decontaminated
and returned to the owner.
Mith access
to the contaminated
areas
under control, survey and
decontamination
of the affected areas
was started.
Originally,
contamination
was found in the Unit 2 hallway, secondary
system
sample area,
and into the west half of the penetration
area.
The
areas
were wet mopped,
resurveyed
and areas of contamination
reduced
to a final area of about
200 square feet next to PM-80.
Additional
areas
surveyed for contamination
were performed in the Unit 1
hallways
and stairways leading to the 85 foot elevation.
No
smearable
contamination
was found in these
areas.
Unit 1 Steam Generator
S/G
Pin'Movement
and Oil Leak
As described
in Licensee
Event Report
(LER) 1-86-13, in September
1986
S/G snubber
load pins were found to have
moved out of position.
As corrective action, the licensee installed pin capture
end plates
and established
a program to measure
pin displacement
once per
quarter.
In response
to this quarterly inspection
commitment, the
pins were measured for movement in January
1987 and
on May 12, 1987.
On May 12, mechanical
maintenance
personnel
discovered pin movement
on the southeast
snubber of S/G 1-2.
An assessment
team was formed
to investigate
and quantify the pin movement.
Results of the
assessment
indicated the pin had moved about 0.6 inch away from the
measuring
hole in the capture plate,
and the pin had rotated about
10 degrees.
The set screw was found to not be tight against the
pin.
As indicated in LER 1-86-13, the licensee is committed to
continue tracking pin movement.
The resident inspector
requested
the licensee to submit a revised
LER to the
NRC providing updated
information on the pin dislocation.
While= inspecting the load pins, maintenance
personnel
also checked
level in the snubber oil reservoirs.
On S/G 1-2, the
common
reservoir for the four snubbers
was found to be low and two-to-three
gallons of oil was observed
on the floor under the snubber.
Maintenance
personnel
determined
the snubber's test plugs were the
source of the leakage.
The tubing line from the oil reservoir to
the southeast
had air entrainment,
and thus the snubber
was
technically inoperable- for an indeterminate
length of time.
The snubber
was determined to be one of two snubbers
tested
by Paul
Monroe personnel
during the Unit 1 refueling outage.
Testing
required
removal of the test plugs
and the special silver-plated
stainless
steel
washers
were not replaced with new washers
by Monroe.
In discussions
with Paul
Monroe, the licensee
concluded the
snubber'ould
be returned to operable status
by venting and fillingwith
hydraulic oil.
The vendor indicated
no damage to the snubber resulted
from air entrainment,
and the snubber would not have locked up
(potentially overstressing
RCS piping).
Venting and filling of the
was completed,
new washers
were installed in the test plugs,
and all other fifteen S/G snubbers
were checked for leakage.
All
other snubbers
had
no oil loss. This issue will be carried
as
an
unresolved
item pending resolution of snubber operability
(50-275/87-20-03).
Unit Tri
Due to Line Differential Current Rela
Actuation
On May 11, 1987, while at about 40 percent
power for demusseling
operations,
Unit 1 experienced
a unit trip and subsequent
generator/reactor trip from an inadvertent actuation of line
differential current relay 587L-I.
The appropriate
emergency
procedures
were followed and the unit was stabilized in Mode 3.
A shunt reactor
had failed at the licensee's
Midway substation
causing
on the 500
KV transmission
system.
This
was propagated
to the Diablo Canyon switchyard where the
line differential current relay incorrectly actuated
causing
a unit
trip..
The tie line differential relay senses
current flow leaving
the generator
banks
and current flow entering the
500
KV substation.
If the current leaving one end of the line
differs substantially
from the current at the other end of the line,
the relay will initiate a unit tr ip.
The licensee's
Substation
Department investigated
the cause of the
indiscriminate relay actuation.
The root cause of the differential
relay actuation
was indeterminate
and remained
under investigation
by the Substation
Department.
To prevent recurrence,
the unit trip
signal provided by the tie line differential relay was
removed from
service
pending resolution of the cause of the tie line differential
signal.
Since the tie line differential relay was not taken credit
for in the
FSAR, and
has redundant
backup protection,
the licensee
deemed this action to be satisfactory.
Inadvertent
Containment Ventilation Isolation
from Plant Vent
Monitor RM-14A
On May 18, 1987,
an Instrumentation
and Controls (ISC) technician
inadvertently
caused
a CVI while performing Surveillance Test
Procedure
(STP)-107B3 "Radiation Source Presentation
(Isotopic)
Calibration of Miscellaneous
Area Radiation Monitors...RM7..." on
Unit 2 incore seal table radiation monitor (RM)-7.
Voltage to the
RM drawer
and detector high voltage had been de-energized
by
removing the power fuses
on the front of the radiation monitor
panels.
When reconnecting
the detector signal
cable in accordance
with step 3.n.l of STP-107B3,
a small electrical
arc occurred
from
what appeared
to be residual
voltage in either the drawer or the
'etector.
The arc caused plant vent radiation monitor 2-RM-14A to
spike, causing
the CVI.
In discussions
with the
I8C technician,
the inspector
concluded this
event was not caused
by any error or carelessness
on the part of the
technician.
The possibility of grounding (to remove residual
high
voltage) the drawer high voltage supply and detector cable prior to
reconnecting
the cable
was discussed
with licensee
management.
The
licensee
concluded this practice would not be advantageous
as
a
spark would be drawn during the grounding process,
creating the
possibility of another
CYI.
However,
as
a result of the NRC's questioning the validity of the
licensee's
root cause analysis,
further investigations
were
performed by the licensee.
These investigations
discovered that low
voltage cables for the radiation monitor remote meter,
the "GMI"
circuit, and
AC power to the local alarm were not deenergized.
These circuits were the source of electrical
power to produce the
spark, rather than "residual voltage"
as the licensee previously
thought.
This example denotes
the
need for a reassessment
of the
adequacy of your root cause analysis
techniques.
STP I-207B3
specified that the channel
to be calibrated
was to be deenergized.
In this instance,
the instrument
power fuses
were removed,
but the
control power fuses
located at the rear of the panel
were not.
This
provided the remaining
AC power at the connector.
Also, the routing
of the interconnecting detector cable
made mating of the connector
extremely difficult.
To prevent .recurrence of this situation,
the cable
was rerouted to
simplify the mating process.
A second corrective action was to
instruct all
IKC personnel
that when
a procedure
specifies
deenergization
of a channel,
the intent is to deenergize
both
control power and instrument power,
unless specified otherwise.
The
third corrective action to be performed
by the licensee is to review
and evaluate all radiation monitoring calibration procedures
for
possible clarification of deenergization
and energization
statements.
In order to partially solve the problem of spurious
CVIs, the
licensee
issued
design
change
(DC) 2-OJ-40119 to change
the time
constant in several
radiation monitors to slow down the response
time of the detectors
and enable
them to be less sensitive to
disturbance
and noise.
The resultant delay in response
time is less
than .1 of the total channel
response
time,
and according to the
licensee, will still meet the Technical Specifications
required
response
time for the radiation monitoring system.
This event,
and other spurious actuations,
are also being studied
by
the licensee's
Noise Reduction Task Force in an effort to determine
cause
and effective corrective action to prevent reoccurrence.
Additionally, a Radiation Monitoring System
Upgrade
Program to
replace existing radiation monitors that cause
CVIs has
been
instituted.
The replacement
radiation monitors are to be more
reliable
and less sensitive to electrical
noise.
Inadvertent
CVI from Induced Noise
On May 15, 1987,
a Unit 2 CYI occurred
as
a result of an
unidentified electrical perturbation
on an instrument
AC power bus
.
to plant vent RM-14B.
Numerous control
room alarms,
powered
by the
identical instrument
AC bus,
were received
and immediately cleared.
Accordingly, the licensee
contributed the cause of the momentary
perturbation to momentary shorting of the bus from maintenance
activities in the plant.
The corrective actions
taken
by the
licensee to prevent re-occurrence
are identical to those described
in the above
CVI for plant vent monitor RM-14A.
f.
Intermediate
Ran
e Hi
h Flux Reactor Tri
On May 11, 1987, with Unit 1 in Mode 3,
STP I-3A "Calibration
Procedure for Intermediate
Range
Channel"
was being performed
on
intermediate
range
channel
N-35, in preparation for restarting the
unit.
Mhile the channel
was being tested,
a control power fuse
on
that channel
blew, causing
an intermediate
range high flux trip on
protection channel
1.
This in turn caused
an intermediate
range
high flux reactor trip, which caused
reactor
main trip breakers
A
and
B to open.
I
The control power fuse blew just as the simulated input test signal
reached
the P-6 setpoint
and flashed the P-6 bistable.
The fuse was
replaced with a similar correctly sized fuse,
and the identical
calibration process
was repeated at least six times in an attempt to
determine if the fuse would blow again.
No failure of the fuse
occurred.
Functional test
STP I-3A was then completed with no
further interruption.
In analyzing root cause of the event,
the licensee
determined the
fuse failed due to "end-of-life," documented
the fuse failure,
and
included the fuse in a data
base for trending.
Failure of this fuse
had not occurred before.
The inspector questioned
licensee
management
as to whether
a more
indepth root cause analysis
would be more appropriate.
Further
examination of the fuse by X-rays to determine if the fuse
had
previously approached
the point of failure and possible
comparison
of electrical
loads
between
IR channels
at the P-6 setpoint were
suggested
by the inspector.
The licensee
agreed to evaluate
the
benefit of further investigation.
The blown fuse replacement policy at Diablo Canyon is that when
a
blown fuse is encountered:
1.
A determination is made
as to whether or not this has
been
a
recurring situation;
2.
A visual inspection for damage
and burned material
odor check
are made;
and
3.
If fuse failure is determined to be recurring or there is
evidence of damage,
indepth analysis
and corrective action are
required prior to returning equipment to service.
However, if fuse failure is determined to not be recur ing, and
there is not indication of damage or degradation,
the fuse
may.
be replaced with the appropriate
rated fuse.
The equipment
then functionally checked
and returned to service.
In all
cases
an Action Request is initiated to document the incident.
The licensee
investigated
the blown fuse replacement policy at
six other operating nuclear generating stations.
Five of those
consulted indicated their-policy was in agreement with Diablo
Canyon policy.
One licensee
indicated that, in some cases,
a
root cause
analysis
was performed
on the equipment, prior to
returning the equipment to service,
following the first
incident of a blown fuse.
Based
on a industry experience that
some fuses
do age,
resulting in their below rated value
open circuiting, and that
Diablo Canyon's policy is in keeping with the industry
standard,
the licensee
concluded that their policy will not be
altered.
However, the licensee
also concluded
steps
are to be
initiated to assure
the existing policy regarding documentation
of blown fuses is clearly presented
to all maintenance
and
operating personnel
on
a recurring basis.
g.
Inadvertent Start of Emer enc
Diesel Generator
2-1
On Hay 14, 1987, at 1021 hours0.0118 days <br />0.284 hours <br />0.00169 weeks <br />3.884905e-4 months <br />,
an I8C technician inadvertently
started Unit 2 Emergency Diesel Generator
(D/G) 2-1.
The technician
had been instructed to perform the portions of I&C loop tests
associated
with diesel
generator
alarms
and annunciators.
Loop
tests
are the procedures
used
by I8C for the calibration
and testing
of instrumentation
and controls not accomplished
by a Surveillance
Test Procedure.
Although the Work Order related to the loop tests
required shift foreman 'approval, there
was
no clearance
issued for
D/G 2-1 so the loop tests
were performed
on an operable diesel
generator.
The technician
had been attempting to perform the loop
test (LT 21-19C) for jacket water pressure
'switch (PS)
229.
The
loop test
he had been issued
had
a significant error in that there
was
no direct annunciation
associated
with PS 229.
The portion of
LT 21-19C that required the annunciation testing
was related to
PS
227 and
PS 236.
This portion had been included in LT 21-19C when it
was written, due to a computer file transposition error.
The errant
loop test
was independently
reviewed
and approved
by an I8C
engineer,
and again approved
by the
I8C general
foreman for use.
To compound
an already undesirable situation,
the
I&C technician
attempted to perform the loop test,
despite its obvious errors,
without stopping the work activity and consulting his supervisor.
PS 229 is in series with a set of contacts
related to engine start
relay ESRlA.
When both sets of contacts
are
made
up they energize
jacket water pressure
relay JWPRl and
JWPR1A.
The technician
was
misled to believe,
by the loop test, that
he needed to energize
JWPR1
8
1A to accomplish the annunciation.
To do this, the
technician realized
he needed to jumper the contacts for ESR1A.
The
I8C technician
proceeded
to jumper the contacts without this action
being specifically addressed
in the loop test.
When the desired
results
were not achieved, i.e.
no annunciation,
he
assumed
his
problem was
an inadequate
jumper across
the contacts
related to
ESR1A.
Without a specific instruction in the loop test,
the
technician manually tripped
ESRlA to make
up the contacts.
Tripping
ESR1A started
D/G 2-1.
It should
have
been apparent to the I8C technician that the work
required to energize
JWPRl 4 lA was not described in LT 21-19C.
Having realized this,
he should
have stopped
work and discussed
the
loop test with his supervisor.
The first indication to the
technician that
LT 21-19C was inadequate
was that to energize
JWPR1
8
1A a jumper had to be placed across
contacts
on ESRIA.
This was
not described in the loop test.
Administrative Procedure
AP C-4Sl
"Mechanical
Bypass,
Jumper
and Lifted Circuit Log Accountability
System:
in the General
section,
paragraph
E states:
"1.
Momentary jumpers
do not require logging on a formal jumper log
but shall
be listed on the...Momentary
Jumper Status
Sheet.
2
Momentary jumpers shall
be controlled by an approved procedure,
work order,
shop work follower, or clearance
request."
Therefore, to place
a jumper on the electrical
equipment of an
operable diesel
generator,
logging and control of the jumper
was
required.
This is an apparent violation (Open Item
50"323/87-20-01).
The second indication to the technician of the inadequacy of LT
21-19C is that it did not require the operation of ESRlA. If the
technician believed this was required to complete the loop test,
he
should
have consulted his supervisor.
A technician
should not,
operate
relays
on operable
safety related
equipment
unless
explicitly directed to by procedure.
As corrective action the
concerned
individual was counselled.
In addition, the licensee
has
undertaken
a program to instruct all plant personnel
on the
importance of procedural
compliance.
As stated previously,
LT 21-19C included
a significant error, in
that portions of. another
loop test
had been included with it.
This
error misled those issuing the test to the field to believing there
was
an annunciator
associated
with PS 229.
Had there not been
an
annunciator test portion of LT 21-19C, the test would not have
been
issued to the field.
A second
weakness
in the loop test is it did not include
a
prerequisite to have the diesel
declared
inoperable for the test.
PS 229 performs
a safety related function, redundant with PS 230, to
energize jacket water pressure
relays
JWPR1 and lA, when the jacket
water pressure
reaches
operating pressure.
Among other functions,
JWPRl and lA supply signals to shut the starting air solenoid valves
and to flash the generator field.
With the jumper installed, if PS
229 failed high (with it contacts
closed)
JWPR1 and
1A would
10
energize
immediately placing the diesel
generator
in a possibly
inoperable condition.
Loop test
21-19C was generated
as
a result of the loop test writer'
guide Administrative Procedure
AP C-454 "Instrumentation
and
Controls
Loop Test Program."
AP C-454 was issued in July 1986, in
an effort to upgrade
the loop test program, in response
to gC
findings of the inadequacy of the loop test program.
The guidance
provided in AP C-454 appears
to be adequate
to generate
loop tests
appropriate to the circumstances.
However, the adequecy of the
implementation of AP C-454 is questionable
in light of LT 21-19C.
As corrective action with regards
to the inadequacy of LT 21-19C,
the licensee
has initiated the following corrective Wtjons:
1.
A review of associated
loop tests for the
same data sheet error
contained in LT 21-19C.
2.
A discussion with all loop test originators
and reviewers
on
how the transposition error occured.
3.
A review of the conformance of the loop test program to ANSI
N18.7 1976Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7 1976" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. and the development of an action plan to review all
safety related
loop tests
based
on the review of the program.
The inspector
has found, in general, that the quality of loop tests
has. suffered in the effort to produce the numbers required for the.
current refueling outage.
The licensee's
corrective actions related
to the adequacy of the loop test program will be tracked
as
an
unresolved
item (Open Item 50-323/87-20-02).
D/G 2-1 was inadvertently started at 1021 hours0.0118 days <br />0.284 hours <br />0.00169 weeks <br />3.884905e-4 months <br />.
It's actuation
was
immediately apparent
in the control
room and was recorded in the
control operator's
logs.
10 CFR 50.72(b)(ii) requires that the
licensee notify the
NRC within four hours of any event or condition
that results in manual or automatic actuation of an Engineered
Safety Feature
(ESF).
The shift foreman
on duty did not recognize
the inadvertent diesel
generator start to be reportable
and,
accordingly, did not make
a report to the
NRC until 1615 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.145075e-4 months <br />
(after it was identified by his supervisor
as reportable).
Another
recent
example of weakness
in the operations
department's
implementation of reporting requirements
for events
was the late
reporting to the County of San Luis Obispo of the main turbine fire.
The late reporting of the diesel start event is an apparent
violation of 10 CFR 50.72.
(Open Item 50-323/87-20-03).
Vortexin
of RHR
Pum
2-2 Durin
Cavit
Draindown
On Hay 12,
1987, in preparation to replace
a source
range detector
on Unit 2, operators
were pumping down the water level in the
reactor vessel cavity, transfer ring the water to the Refueling Mater
Storage
Tank (RMST) at about 3,000 gallons per minute (gpm)
utilizing Residual
Heat
Removal
(RHR) pump 2-2.
An operator
was
stationed
inside containment to visually observe water level in the
11
cavity.
The wide range
and narrow range reactor vessel
refueling
level indication system
(RVRLIS) was available to operators
in the
.
control
room.
Operating
Procedure
(OP) B-2:VI was in use to control
the pumpdown,
and specified that the
RHR pump was to be stopped
when
water level in the reactor vessel
reached
the 113'levation
as
indicated
by RVRLIS.
A disparity between
RVRLIS and actual
observed
cavity water level
was identified when wide range
RVRLIS indicated
115 1/2'hile actual
observed
level inside containment
was reported
to be 117'.
Discussions
were held on the Shift Foreman
(SFM),
Senior
Control Operator
(SCO),
and Control Operator
(CO) level in an
attempt to identify the cause of the disparity.
However,
pumpdown
was allowed to continue
as the disparity increased.
When
RVRLIS
reached 113'levation,
10 minutes after identification of the
disparity,
RHR flow was throttled back, but the
RHR pump was not
stopped
as required
by OP B-2:VI.
Operators
assumed
indicated
RVRLIS water levels were incorrect,
since
an operator inside
containment
was directly visually identifying cavity water level.
Over the next
2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period, the
RHR pump was allowed to vortex
twice,
even though discussions
and assessments
were conducted
by the
operators
on at least three occasions for periods varying from 6
minutes to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
However, having not stopped
RHR pump operation
once water level indication disparities
were observed,
and failure
to obtain upper management
review and concurrence of a systematic
approach for problem resolution of a first-of-a-kind problem prior
to continuation of plant evolutions are considered
to be improper
operation of the facility outside established
procedural
guidelines.
Due to the complexity of this event,
a detailed description is
provided below.
In preparation to replace Unit 2 source
range detector
N-31, water
in the refueling cavity was to be pumped to the
RWST by
RHR pump 2-2
discharging through the
RHR heat exchanger
and valve 8741
(RHR
return to RWST).
Normal
RHR system discharge
to loop 3 and 4 cold
legs
was to be isolated,
and cavity pumpdown rate
was to be
controlled using HCV-637 (RHR Hx 2-1 outlet flow control valve) with
RHR pump 2-2 recirculation valve in automatic.
An
On-The-Spot-Change
to
OP B-2:VI "RHR - Draining the Refueling
Cavity" was issued
and approved to control the evolution.
Precautions
were included in the procedure to caution against
dropping the water level in the reactor vessel
to the point where
suction to the
RHR pumps could be potentially lost.
The reactor
was
to be completely defueled prior to initiating cavity draindown.
Narrow range
RVRLIS was to be enabled
and hooked
up to a multipoint
recorder,
and providing low level alarms.
OP B-2:VI specified
once
water level in the refueling cavity was lowered to about
one foot
above the reactor vessel
flange, the refueling cavity pumpdown rate
was to be throttled back using HCV-637.
OP B-2:VI further directed
that when water level
was lowered to about
1 foot below the reactor
vessel
flange (approximately
113 foot elevation
on RVRLIS or tygon
tube indication),
RHR pump 2-2 was to be stopped
and final vessel
pumpdown
was to be accomplished
using the refueling water
purification system.
12
From an initial cavity water level of about 138'elevation)
cavity
pumpdown was initiated,
and continued at a rate of approximately
3,000
gpm.
Wide range
RVRLIS LI-956 indicated agreement with the
"Reactor Vessel
Refueling Level" alarm received at 137'".
The
trend recorder
read
1 1/2" less.
The cavity water level
was being
observed
by an operator stationed
inside containment to confirm
control
room indications.
The temporary narrow range
RVRLIS
recorder
was not functioning (in violation of the procedure)
and I8C
technicians
were investigating the problem.
At 115'" wide range
RVRLIS, the watch inside containment reported water level to be
'117'.
Possible
causes
for the 1 1/2'isparity were discussed
by
operations
personnel
as
pumpdown continued.
It was decided that a
correlation check between
RVRLIS and visual level could be
accurately~erformed
only at the vessel
flange level.
Wide range
RVRLIS incficated
a level of 114', but visually the level appeared
to
116 1/2'a
2 1/2'isparity).
Pumpdown flow rate
was not throttled
at 115'ince visually the level
was at 116 1/2'nd the operators
questioned
the accuracy of the
RVRLIS.
Shortly thereafter,
wide
range
and narrow range
RVRLIS both indicated
113 1/2'hile the
watch reported
a 116 1/2'evel (disparity increasing to 3').
HCV-637 was closed
and
FCV-641B then opened in automatic,
placing
RHR pump
2-. 2 on recirculation.
This was contrary to the
May ll,
1987,
OTSC to
OP B-2:VI, which specified in step
14 that
RHR pump
2-2 be stopped at "approx. 113'VRLIS on tygon tube indication."
At this point,
RVRLIS alarm setpoints
were changed
from wide range
values to narrow range values of 107'" (low) and 113'" (high).
Discussions
regarding discrepancies
between indicated level
and
observed
level continued for about
an hour and centered
around
possible
causes
such
as
improper venting, valve lineups,
and
instrumentation errors.
An auxiliary building auxiliary operator
(AO) was sent into containment to verify RVRLIS lineup.
Inside
containment,
the watch indicated level dropped about
3 inches but
was still at about 116'o
116 1/2'.
RWST level trended
up very
slowly and
RVRLIS still dropped but at a much slower rate.
The
SFM,
SCO and
CO agreed that the continued
change in levels
was
due to
leakby past the seat
on butterfly valve HCV-637, causing about 200
gpm flow to still be going to the
RWST.
A decision
was
made to
allow RHR pump 2-2 to continue to run on recirculation to allow
visual cavity level to slowly drop to reactor vessel
flange level
(114'levation) at the rate of about 200
gpm.
The auxiliary
building AO reported that the
RVRLIS lineup inside containment
was
good.
A senior reactor operator
(SRO) was sent into containment to
independently verify the
RVRLIS lineup was correct.
I8C was still
unable to get the temporary
RVRLIS recorder to work.
At about
1 1/2 hour s after the first discrepancy
between
RVRLIS and
direct visual indication inside containment
was noted,
an
approximately
4 amp fluctuation of the
RHR pump 2-2 motor was
observed
by the
SFM, and the
pump was shutdown.
RVRLIS indicated
107'hile the watch inside containment
reported the cavity water
level at 116 1/2'.
The
SRO inside containment
doubted cavitation of
the
RHR pump since water remained in the cavity.
During the next
forty minute period, the
SRO inside containment
checked
the
RVRLIS
13
lineup and found it to=be satisfactory,
while the auxiliary AO
vented
RHR pump 2-2 and found little air in the pump.
Simultaneous.
discussions
were held in the control
room to address
the discrepancy
between
RVRLIS and actual
observed
level in the cavity.
Since
no
fuel was in the reactor,
the
SFM concluded that additional plant
evolutions should
be performed at that time to indentify and correct
whatever procedural
or indication problems
were causing the
discrepancy.
The limiting factor to the evolutions
was to protect
the
RHR pump from damage.
Inside containment,
the
SRO placed the
tygon tube level
guage in service.
The refueling water purification pump was started to pump water
from
the refueling canal to the
RWST, and cavity water was lowered to
114'.
Concurrently, for about six minutes,
discussions
continued
on
the
RVRLIS indication problem.
One possible explanation
given for
the fluctuating amps
on the
RHR pump was that the
pump recirculation
valve (FCV-641B) might have
been cycling due to flow being near the
valve's flow control setpoint.
Accordingly, to assess
this possible
explanation,
the
AO was directed to close
manual
valve V-8741
stopping discharge
to the
RWST.
The
RHR pump was then started
on
recirculation with an
AO stationed at the
pump to listen for
cavitation.
Valve 8809B was then opened
by the
CO and HCV-637 was
throttled to direct flow to the loop 3 and 4 cold legs.
Pump
amps
again fluctuated,
the
pump was shutdown,
and both valves were
closed.
No sounds of pump cavitation were detected
by the
AO at the
RHR pump.
For the next 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 20 minutes,
the indication problem was again
discussed.
Inside containment,
the watch reported cavity level to
be at 115'nd decreasing.
The
RHR pump was vented
once again, with
little air found.
Further discussion
regarding possible
causes
of
the encountered
problems continued.
The
SRO inside containment
reported tygon tube level indication reading
107 1/2
, agreeing with
both wide and narrow range indication (LI-956 and LI-957).
A
decision
was then
made not to restart the
RHR pump due to numerous
indications that water level inside the reactor vessel
was low, even
with
1 foot of water above the flange in the cavity.
After a brief discussion,
a decision
was
made to reflood the vessel
from the
RWST.
Valve SI-2-8980
was cracked
open to reflood the
vessel
and check
RVRLIS indication.
Both wide and narrow RVRLIS
showed
an increase after about thirty seconds.
The inside
containment
watch reported
no change in cavity level,
even though
RYRLIS indicated
a 5'evel
increase.
Eventually, the watch inside
containment reported
numerous "fountains" of water coming out of the
upper internal
package
rod cluster control guide tubes,
and
RVRLIS
indicated level at 114'.
At that time, SI-2-8980
was shut and
RVRLIS stabilized at 115'levation.
Operators
then concluded that
even though about
2 1/2'f water remained in the cavity above the
vessel
flange, the water level inside the reactor vessel
had been
lowered to 7'elow the flange.
Prints of the Unit 1 and Unit 2 top hat assemblies
were obtained,
and the explanation of the discrepancy
between indications
became
14
apparent.
The upper internals
package
was forming
a seal
on the
reactor vessel
flange since
no fuel assemblies
were in the core.
With fuel installed in the core, the leaf springs
on the fuel
assembly
top plate provided enough lifting force to unseat
the upper
internals
package
from the upper internals
support
ledge
when the
reactor
head
was not installed.
With the upper internals
package
seated
on the support ledge,
the only drain path from the refueling
cavity to the reactor vessel
was through the rod cluster control
assembly
guide tubes
and the head cooling flow holes in the upper
support plate.
Since the guide tubes
extend about
2 feet above the
vessel
once water level in the refueling cavity drops to the
two foot (116'levation) level, flow from the cavity to the reactor
vessel
is limited to the capacity of the head cooling flow holes
which is significantly less
than
RHR pump capability.
In reviewing this event,
the
NRC identified several
improper actions
by the licensee.
For
a first-of-a-kind operation
such
as this,
a
more thorough
and indepth
assessment
of the evolution should
have
been provided prior to beginning draindown.
The entire process
lacked the fundamental of a cautious
analyzed
approach.
At the
first indication of a disparity between
RVRLIS and actual
observed
level,
pumpdown of the cavity should
have
been
stopped,
an
assessment
made,
a planned out organized
approach
developed,
and
upper management
involvement and concurrence
obtained prior to
proceeding with any plant evolutions.
OTSC, Revision 0, to
OP B-2:VI, specified in step
14 "when the water
level in the refueling cavity'has
been
lowered to approximately I
foot'elow the reactor
vessel
flange, stop
RHR pump 2-2
(approximately 113'n
RVRLIS or tygon tube indication)."
Within 10
minutes of recognizing the inconsistency
between
RVRLIS and observed
cavity water level, both
WR and
NR RVRLIS indicated 113'.
However,
the
RHR pump remained
running for a period of about
1 I/2 hours
after the inconsistency
was observed until level dropped to
107'levation.
The
pump was also later restarted.
The plant evolutions
conducted
below the 107'levation water level constitute operations
outside the scope of OP B-2:VI.
Accordingly, these actions
are
considered
an apparent violation of the procedure
(Item
50-323/87-20-04).
As corrective action,
OPs B-I:VI and A-2:II were revised to define
proper
RHR flow rates
and emphasize
importance of operator reliance
on RVRLIS.
Additionally three
memos were issued to the operating
staff.
The first was
an Operations Shift Order issued
by the senior
operations
supervisor stressing
the need to perform operations
in
accordance
with good procedures.
A second
memo to all operations
personnel
was issued
by the operations
manager
regarding
use of
procedures.
Both memos stressed
that if a procedure is not
adequate,
or if unforeseen
circumstances
develop,
the operation in
process
must stop
and further guidance
be obtained prior to
resumption of work.
This philosophy is to apply regardless
of
impact on outage
schedules,
plant startup,
or required load changes.
15
The third memo from the operations
manager to shift supervisors,
shift foreman,
and shift technical
advisors
addressed
guidelines for
handling investigations of significant occurrences
and providing
information to upper management.
Additionally, PG8E
s Vice
President of Nuclear Power Generation
conducted
discussions
with
each operating
crew regarding several
items including following
procedures,
stopping work when things are not going according to
plans or when questions
develop,, and involvement of proper people
(including management)
in decision making process.
Unit 2 Refuelin
Water
S ill to the Auxiliar Buildin
On May 8, 1987,
between
1757 and 1811 hours0.021 days <br />0.503 hours <br />0.00299 weeks <br />6.890855e-4 months <br />,
several
hundred gallons
of contaminated
water spilled into the Auxiliary Building from the
Unit 2 Refueling Water Storage
Tank (RWST) through
an open flange
downstream of charging
pump 2-3 (the positive displacement
charging
pump).
The flange was
opened
when the charging pump's relief valve,
CVCS-2-8116,
had been
removed for maintenance.
Airborne and
contamination related to the spill were relatively minor and the
spill was cleaned
up within a matter of hours.
Prior to the spill, the licensee
had been preparing to establish
a
boration flow path,
as required
by TS 3.1.2.1,
in anticipation of
reloading the core.
Coincidentally,
maintenance
was being performed
on CVCS-2-8116.
On the
same clearance,
work had been completed
on
Volume Control Tank (VCT) discharge isolation valves
CVCS-2-LCV 112
B8C.
To establish
a boration flow path, the status of a number of
the clearance
boundary valves for the above work was affected.
With
work on CVCS-2-LCV 112C complete, it could
now be used
as
a boundary
valve in lieu of RWST to charging
pumps isolation valves SI-2-8805
A8J3.
In accordance
with Administrative Procedure
(AP) C-6S1,
"Clearance
Request/Job
Assignment," the shift foreman requested
the work
planning operations
coordinator to review and reissue
the clearance
to establish
a new work boundary.
In reviewing the clearance,
which
had
a total of 52 clearance
points,
the operations
coordinator noted
that charging
pump 2-3 suction isolation valve CVCS-2-8473
was
on
the clearance
but did not notice that it was listed as
open with a
"caution" tag and not closed
as
he assumed.
CVCS-2-8473
had been
left open
as
a drain path from the charging
pump suction header
through the charging
pump 2-3 separator stabilizer
and CVCS-2-558 to
the miscellaneous
equipment drain tank.
Although CVCS-2-8473
needed
to be closed
as
a boundary valve to establish
a boration flow path
since the operations
coordinator thought it was closed, it was
inadvertantly left open.
The operations
coordinator
added
two
clearance
points to the clearance,
including one for CVCS-2-LCV
112C,
and forwarded it to the operations
department
clearance
coordinator.
The clearance
coordinator reviewed the clearance
and,
just as the operations
coordinator
had done,
noted that CVCS-2-8473
was
on the clearance
but did not note its position.
The clearance
was then forwarded to the Shift Foreman
(SFM) for review and
dispositioning.
Neither the
SFM nor anyone
on his crew noted that
CVCS-2-8473
was listed incorrectly on the clearance
as
opened.
16
At 1721 hours0.0199 days <br />0.478 hours <br />0.00285 weeks <br />6.548405e-4 months <br /> the two new clearance
point valves were positioned,
tagged,
and verified.
At 1757 hours0.0203 days <br />0.488 hours <br />0.00291 weeks <br />6.685385e-4 months <br /> operations
reported off valve
.
SI-2-8805A by re-establishing
power to its breaker.
Operations
had
expected
SI-2-'8805A to remain closed,
however,
since the
YCT was
empty,
(another
requirement of the clearance),
a low level automatic
charging
pump suction transfer
signal
opened the
RWST isolation
valve.
With CVCS-2-8473 open,
a path
was established
from the
through SI-2-8805A to CVCS-2-8473, to the stabilizer separator,
through charging
pump 2-3,
and finally out the open flange for
relief valve CVCS-2-8116.
At 1810 hours0.0209 days <br />0.503 hours <br />0.00299 weeks <br />6.88705e-4 months <br />,
a security guard notified
the control
room that water was leaking out of the charging
pump 2-3
room.
At 1811 hours0.021 days <br />0.503 hours <br />0.00299 weeks <br />6.890855e-4 months <br /> the operator discovered that SI-2-8805A had
opened automatically and
he closed it.
It was estimated that 1300 gallons of water had drained from the
RWST.
Although the actual
volume of water spilled to the auxiliary
building could not be accurately
determined, it was estimated to be
several
hundred gallons.
Accurate measurment of the water spilled
was not possible
since the
RWST capacity is 400,000 gallons,
and
only a fraction of a percent of change in level of 400,000 gallon
RWST was observed.
In addition, the majority of that volume drained
through
CVCS-2-558 to the Miscellaneous
Equipment Drain Tank (NEDT)
and the actual
level
change of the
MEDT is not trended.
Therefore,
it was not possible to establish
the actual
volume of water spilled
to the Auxiliary Building.
The licensee's
investigation of this event determined
the cause to
be the inadequate
review of the clearance.
The licensee initiated a
human performance
evaluation to determine if there is a need to
revise the clearance
procedure.
The effectiveness
of the evaluation
will be tracked
as
an unresolved
item.
(Open Item 50-323/87-20-05).
Containment Ventilation Due to Source
Check on Wron
Radiation
Monitor
On May 25,
1987, in preparation for the planned discharge
of waste
evaporator
condensate
tank 0-2, auxiliary operators
were in the
process of performing the pre-discharge
checks
on Unit 1 RM-18, the
liquid radwaste effluent monitor,
as required
by OP
G-1: II "Liquid
Radwaste
System - Processing
and Discharge of Liquid Radwaste."
The
operator
proceeded
to the radiation monitor racks in the control
room, located the controls for RM-18, and proceeded
to the nearest
telephone to establish
communications with another operator at the
auxiliary building control board.
After establishing
communications,
he returned to the
RM-18 controls
and proceeded with
the source
check.
Instead of operating controls for source
checking
RM-18,
he inadvertently initiated a source
check
on RM-14B, the
plant vent radiogas
monitor, which had its controls located directly
below the controls for RM-18.
RN-14B exceeded its high trip
setpoint while being source
checked, initiating a CVI signal.
As no
containment venting was in progress,
only the isolation valves for
RMs-11812, the containment
radiogas
and air particulate monitors,
closed
as
a result of the signal (in accordance
with plant design).
17
The signal
was reset,
and RMs-11812 were unisolated
and returned to
service.
The root cause of this event
was personnel
error.
A contributing
cause
was poor human factor engineering
in the labeling of the
radiation monitoring racks in the control
room.
As corrective action, the operator involved was counseled
as to his
improper actions.
Additionally, the licensee
indicated the labeling
on the radiation monitoring racks in the control
room will be
assessed,
and revised
as necessary
to improve
human factor
considerations.
k.
Performance of Testin
on Wron
Unit
On May 25,
1987
IBC technicians
performed portions of loop test for
RCS loop 1 delta
T deviation
on the wrong unit.
The loop test
was
scheduled to be performed
on Unit 2, which was in a refueling
outage,
but was inadvertantly attempted
on Unit 1.
This resulted in
the tripping of the overtemperature
delta
T reactor trip bistable
for that loop and the bistable for overtemperature
delta
T
anticipatory rod stop
and turbine runback.
In all cases
two out of
four logic is required to initiate action
and all other channels
remained in service
so
no automatic
responses
were actuated.
The
details =of this event
and the results of the licensee's
investigation
and actions taken to prevent recurrence will be
included in the next inspection report,
50-275/87-23
(Open Item
50"275/87-20-01).
Three violations 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 ~
Diesel Generator
Instrument
Panels
The inspector observed portions of preventive maintenance activities
for diesel
generator
instrument panels.
The observed activities
were performed in accordance
with maintenance
instructions with
appropriate prerequisites
and precautions
observed.
The inspector
noted that relays
ARD relays) within the
instrument panel
were similar to relays at Palo Verde which had
a
problem with debris in the relay.
The inspector discussed this
problem with the electrical
foreman.
The electrical
foreman planned
to evaluate
the need for further inspection of the relay.
18
b.
Motor 0 crated Valve
Tor ue Switch Settin
The inspector
observed electrical
maintenance
personnel
perform
torque switch setting
on eight inch
MOV SI-2-8804B
(RHR heat
exchanger
2 to the SIS pumps).
The valve motor operator
was
a
Limitorque model
SMB-1.
Work was accomplished
in accordance
with
work order C0013380
and approved
On-The-Spot
changes
to Maintenance
Procedure
E-53.10B "Limitorque Operator Torque Switch Adjustment."
Manual
hand wheel closing thrust readings of 9440,
9580,
and 9280
pounds
were recorded
and were witnessed
by a gC inspector.
These
readings
exceeded
the minimum acceptable
value of 8550 pounds
thrust.
The gC inspector also witnessed
the motor closing thrust
(torque switch setting),
which was found to be 21470,
21420,
and
21160 pounds
(due to motor inertia).
These values did not exceed
the stem stud
maximum yield of 25540 pounds thrust and were thus
also acceptable.
Test equipment,
including the load cell set,
was calibrated.
From a
review of documentation
associated
with recent valve operator
maintenance,
the inspector
determined
the proper grease
(Exxon
Nebula
EPO)
had been
used in the main gear case.
C.
Containment
Sum
to
Pum
2-2 Suction Isolation Valve
The inspector observed portions of a corrective electrical
maintenance activity performed
on the containment
sump to
RHR pump
2-2 suction isolation valve (SI-2-8989B).
During
December of 1986,
the licensee
performed
an environmental qualification inspection of
the valve operator motor,
and discovered
a hairline crack on one of
the limit switch rotors.
Since the defect was determined
not to,
affect the operability of the valve, the licensee
scheduled its
replacement for the refueling outage.
The- inspector witnessed portions of the limit switch rotor changeout
and determined that a-certified replacement part was used.
In
addition, appropriate
technical specifications
were
met.
Tagouts
and administrative approvals
were obtained
and qualified personnel
performed the job.
d.
Main Steam Safet
Valve Settin
with H draulic Assist
On the evening of May 12, the inspector witnessed
the performance of
Maintenance
Procedure
(MP) M-4.11 "Main Steam Safety Valve Setting
with Hydraulic Assist" for Unit 1 main steam relief valve 1-RV-7.
1-RV-7 had apparently lifted the previous
evening at a point lower
than the 1035 psi setpoint for the 10K steam
dumps.
The nominal
setpoint for the lowest set main steam relief valves is 1065 psi +
or - 11 psi.
Lifting prior to the actuation of the
10K steam
dump
indicated that the setpoint for 1-RV-7 had drifted low.
Unit 1 was,
at that point, in MODE 3.
Prior to proceeding to
MODE 2, the
licensee
performed
MP M-4.11 to set the relief valve within
tolerance.
19
The inspector
noted that all prerequisites
were met and that the
test was performed
by qualified personnel.
In addition,
communications
were established
between
the maintenance
personnel
and the control
room.
The inspector also observed that
a qualified
QC specialist
observed
the testing in accordance
with an appropriate
QC inspection plan.
The as found lift point of the relief valve was
found to be approximately
1048 psi.
The valve was reset to
approximately
1075 psi.
The difference
between
the as found lift
point and the lift point reported
by operations
was attributed to
the response
time of the
10% steam
dumps
and the accuracy of the
control
room steam pressure
chart recording.
Hot Bendin
of Unit 2
RHR Pi in
On May 4, 1987, swing shift mechanical
maintenance
personnel
heated
a portion of Unit 2
RHR Train A piping to 1200 degrees
Fahrenheit,
in
an attempt to hot bend the pipe, without the use of a qualified
procedure.
The details of this occurrence
and the results of the
licensee's
investigation
and actions
taken to prevent recurrence
will be included in a subsequent
inspection/investigation.
This
occurrence will be tracked
as an. unresolved
item (Open Item
50-323/87-20-06).
The review and approval
by a
QC planner of the work order allowing
the hot bending of safety related piping indicates
a lack of
familiarity of the
QC planner of the heat sensitizing effects of
heat
on austenitic stainless
steel.
It should
be apparent to all
planners that any time heat is applied to safety related piping a
special
process
procedure is required.
In addition, the licensee's
procedure
which provides the work control document review guidelines
for QC planners
showed weakness.
The inspector
reviewed Quality
Control Procedure
QCP-10.4
"Work Control
Document Review."
The
purpose of the procedure is to define the method for the Quality
Control Department's
review of work control documents
and as
such is
the governing procedure for the
QC planner's
review of work orders.
The instructions in the procedure state that the
QC planner
"...shall review the work control document for technical
and quality
requirements
using the appropriate checklist included in the
appendices
to this procedure."
However, the appendices
of QCP 10.4
does not include
a checklist for the review of work orders although
the work order format for work control
documents
has
been in use
since July l986.
Had the checklist in the appendices
of,QCP 10.4
been
updated in a timely manner following the initiation of the work
order system, it is possible
the
QC planner reviewing the package
would have required the use of a special
process
procedure.
Independent of the inspector's
review and the corrective actions of
the licensee
related to this event,
the Quality Control Department
also identified the deficiencies
contained in QCP 10.4.
A review of
Quality Control Procedures
was performed
by QC during the months of
April and May, 1987 to verify compliance with quality assurance
requirements
and other committments.
This review concluded that
QCP
10.4 needed
to be revised to reflect the work document
system
presently being used.
The inspectors
questioned
why a revision to
20
No
gCP 10.4 was not initiated with the institution of the work order
system.
This issue
and the timely revision of gCP 10.4 will be
tracked
as
an unresolved
item.
(Open Item 50-323/87-20-07).
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 ~
Stroke Time Testin
1-2 Blowdown Sam le
Containment Isolation Valve 1-FCV"248
The inspector witnessed the performance of Surveillance Test
Procedure
(STP) V-2J "Exercising 5 Position Verification of Power
Operated
Valves for Outside Containment Isolation Valves" and
V-3S2 "Exercising Phase
A Containment Isolation Valves
(Steam
Generator
Blowdown)" on steam generator
1-2 blowdown sample
containment isolation valve 1-FCV-248.
For these tests,
1-FCY-248
was cycled for the observation of the actual
valve position and an
isolation time of less than
10 seconds.
The tests
were performed in
accordance
with the procedure
by the operations
crew under the
supervision of the Unit 1 senior control operator.
The valve testing
was required
when it had failed to reposition
properly during the performance of STP I-lllA"Functional Test of
Blowdown Sample Effluent Liquid Monitor RM-19,"
which required the stroking of 1FCV-248.
The valve was closed,
as
required
by the TSs
and declared
STPs V-2J and V-3S2
were performed after corrective maintenance.
With the completion
and review by the Unit 1 shift foreman of STPs V-2J and V-3S2,
1FCV-248 was returned to service.
b.
Unit 2 Containment Isolation Valve Local
Leak Rate Testin
The inspector witnessed
the performance of STP V-600 "General
Containment Isolation Valve Leak Tests"
on a number of containment
isolation valves.
The inspection
was performed to satisfy
NRC
inspection procedure
61720 "Containment
Local
Leak Rate Testing."
However, this inspection
was not complete at the end of the
inspection period and therefore will appear in the next inspection
report,
50-323/87-22.
No violations or deviations
were identified.
6.
Unit 2 Refuelin
Outa
e
a 0
Fuel
Assembl
Reconstitution
The inspector
observed portions of the licensee's
efforts to replace
damaged
fuel rods in three fuel assemblies
with inert steel
rods.
21
Sampling of primary reactor coolant for Unit 2 during power
operations
indicated that there
had been
some
damage to fuel rods..
As a result, the licensee
performed ultrasonic testing
on all fuel
assemblies
after they had been placed in the spent pool
and
identified three assemblies
with one
damaged fuel rod a piece.
The
licensee
contracted
to replace the
damaged
fuel rods
with inert steel
rods,
a process
known as fuel reconstitution.
The procedure for fuel reconstitution
includes the following steps:
1)
The-fuel assembly is taken from its spent fuel rack position
and placed in a canister in a special
elevator.
2)
The lid on the canister is shut, the assembly rotated
on its
axis,
and the bottom lid is opened
exposing the bottom nozzle.
3)
The bottom nozzle is removed.
Since the nozzle is welded to
screws which attach to the
RCCA guide thimbles (24 locations)
some weld grinding is required.
4)
The faulty fuel rod is lifted from the assembly
and placed in a
special
rack that can hold a number of rods.
The rack is
placed in a corner location in the spent fuel racks.
A steel
rod is inserted in the position of the old fuel rod.
5)
A new nozzle is placed
on the assembly,
with new screws
attaching it to the 24 guide thimbles.
The screws
are then
crimped 'to the nozzle with a special
crimping tool.
6)
The canister lid is closed
and the fuel assembly is rotated to
its upright position,
removed from the elevator
and placed in
the spent fuel racks.
The fuel reconstitution
was performed using
a licensee
approved
procedure.
The inspector observed that steps
in this
procedure
were executed carefully and methodically.
The four member
team appeared qualified and knowledgeable of their
procedure.
The torquing of the nozzle screws
and the crimping of
the screws
was accomplished with calibrated instruments
to values
established
in the procedures.
The inspector
noted that precautions
and limitations were observed.
Proper controls were established
for the fuel handling area.
Of
note,
a "hot particle zone"
was established for the area
around the
spent fuel pool in an effort to control the spread of hot particles.
To date,
the licensee
has
had little problems with hot particles.
However, they are proceeding with caution in the fuel handling area
since the most likely source of hot particles
are the tools that are
used at at other plants
and brought to Diablo Canyon.
All personnel
gaining access
to the "hot particle zones"
are required to attend
a
lecture
on the control of the particles.
No violations or deviations
were identified.
22
7.
ualit
Hotline Effectiveness
~
~
~
The inspectors
reviewed the licensee's
evaluation of guality Hotline
concerns87-001 through 87-006.
The concern evaluations
were in
accordance
with the licensee
s guality Hotline policies
and procedures.
The guality Hotline Summary Reports acceptably
addressed
the concerns
and
documented
the-actions
taken.
In discussions
with various site personnel,
the inspectors
were informed
that there
was
a feeling that use of the guality Hotline by an individual
could result in repercussions.
This feeling was conveyed to Hotline
management,
Mr. Lieber.
Mr. Lieber indicated
he would address
this issue
in the- next
GONPRAC meeting.
This will be followed as followup item
(Open Item 50-275/87-20-02).
No violations or deviations
were identified.
8.
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 inspectors:
Unit 1:
86-14, 86-17, 87-05
No violations or deviations
were identified.
9.
Exit
On June 10,
1987 an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.
I>>