ML17146A376
| ML17146A376 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 05/02/1986 |
| From: | Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17146A374 | List: |
| References | |
| 50-387-86-06, 50-387-86-6, 50-388-86-04, 50-388-86-4, IEB-80-17, NUDOCS 8605130226 | |
| Download: ML17146A376 (28) | |
See also: IR 05000387/1986006
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report
Nos.
50-387/86-06
50-388/86-04
Docket Nos.
50-387
CAT
C
50-388
CAT
C
License
Nos.
NPF-22
Licensee:
Penns
lvania Power
and Li ht
Com an
2 North Ninth Street
Allentown
Penn s
1 vani a
18101
Facility Name:
Sus
uehanna
Steam Electric Station
Inspection At:
Salem Townshi
Penns
lvania
Inspection
Conducted:
March
15
1986 - A ril 15
1986
Inspectors:
R.
H. Jacobs,
Senior Resident
Inspector
L.
P 'sc
, Resident
Inspector
Approved By:
. Strosnider,
Chief, Reactor Projects
Section
1B,
s/~/z~
date
Ins ection
Summar
~d:
i
t
7:
2
1
of plant operations,
licensee
events,
open items, surveillance,
maintenance,
and the Unit
1 Refueling Outage.
Results:
The inspector
noted that corrective maintenance
is required
on the
125
VDC Station Battery lighting system (Detail 2.2. 1);
an unusual
event
was
declared
due to
a contaminated/injured
man (Detail
3. 1);
an
open states link
was identified during the performance of the
test (Detail 5. 1);
and post-maintenance
testing of motor operated
valve maintenance
needs
to be
reviewed (Detail 5.2. 1).
Three violations were identified.
One violation concerned
improperly controlled
maintenance
work in the reactor building recirculation
plenum (Detail 5.2.2).
The
second violation concerned
the inoperability of two
SDV level transmitters
(Detail 6.6).
The third violation concerned
SDV level transmitter isolation
valves which were not locked open
as required
by station administrative controls
(Detail 6.5).
8605130226
860507
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DETAILS
4
1.0
Followu
on Previous
Ins ection
Items
Closed
Unresolved
Item
388/84-34-14
- Evaluate
Diesel Generator
Fre uenc
Oscillations
During the Unit 2 Loss of All AC Power event in July 1984,
the
'A'mergency
Diesel
Generator
(EDG) exhibited large frequency osci lla-
tions after
a manual start
and was subsequently
manually tripped by
the operator.
Further testing of the diesel
generator
following the
event could not reproduce
the oscillations.
The licensee
issued
scram recovery action item 2-84-04-21 to conduct
a review of the
performance
records
to determine if there
had been
any previous prob-
lems with oscillations.
In Inspection
Report 50-388/85-13,
the inspector
reviewed the
licensee's
assessment,
which included recommendations
for additional
testing of the diesel
generators.
The site staff had not completed
its evaluation of the recommendations
at the time of the followup.
The licensee's
corporate
engineering staff recommended
additional
testing of the diesel
generators
in PLI-37643 dated January
14,
1985.
The two monthly tests
recommended
were: (1) measuring
the output of
the governor
load sensor with an amplifier during manual operation;
and (2) measuring
the resistance
of the
speed
reference resistor
used
in emergency operation.
Plant staff review of the recommendations
found that the devices
are currently tested
in other surveillance
procedures
(18-Month Tests),
and that due to the history of reliable
operation of the devices,
the increased
testing
frequency
was not
warranted.
In addition the licensee
recently performed modifications
to the governor oil cooler, which should
improve the governor
response.
The inspector
reviewed the associated
surveillance
tests
and the re-
cent results for indications of degradation.
No unacceptable
items
were noted.
1.2
Closed
Violation
388/85-06-07
Emer enc
Li htin
Batter
Power
Su
1
Not 8-Hour Rated in Fire Zone 2-2A
In February
1985,
the inspector identified that the emergency light-
ing battery
power supply unit installed in the stairwell to the Re-
mote Shutdown
Panel
at the
670 feet elevation of the Unit 2 Reactor
Building (Fire Zone 2-2A, Core Spray
Pump
Room) did not meet the re-
quirements of 10CFR50,
Appendix R,Section III.J.
The installed light was manufactured
by Exide,
and was physically
different from the Dual-Lite Model units used in other safety-related
areas.
On July 19,
1985 the non-conforming battery
power supply was
replaced with a Dual-Lite 8-hour unit under
WA V50318.
The
14
85-0114
was subsequently
closed.
The inspector verified that the
new
light was installed.
2.0
Review of Plant
0 erations
2. 1
0 erational
Safet
Verification
The inspector toured the control
room daily to verify proper manning,
access
control, adherence
to approved
procedures,
and compliance with
LCOs.
Instrumentation
and recorder traces
were observed
and the sta-
tus of control
room annunciators
was reviewed.
Nuclear Instrument
panels
and other reactor protection
systems
were examined.
Effluent
monitor s were reviewed for indications of releases.
Panel
indica-
tions for onsite/offsite
emergency
power sources
were examined for
automatic operability.
During entry to and egress
from the protected
area,
the inspector
observed
access
control, security boundary integ-
rity, search activities, escorting
and badging,
and availability of
radiation monitoring equipment.
The inspector, reviewed shift supervisor,
plant control operator
and
nuclear
plant operator
logs covering the entire inspection period.
Sampling reviews were
made of tagging. requests,
night orders,
the
bypass
log, Significant Operating
Occurrence
Reports
(SOORs),
and gA
nonconformance
reports.
The inspector
observed
several shift, turn-
overs during the period.
No unacceptable
conditions were identified.
2.2
Station Tours
The inspector toured accessible
areas of the plant including the con-
trol room, relay rooms,
switchgear
rooms,
cable
spreading
rooms,
pen-
etration areas,
reactor
and turbine buildings, diesel
generator
building,
ESSW pumphouse,
and the plant perimeter.
During these
tours, observations
were
made relative to equipment condition, fire
hazards,
fire protection,
adherence
to procedures,
radiological
con-
trols and conditions,
housekeeping,
security,
tagging of equipment,
ongoing maintenance
and surveillance
and availability of redundant
.
equipment.
2.2.1
125
VDC Station Batter
Li htin
S stem
During a tour of the Unit
1 and Unit 2 reactor buildings
on
March 31,
1986,
the inspector
noted that
some of the
125
VDC Station Battery Emergency lights were on,
some were
off, and
some did not have light bulbs installed.
The in-
spector
reviewed lighting drawings
EL-64 and the
FSAR to
determine
the correct configuration requirements.
Section 9.5.3
states
that the
125
VDC lighting fixtures
are normally energized
from the normal
AC subsystem,
and
automatically transfer to the
125
VDC system
on loss of
power.
The
FSAR also states
that continued energization
of
the
lamp w'ith AC power during normal operation
reduces
the
load on the battery chargers
and maintains
the
lamp fila-
ment at
a temperature
that limits the initial current
surge
when the
DC voltage is applied to the lamp,
and also allows
the lights be monitored continuously.
It appears
that cor-
rective maintenance
is required to ensure
the emergency
lighting system
meets
the
FSAR commitments'any
of the
.
areas
needed
to shutdown outside
the control
room currently
do not have operable light fixtures.
This item is
unresolved.
(387/86-06-01;
388/86-04-01)
3.0
Summar
of 0 eratin
Events
3.1
Unit
1
Unit
1 continued with its second refueling outage
which commenced
on
February
15,
1986.
The Unit reached
Operational
Condition
4 on April 8,
1986.
The, outage activities are discussed
in Detail 7.0.
The licensee
declared
an Unusual
Event at 7:00 p.m.,
March 21,
due to
a contaminated
injured man.
The individual was replacing the control
rod drive housing support underneath
the reactor vessel
when the
platform grating
gave way.
He fell about
10 feet to the subpi le
floor injuring his right knee.
He was in full protective clothing
(PC) using
a respirator,
but
some contamination
soaked
through the
clothing.
He was decontaminated
prior to being sent off site.
Con-
tamination levels
on the individual's skin were about
1-3K dpm/100cm 2
when
he was transported
via ambulance
to the Berwick Hospital.
The
hospital
had been alerted
and
was prepared
to minimize contamination
spread.
An HP technician
rode with the individual in the ambulance
and
an
HP supervisor
went to the hospital.
The Unusual
Event was
terminated at 7:57 p.m.
when the individual was transported
to the
hospital.
He was completely deconned
and all contaminated
materials
were brought back to the site.
Surveys of the hospital
and ambulance
showed
no spread of contamination.
The individual is a PP5L employee
and
has
a. broken
knee
cap.
Undervessel
work was halted until an in-
vestigation
was conducted
and the grating reinforced.
On April 8, the annual
emergency drill was held and involved full NRC
participation.
An assessment
of the drill will be included in In-
spection
Report 50-387/86-07;
50-388/86-08.
3.2
Unit 2
Unit 2 operated
at or near
100 percent
power for most of the inspec-
tion period.
Scheduled
power reductions
were conducted
throughout
the period for control rod pattern adjustments,
surveillance testing,
and scheduled
maintenance.
P
4.0
Licensee
Re orts
4. 1
In-Office Review of Licensee
Event
Re orts
The inspector
reviewed
LERs submitted to the
NRC:RI office to verify
that details of the event were clearly reported,
including the
accuracy of description of the"cause
and adequacy
of corrective
ac-'ion.
The inspector determined whether further information was re-
quired from the licensee,
whether generic implications were involved,
and whether the event warranted onsite followup.
The following LERs
were reviewed:
Unit
1
- 86-005, Reactor Building Ventilation Isolated
on High Radiation
Signal
86-006,
Unplanned
Engineered
Safety
Feature Actuation
When 'States
Link'ightened
86-007, Division I
LOCA Isolation Occurred
Due to Blown Fuse
Unit 2
- 86-004, Reactor
Scram (Manual)
Due to Main Transformer Overheating
~Previously discussed
in Inspection
Report 50-387/86-02;
50-388/86-01
~*Previously discussed
in Inspection
Report 50-387/85-36;
50-388/85-32
4.2
Review of Periodic
and
S ecial
Re orts
Upon receipt, periodic
and special
reports
submitted
by the licensee
were reviewed
by the inspector.
The reports
were reviewed to deter-
mine that they included the required information; that test results
and/or supporting
information were consistent with design predictions
and performance specifications;
that planned corrective action was
adequate
for resolution of identified problems;
and whether
any in-,
formation in the report should
be classified
as
an abnormal
occurrence.
The following periodic
and special
report
was reviewed:
Monthly Operating
Report
March 1986, dated April 11,
1986.
The above report was found acceptable.
5.0
Monthl
Surveillance
and Maintenance
Observations
5.1
Surveillance Activities
The inspector
observed
the performance of surveillance
tests
to de-
termine that:
the surveillance test procedure
conformed to technical
specif'ication requirements;
administrative
approvals
and tagouts
were
obtained before initiating the test; testing
was accomplished
by
qualified personnel
in accordance
with an approved surveillance
procedure;
test instrumentation
was calibrated; limiting conditions
for operations
were met; test data
was accurate
and complete;
removal
and restoration
of the affected
components
was properly accomplished;
test results
met Technical Specification
and procedural
requirements;
deficiencies
noted were reviewed
and appropriately resolved;
and the
surveillance
was completed at the required frequency.
These observations
included:
Trip Testing Using Auxiliary Steam,
performed
on April 7,
1986.
During the performance of TP-152-006 witnessed
by the inspector
on
April =7,
1986,
the
HPCI turbine exceeded
the acceptable
trip setpoint of 5059-5265
RPM.
The turbine tripped at 5289
RPM.
After adjustments
by mechanical
maintenance,
the test
was reperformed
successfully
on April 8.
While setting
up for the test,
on April 7,
IEC technicians
were to
open states
links AA-5 and AA-8 in terminal
panel
TB1C016-Al to de-
feat the low steam
supply pressure
isolation to HPCI.
When the panel
was opened, it was found that the links were already
open,
but no
tags were
on them.
The system status file was searched,
and
no work
was being performed which authorized
opening these links.
The
licensee initiated
SOOR 1-86-109 to investigate
the cause.
The
results of the investigation will be reviewed in a subsequent
inspection.
(387/86-06-02)
5.2
Maintenance Activities
The inspector
observed
portions of selected
maintenance activities to
determine that the work was conducted
in accordance
with approved
procedures,
regulatory guides,
Technical Specifications,
and industry
codes or standards.
The following items were considered
during this
review:
Limiting Conditions for Operation
were met while components
or systems
were
removed
from service;
required administrative approv-
als were obtained prior to initiating the work; activities were ac-
complished
using approved
procedures
and
gC hold points were
established
where required;
functional testing
was performed prior to
declaring
the particular component
operable; activities were accom-
plished
by qualified personnel;
radiological controls were imple-
mented; fire protection controls were implemented;
and the equipment
was verified to. be properly returned to service.
P
F
5.2.1
Motor 0 crated
Valve Maintenance
On March 20,
1986, while performing SE-149-002,
RHR Divi-
sion II Logic System Functional Test,
the recirculation
system discharge
bypass
valve (1F032B) did not automatical-
ly clo'se
on receipt of a
LOCA signal.
This function is
part of LPCI injection.
The licensee
investigated this
occurrence
and determined that
a lead in the auto-closure
logic was
landed improperly at the motor operated
valve
(MOV).
The lead
was found terminated at terminal
TB-82 and
to correct the problem,
the lead was
moved to terminal
TB-81.
The valve was subsequently
tested satisfactorily.
Unit
1 was in Operational
Condition
5 and the auto-closure
function of this valve was not required to be operable,
The inspector
reviewed this occurrence
to determine its
cause.
This valve actuator
had been recently worked for
MOV environmental qualification (Eg) preventive maintenance
(PM) under
WA P-53156.
The inspector
reviewed this work
package,
electrical
schematics
E-151 sheet
14, Ml-B31-275
( 16) and connection
drawings
E-379.
The inspector also
reviewed work packages
and applicable
schematics
for sever-
al other valves which received
MOV Eg
PMs this outage.
During the work performed
on
1F032B, the actuator
was de-
terminated,
disassembled,
and reworked.
All leads
were
removed
from the limit and torque switch assemblies.
Form
MT-GM-021-2 was filled out with the required verifications
for lead removal
and installation.
The form indicates that
a lead was removed
from and reinstalled to TB-82 (Cable
¹RKlg1506E).
E-151 sheet
14 and E-379,
show that TB-82 is
a spare limit switch contact.'pparently,
the work group"
removing the lead
on March
5 misread
the termination
number
and the individuals reterminating
the lead
on March
7 put
it back
on TB-82 since it was indicated that this was the
terminal
from which it was removed.
All other leads re-
moved'and
reterminated
matched
the print.
This error was
not identified during post-maintenance
testing of the
valve.
The only operational
retest required after mainte-
nance completion
was to stroke
and time the valve, verify-
ing proper valve performance
by control
room indication.
Since only the auto-closure
function of the valve was dis-
abled,
the retest
was inadequate
to identify this problem.
The work plan and Equipment
Release
Form did not require
any further testing to declare
the valve operational.
How-
ever,
due to the outage
schedule,
the
system
Logic
System'unctional
Test (LSFT) was performed prior to declaring the
recirculation or
RHR system operational,
although the
was not required to be performed after this maintenance.
The licensee
performed
37 valve actuators
during this outage.
These valves are in the
RHR, Core
Spray,
systems.
The
inspector determined that in each
case,
according to the
outage
schedule,
either the system
LSFT was scheduled
to be
performed after completion of the valve maintenance
or the
valve does not have
an auto-closure
or opening function.
Therefore,
for this outage
the adequacy
of these
valves
following the
Eg
PMS is not a concern.
However, the retest
specified for the
PM should
be adequate
for the work per-
formed.
The inspector discussed
this issue with the Main-
tenance
Supervisor
Qho indicated they would review this.
This issued is considered
unresolved.
(387/86-06-03)
Recirculation
Plenum Work
On March 27,
1986, while observing
maintenance
on the reac-
tor building recirculation
plenum,
the inspector
noted that
access
hatches
to both the recirculation
fan supply and
discharge
sides of the recirculation
plenum were
open at
the
same time
Work was ongoing inside the upper
(supply)
portion of the plenum, but
no work was ongoing
on the dis-
charge side.
The inspector also noted that fuel movement
was in progress
on Unit
1 and
no
LCO had been entered for
loss of secondary
containment integrity.
The inspector
discussed
this condition with the Unit
1 and Shift Supervi-
sors.
Both individuals were
unaware that the plenum hatch-
es were open.
The work inside the recirculation
plenum
had
been authorized
by shift supervision with the understanding
that the access
hatch would be opened
to allow ingress
and
egress
only and that the access
hatch would be replaced
(although not tightened) while the work was underway.
Equipment
Release
Form (ERF) A-43692 was released
at 7:45
a.m.
March 27, to permit access
to the recirculation
plenum.
The
ERF stated that
a
man will be stationed at the
hatch during the access
period.
It did not indicate that
more than
one hatch would be'opened
or that the hatch would
only be opened for ingress
and egress.
As noted above,
when the inspector
observed that the access
hatch to the
lower plenum was opened,
there
was
no one stationed at the
hatch.
The work in the plenum was authorized
by WAs P60063
and P51875,
and involved preventive
maintenance
on the re-
circulation fans
and dampers.
This work is normally per-
formed during
a two-unit outage
when
secondary
containment
is not required.
This maintenance
needed
to be performed
during this pe'riod to satisfy environmental qualification
requirements.
~>>
J
The recirculation
plenum houses
the 'A'nd 'B'ecircula-.
tion fans
and their isolation dampers.
Upon receipt of any
zone ventilation isolation signal,
the recirculation fan in
AUTO LEAD will start to recirculate
the air in the isolated
ventilation zones (I, II and/or III) to minimize the con-
centration of radioactive
gases
in the event of an acci-
dent.
The Standby
Gas Treatment
System
(SGTS) takes
a
suction
on the discharge
side of the plenum to maintain
a
negative
pressure
in the reactor building and filter the
offsite release.
If the recirculation
fan in AUTO LEAD
fails to develop 0.5 in. W.C. pressure
across
the fan, af-
ter
a time delay,
the running fan will stop
and the standby
fan will start.
In this case,
the standby
fan (OV201A) was
tagged out.
Therefore,
the two open hatches
on the suction
and discharge
sides of the plenum would tend to equalize
pressure
across
the fan and
may have prevented
the running
fan from developing
the required 0.5 in. W.C. If the run-
ning fan tripped off, there would be
no recirculation flow.
Previous
experience
has
shown that without recirculation
fans,
the drawdown times for the
SGTS system to drawdown to
a 0.25 inch vacuum in the different ventilation zones,
would be exceeded.
Therefore, this condition
may have de-
graded
secondary
containment integrity.
When the inspector notified the control
room of the condi-
tion of the recirculation
plenum,
the Shift Supervisor
im-
mediately halted fuel movement.
The work in the recircula-
tion plenum was
secured
and the hatches
reinstalled.
Fuel
movement
was
recommenced
at 12:45 p.m.
March 27.
The main-
tenance
supervisor
indicated that both plenum hatches
were
open at the
same
time from approximately
10:00 a.m. to
12:00 a.m.,
a period of two hours.
The licensee
prepared
a
Significant Operating
Occurrence
Report
(SOOR) to evaluate
the incident.
Technical Specification 3.6.5. 1 requires maintaining
secon-
dary containment integrity when the reactor is in Opera-
tional Conditions
1, 2, 3, or when fuel handling is in
progress.
In this case,
Unit 2 was at power and fuel move-
ments were ongoing in Unit 1.
Opening
and leaving
open
both recirculation
plenum hatches
for two hours degraded
secondary
containment integrity.
This was contrary to the
directions
on the Equipment
Release
Form and the under-
standing of the operators.
Since the operators
were un-
aware of the condition of the recirculation
plenum,
no
Limiting Condition for Operation
was entered for not
main-'aining
secondary
containment integrity.
The release
of
this work was inadequately controlled and is
a violation of
AO-QA-306, System/Equipment
Release.
(387/86-06-04)
10
6.0
Ino erable
Scram Dischar
e Volume Level Transmitters
6.1
Summar
of Event
On April 10,
1986,
in Operational
Condition 4, licensee
I&C techni-
cians
noted contradictory
scram discharge
volume
(SDV) level indica-
tions during an operational
hydrostatic test.
Subsequent
investiga-
tion found that the isolation valves to two SDV level transmitters,
which provide reactor protection
system
(RPS) signals,
were closed.
Further review identified that the valves
had been closed
since the
installation of the level detectors
in May 1985.
The cause of the
instruments
was the inadequate
close-out of a modification
package.
Due to the nature of the instrumentation circuits and the
surveillance test requirements,
the inoperable detectors
would not
have
been detectable
during normal plant operation.
6.2
S stem Descri tion
The
scram discharge
volume receives
the water displaced
by the motion
of the control
rod drive pistons during
a reactor
Should this
volume fill up to
a point where there is insufficient volume to ac-
cept the displaced
water control rod insertion would be hindered.
The reactor is therefore tripped when the water level
has
reached
a
point high enough to indicate that it is filling up, but the volume
is still great
enough to accommodate
the water from the movement of
the rods
when they are inserted.
In addition, if at the completion
of a scram the level of water in the
scram discharge
volume is great-
er than the trip setting,
the
RPS cannot
be reset until the discharge
volume has
been drained.
Four nonindicating level float switches
(one for each channel)
pro-
vide scram discharge
volume high water level inputs to the four RPS
channels.
Two switches
are installed
on each
instrument
volume.
In
addition,
a level indicating switch (tr ip unit), with transmitter,
in
.each
channel
provides
redundancy with the level switches.
This ar-
rangement
provides
sensor diversity,
as well as redundancy,
to assure
that
no single event or common-mode failure could prevent
a scram
caused
by
SDV high water levels
Both the four level transmitters
and
four float switches
are required to be operable
by Technical Specifi-
cations Table 3.3. 1-1.
All eight detectors
have the
same trip set-
point of 88 gallons
and are calibrated
on the
same
frequency (every
18 months).
IE Bulletin No. 80-17, "Failure of 76 of 185 Control
Rods to Fully
Insert During
a Scram at
a
BWR", and the subsequent
five supplements,
described deficiencies with the
SDV design.
In response
to the bul-
letin (PLA-770 dated
May 26,
1981),
the licensee
stated that delta-
pressure
level switches would be installed to provide diversity for
scram initiation.
The commitment
was included in the Unit
1 Oper-
ating License dated July 17,
1982,
as License Condition 2.C.(17).
11
The License Condition stated that prior to startup following the
first refuel'ing outage,
diverse
and redundant
SDV instrumentation for
each
instrumented
volume, including both delta pressure
sensors
and
float sensors,
were to be incorporated
into the
scram discharge
volume system.
6.3
Plant Modification Record
(PMR)82-578, which installed the level
transmitters,
was completed
on- May 2,
1985.
A letter was also sent
to
on May 20,
1985 stating that the design modifica-
tions required
by the License Condition had been
implemented.
Descri tion of Event
On April 10,
1986
an operational
leak test
was in progress
on Unit l.
The unit was in Operational
Condition 4 and was nearing completion of
the
second refueling outage which commenced
on February
15,
1986.
As
part of the surveillance test SE-100-002,
ASME Class
1 Boundary Sys-
tem Leakage/Hydrostatic
Pressure
Testing,
a full reactor
was
manually initiated from the control
room.
At approximately
11:00
a.m.,
IAC technicians
who were performing unrelated
work in the upper
relay room,
noted contradictory
SDV level indications
on panel
1C635.
The Al detector
was indicating upscale
h'igh as expected,
but the
A2=
detector
was indicating downscale
low.
The technicians notified the
control
room and the discrepancy
was investigated.
Operators dis-
patched
to the reactor building
found valves
147F160C
and
D and
147F155C
and
D locked closed,
thus isolating level transmitters
LT-C12-1N016C and
D from the instrument
volume.
As noted above,
these
level transmitters
provide
a reactor protection
system
signal
on high level in the
scram discharge
volume.
Further license
review identified that the system checkoff list (COL) incorrectly
required
these
valves to be locked closed.
The valves for the other
two level transmitters
were found open,
and were correctly aligned in
the
COL.
6.4
Licensee
Investi ation and Corrective Action
Following identification of the isolated level transmitters,
the
li-'ensee
took immediate corrective actions to realign the Unit
1 iso-.
lation valves
and to verify the status of Unit 2, which was operating
at
100 percent
power.
The checkoff list for Unit 1, CL-155-0012,
was
revised to restore
the 'C'nd 'D'evel transmitters,
and the valves
were properly aligned.
The level indications in the upper
and lower
relay panels
were verified to be proper.
The Unit 2 checkoff list
was verified to be correct,
and the isolation valves were physically
checked
to be in the proper position.
A Significant Operating
Occurrence
Report
(SOOR 1-86-113)
was issued
to describe
the event
and to initiate an investigation
and corrective
action.
The licensee
evaluated
the event
and determined it not to be
reportable
in accordance
with 10 CFR 50.72 '
12
On April 20,
1985, during the Unit
1 first refueling outage,
the Con-
trol
Rod Drive Hydraulic System
was lined up by operations
checkoff
1 ist COL-OP-155-001-2,
Revision 4.
This valve lineup listed the
"normal positi'on" for the eight level transmitter
isolation valves
as
locked closed.
The valves were locked closed in the
COL because
the
modification to install the level transmitters
had been only partial-
, ly completed,
and this incomplete installation
was to be is'olated
from the instrument volume.
The modification
PMR 82-578,
was com-
pleted.and
declared
operational
on May 2,
1985.
Prior to declaring
a system operable,
the modification process
re-
quires the completion of Operational
Readiness
Form AD-gA-410-8.
The
form requires that the Operations
section
head
sign the checklist to
indicate that the required actions
are complete.
One of the required
actions
includes updating operating procedures'his
section of the
form was signed
on May 2,
1985.
Licensee
review, following the
event, identi'fied that during the modification closeout
process,
the
operations
section did not identify that the
COL needed
to be revised
to place the
new level transmitters
into service.
The Document
Re-
view sheet,
Form AD-gA-410-3, completed
by the responsible
engineer
did not list any operating
procedures
that required revision.
This
was also true for the
OMISS Abstract.
Both of these
documents
should
have noted that the
COL needed revision,
and normally would have
alerted the Operations
section that
a change
was required.
The level transmitter modification was reviewed
and closed out on
May 2,
1985.
Later the
same
day,
members of the control
room oper-
ating staff noted that the valves were still closed
on the
COL, and
a procedure
change,
(PCAF 1-85-562)
was issued
to open the isolation
valves for the 'A'nd 'B'etectors.
The
PCAF did not address
the
'C'nd 'D'ransmitters.
During the investigation it could not be
determined
why the other two detectors
were not realigned,
but it
appears
there
may have
been
a drawing error at the time which showed
the 'C'nd 'D'etector valves already
locked open.
6.5
Although the licensee
investigation
was not complete
by the
end of
the inspection period,
the root cause
appears
to be the inadequate
closeout of the completed modification.
NRC Followu
Review
The inspectors
reviewed the operating
procedures,
checkoff lists,
surveillance
procedures,
system drawings
and the modification package
related to the
scram discharge
volume to determine
the cause of the
isolated valves
and to determine
whether the inoperability should
have
been detected
previously.
Inspector
review of the modification package
and applicable
documents
confirmed the licensee's
findings.
As discussed
in section 6.4, the
cause of the isolated level detectors
appears
to be
an error made in
the closeout of the
SDV modification package.
13
The level transmitters
are required
by Technical Specifications
to
have
a monthly functionaT and 18-month calibration surveillance test
performed
on them.
The monthly functional test consists of injecting
a signal into the circuit in the relay
room to verify the circuit
response.
The isolation valves are not manipulated during this test,
and the level transmitter is not disturbed.
The
18 month survei 1-
lance test requires
the manipulation of the transmitter isolation
valves,
but since the system
had just been
placed in service
in Hay
1985, this surveillance test
had not yet been
performed.
It is
possible that this inoperability would have
been identified during
the calibration procedure
which is scheduled
for November
1986.
All
of the surveillance tests
performed
on the isolated detectors
met the
acceptance
criteria.
The post-modification testing that was performed
also did not verify that the level transmitters
were connected
to the
process.
The system
schematic
diagrams
were reviewed to determine if the
post-trip review process,
following one of the three reactor
during this period,
should
have detected
the inoperability of the
level transmitters.
The level transmitters
provide inputs to the
trip system,
SDV high level alarms,
and plant computer points.
The
inputs to the
system
are in series with the float switch inputs;
so that as long as the float switches
operate
properly, the
RPS sys-
tem will respond
as designed
on
a
SDV high level condition.
The
alarm
and computer point contacts
are in parallel
so that any input
will provide the indication.
Due to this circuit configuration,
the
inoperability of the transmitters
could not have
been detected
by
control
room indications or the plant computer printouts.
The only
direct indication available is the level meters
in the relay room,
which would only indicate during
a scram.
The inspectors
conducted
a walkdown of the Unit
1 and Unit 2
SDV in-
stallations.
Several
discrepancies
were identified with the Unit 2,
'OL and drawings.
Administrative procedure
AD-QA-302, System Status
and Equipment Control, states
that root valves (first valves off
process
line) that supply safety related instrumentation will be
locked open.
During the walkdown of the Unit 2 system it was noted
that four of the isolation (root) valves were not locked open,
as
were the. other twelve valves.
The checkoff list CL-255-0012 also
listed these
valves
(247155A,
B,
C,
and
D) as
open rather than locked
open.
This does
not appear
to be consistent with the administrative
procedure.
The system drawing was also incorrect.
P&ID H-2147
shows
that isolation valves
247F115A
8
B and
247F160A
8
B are locked closed
while they should
be locked open.
This item is
a violation.
(388/86-04-02)
6.6
Technical
S ecification Adherence
Technical Specification Limiting Condition for Operation
(LCO) 3.3. 1
requires that during Operational
Conditions
1, 2,
and
5 (with any
control rod withdrawn), the reactor protection
system instrumentation
lf
%y
'I
channels for the
scram discharge
volume high wat'er level transmitters
be operable.
Table 3.3. 1-2 states, that two operable
channels
per
trip system
are the minimum required.
With the
number of operable
channels
less
than the required
Minimum
channels
per trip system,
for both trip systems,
at least
one trip system is to be placed in the tripped condition within
1
hour and the unit is to be in at least
Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
(if starting in Operational
Condition
1 or 2).
6.7
Contrary to the above,
between April 20,
1985 and April 10,
1986 two
scram discharge
volume high water level transmitters
were inoperable,
in that their isolation valves were
shuts
This is
a violation.
(387/86-06-05)
Safet
Si nificance
As described
in sectiop 6.2,
the two level transmitters that were
found isolated provide inputs to the reactor protection
system.
One
detector
from each
RPS trip system
was affected.
The remaining
two
level transmitters,
one per division, were sufficient to provide
a
reactor
scram signal
on high scram discharge
volume water level, as-
suming
no single fai lure.
In addition,
the four float switches,
which provide diverse
and redundant initiation signals
were operable.
Inspector
review of completed surveillance
tests verified that the
float switches
were operable,
and that there
has not been
a history
of failures of these detectors.
Each
SDV instrument
volume is monitored
by two other level detectors,
which provide alarm functions.
One float switch on each
volume pro-
vides
a "not drained" alarm,
and another
provides
a
Rod Block Signal.
The four high level float switches also provide
a high level alarm,
in addition to the
RPS signal.
Therefore, if any leakage
had oc-
curred, it would have
been annunciated
in the control
room.
During
normal operation
the
SDV vent and drain valves are open, allowing any
leakage
to drain from the volume.
The level transmitters
were installed during the Unit
1 first refuel-
ing outage
in May 1985.
Therefore,
the unit did operate
safely,
and
in accordance
with Technical Specifications,
for approximately three
years with only the four float switches
The objective of
the design modification which installed the additional transmitters
was to provide diversity,
so that
a single
random failure or poten-
tial
common cause failures could be accomodated.
Investigations
and
test performed
by
BWR licensees
have
shown that crud buildup,
human
error, manufacturing defects,
hydrodynamic forces
and environmental
concerns
have led to past
common-cause
failures with the float
switches.
The level transmitters
were added to the Technical
Speci-
fications by the licensee
following the modification.
15
Although the isolation of the level transmitters
appears
to be of
minimal safety consequence,
the adequacy of the. closeout
and testing
of safety-related
modifications must be viewed as
a safety concern.
Since the
same controls are
used
on other safety-related
modification
activities, this area
should
be addressed
in the licensee's
correc-
tive action.
6.8
Summar
of Findin
s
Technical Specification 3.3. 1, which requires
four SDV level
transmitters
to be operable
in Operational
Conditions
1, 2,
and
5,
was violated.
The valves to two of the level transmitters
were isolated
on April 20,
1985,
and Unit
1 operated
from June 8,
1985 until February
15,
1986 when the unit shutdown for a
refueling outage.
(There were three short forced outages
during
the period).
The isolated valves were discovered
on April 10,
1986.
The level transmitters
were left isolated after the completion
of a modification due to
a failure in the modification closeout
process.
The checkoff list was not revised during the closeout
process,
and the operating
procedures
were not identified as
needing revision
on the Document
Review Form, or the
OMISS ab-
stract.
Two of the detectors
were later valved in when identi-
fied by operations
personnel.
The closeout
process
needs
to be
reviewed for adequacy.
Post-modification testing did not verify
that the detectors
were connected
to the process.
Due to the configuration of the
SDV level circuitry, and indica-
tion, the licensee
could not have
been
expected
to identify the
isolated detectors
during normal plant operation.
The
SDV high
level alarm contacts
are paralleled with the float switch contacts
so that either device will actuate
the alarm.
Therefore, if the
float switches
responded
as designed,
the failure of the level
transmitter
would be masked.
The
same
type of circuitry exists
for the computer points.
Review of the post-trip data would not
have
shown
any abnormal
occurrences.
The level transmitter in-
dication in the relay room, observed
during
a scram,
was the
only method to identify the isolated detector.
The closed
valves would have
been manipulated
by the 18-month calibration
procedure,
but it was not due to be performed until November
1986.
Since the isolated level transmitters
provided redundant sig-
nals,
and the four float switches
were fully operable,
the fact
that the detectors
were inoperable
appears
to be of minimal
safety significance.
The unit operated for approximately three
years prior to the installation of the level transmitters.
16
Several
procedural
and drawing problems
were noted during the
investigation.
Although the station administrative
procedures
require that instrument root valves
be locked open,
the Unit 2
checkoff list did not lock open all of the level transmitter
isolation valves.
In addition, the Unit 2 system drawing,
M-2147, incorrectly stated that four of the isolation valves
were normally locked closed:
The'alves
were found in the cor-
rect position.
The licensee
investigation
has not been
completed
and more in-
formation
may become available at
a later date.
This will be
reviewed during
a later inspection.
7.0
Unit
1 Refuelin
Outa
e Activities
7. 1
Refuelin
Outa
e
Summar
During this period, Unit
1 continued its second refueling outage
which began
February
15,
1986.
Major outage work during this period
consisted
of restoration of Division I systems,
bulk work and resto-
ration of Division II systems,
refueling, integrated
system testing,
and preparations
for startup.
It was noted in the last report peri-
od, that
some linear indications were identified on the
steam dryer
and support block during in-vessel
inspections.
These indications
did not require repair.
Refueling began
on March 21 and was complet-
ed March 28.
'Due to an excessive
number of failures of snubbers,
the
licensee
was required to remove
and test
more than
1000 snubbers.
Outage critical path time was not impacted.
Following refueling com-
pletion,
4KV bus outages
were conducted
to install
a degraded
grid
voltage modification.
The bus outages
were followed by loss of
offsite power and
LOCA testing
which was completed April 7.
The
reactor
vessel
head
was reinstalled
and Operational
Condition
4 en-
tered
on April 8.
The Operational
hydrostatic test
was completed
on
April 11.
Leaks identified during the test,
including leaks in the
reactor vessel
head piping and two control rod drives,
were repaired.
At the end of the report period,
the outage
was still on schedule with
reactor startup
expected
to occur on April 18.
7.2
Desi
n Chan
es
and Modifications
The inspector
observed
portions of selected modification activities
to determine that:
Limiting Conditions for Operation
were met while
components
or systems
were
removed
from service;
required administra-
tive reviews
and approvals
were obtained prior to initiating the
work; the installation conformed to the'rawings
and other design
documents; activities were conducted
using formal work control proce-
dures;
and
gC hold points were established
where required.
17
Portions of the following activities were 'observed:
PMR 84-3113,
Degraded Grid Voltage Protection,
performed
under
CWO C51225
on March 21,
1986 (1A202
4KV Bus).
No unacceptable
conditions were identified.
7.3
Com lex Surveillance
Test Witnessin
The inspector
observed
the performance of portions of certain
complex
18-Month Surveillance tests to determine that:
the Technical
Speci-
fication (TS) surveillance
requirement
was covered
by an approved
procedure;
that prerequisites
were completed;
special
test equipment
was calibrated;
required data
was accurately
recorded;
appropriate
revision of the test procedure
was available
and in use
by test per-
sonnel;
system restoration
was accomplished
upon completion of test-
ing; and the surveillance
was performed within the time frequency
specified
by the Technical Specifications.
Portions of the following tests
were observed:
18-Month Diesel Generator 'C'uto Start
and
ESS
Bus
1C Energization
on Loss of Offsite Power - Plant Shutdown,
performed
on April 4,
1986.
18-Month Diesel Generator 'O'uto Start
and
ESS
Bus
1D Energization
Plant Shutdown,
performed
on April 7,
1986.
18-Month Diesel Generators 'B'nd 'D'uto Start
and
ESS
Buses
1B and
1D Energization
with a
LOCA - Plant Shutdown,
performed
on April 7,
1986.
18-Month Diesel Generators 'A'nd 'C'uto Start
and
ESS
Buses
1A and
1C Energization
with a
LOCA - Plant Shutdown,
performed
on April 5,
1986.
The following items were noted:
During the performance of SE-124-107,
the 'C'SW pump did not
start automatically
as designed.
In addition, the 'C'SW
pump
and
1A RHRSW pump could not be manually started
from the control
room.
Licensee investigation later found that relay
44AX1 had
not picked up.
It was replaced.
A data review following the
test
found that timing relay 62A-20302 for the
1C
RHR pump was
'out of tolerance.
It was also repaired.
During SE-124-D02,
the inspector
noted that
speed oscillations
occurred
on the 'D'iesel
generator
following the
shutdown of
the
RHR pump.
Frequency
decreased
to approximately 58.5 several
times before the test
was completed.
t
lt
18
During the performance of SE-124-C02,
the inspector
noted
some
discrepancies
with the procedure
changes
that were issued prior
to the test.
PCAF 1-86-486
added
an additional prerequisite for
the test,
but the step
was not added to Attachment
A for signing
for completion of the prerequisite.
The change
added ventila-
tion fan
1V210C
(RHR Pump
Room Unit Cooler) since drywell cool-
ing fan
1V414A was out of service.
Just prior to starting the
test,
the inspector discussed
the discrepancy with the test di-
rector,
who then noted the error in the
PCAF.
In addition, the
PCAF had not been properly incorporated into the procedure.
The
test director then issued
a
new
PCAF to the procedure
and
had
the additional
fan started
as required.
The inspector
had
no
further
concerns'.0
Alle ation - Dravo
C
On March 31, the inspector received
an allegation via telephone
from a
recently terminated
Dravo, Inc.
QC inspector.
Dravo, Inc. is the con-
structor for the fifth diesel. generator
(D/G) project.
The individual
indicated that
he
had
been terminated
for refusing to perform an inspec-
tion on bolts to be
used with Unistrut supports.
He indicated that
he
refused
to perform the inspection
because
a Non-Conformance
Report
(NCR)
was outstanding,
relating to the bolts.
His concern
was that Dravo im-
properly used
a Gibbs
& Hill document to authorize cutting of the bolts,
and questioned
whether it was acceptable
to cut these bolts.
The inspector
reviewed
NCR Number 361, Construction Site Procedures
(CSP)
8. 1 "Non-Conformance
Reports",
CSP 8.4 "Configuration Control
and Informa-
tion Request",
Quality Control Procedure
(QCP) A-10 "Control of Noncon-
forming Items",
and Information Request
( IR) PP&L-009.
The inspector also
discussed
this incident with the
PP&L Assistant
QA manager for the fifth
D/G project,
the Dravo, Inc.
QC Site Supervisor
and
a
PP&L engineer.
On
February
27,
1986, Information Request
PP&L-009 was issued
requesting
per-
mission to cut 1/2"-13 x
1 3/16" and 1/2"-13
x
1 1/2" bolts to
a length of
1/2" and 15/16" respectively.
The bolts were to be used with Unistruts
and were too long.
On February
27, the
IR was resolved indicating that
the bolts could be cut.
The
IR was written on
a Gibbs
& Hill (G&H) IR
form.
The nonconformance
specified
on
NCR ¹361 dated
March 25,
1986 was
that IR PP&L-009 was prepared
on the wrong form (Attachment
C rather than
Attachment
F to
CSP 8.4)
~
The
NCR specified that this was nonconforming
because
the approval authorities
and distribution are different.
The
was dispositioned
"use-as-is"
on March 26 based
on the fact that it was
an
isolated
case
and that the
IR was properly dispositioned
by PP&L Nuclear
Plant Engineering.
However,
the
NCR was apparently
not dispositioned at
the time the individual refused to perform the inspection.
In reality, the
PP&L and Gibbs
& Hill IR forms are virtually identical
forms.
The incorrect form was
used but was processed
in accordance
with
procedure.
The
NCR originator
and the
NCR log indicated that
a "Hold" Tag
was not issued for this
NCR.
Therefore,
no equipment
was placed in a
19
"hold" status.
The governing procedures,
gCP A-10 and
CSP 8. 1, however,
do not recognize
issuance
of an
NCR without a "hold" tag although the pro-
cedures
do not explicitly state that
NCRs must use "hold" tags.
Since
this issue
does not relate to the safety
impact of the allegation, it will
not be further addresssed.
The potential
safety concern relates
to use of the cut bolts.
Since the
bolts were only shortened,
the strength properties of the bolt are not
affected.
The bolts were to be used in Unistrut as part. of a conduit sup-
port and the bolts would be engaged with a spring nut.
PP&L engineering,
which was the proper design authority,
approved
the cutting and use in
this application.
The inspector
reviewed
PP&L Specification
C-1055,
"Technical Specification for Routing
and Installation of Conduit and
Conduit Supports
in the 'E'iesel
Generator Building", which indicates
that 1/2" diameter bolts are acceptable
for this application
and the spec-
ification does
not preclude bolt cutting.
Therefore,
there is no safety
concern 'with the use of these bolts.
This allegation is closed.
9.0
Reactor
Hi
h Pressure
Switch Head Connection
On March 6,
1986 during the current Unit
1 refueling outage,
the licensee
identified that the head correction calculations of PS-B21-1N023A,
B,
C,
D
(Unit
1 reactor vessel
steam
dome pressure
switches)
were in error.
These
pressure
switches
provide input to the reactor protection
system
(RPS) to
scram the reactor
on high pressure.
The head correction calculational
error was in the non-conservative
direction by 9.7 psig.
The nominal trip
setting in the Technical Specifications
(TS) is 1037 psig.
The allowable
value is 1057 psig.
The licensee
reviewed past calibration data
from 1982
to the present
and identified no cases
in which the unit was operated with
the pressure
switch setting exceeding
the Technical Specification allow-
able value
due to this head correction error.
The calculational error did
cause
the "As Left" setting of the switches following a calibration to be
in excess
of the nominal trip setting of 1037 psig
on many occasions.
The
surveillance
procedure,
SI-158-303,
specifies
an "As Left" value for these
switches to be less
than or equal
to the nominal trip setting,
so that
between calibrations,
instrument drift should not cause
the pressure
switch setting to exceed
the allowable valves.
However,
since the allow-
able value was not exceeded,
no Technical Specification violation occurred.
The head correction calculation error resulted
from using
an improper ele-
vation for the pressure
switches.
The licensee
reviewed
head correction.
calculations for the corresponding
Unit 2 pressure
switches
and
50 other
Unit
1 and Unit 2 instruments.
No other discrepancies
were identified.
The inspector
reviewed portions of the pressure
switch surveillance
data
and elevation data for other
instruments
and identified no discrepancies.
The calcul'ations
were performed
by the
same individual and appear to be
isolated occurrences.
The inspector
had
no further concerns.
20
0.
~Ei
tl
On April 18,
1986 the inspector discussed
the findings of this inspection
with station
management.
Based
on
NRC Region I review of this report and
discussions
held with licensee
representatives,
it was determined that
this report does
not contain information subject to
restrictions.