ML17227A455
| ML17227A455 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 05/29/1992 |
| From: | Elrod S, Landis K, Schin R, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A453 | List: |
| References | |
| 50-335-92-07, 50-335-92-7, 50-389-92-07, 50-389-92-7, NUDOCS 9206150031 | |
| Download: ML17227A455 (33) | |
See also: IR 05000335/1992007
Text
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++*++
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-335/92-07
and 50-389/92-07
Licensee:
Florida Power
5 Light Company
9250 West Flagler Street
Miami, FL
33102
Docket Nos.:
50-335
and 50-389
License Nos.:
and
Facility Name:
St. Lucie
1 and
2
Inspection
Conducted:
arch
24 - May 2,
1992
Inspectors:
S.
.
o , Sensor
Ress
ent
nspector
Date
lgne
. A. Scott,
Re
ent Inspector
Dat
Sig ed
Approved by:
R.
. Sch n,
roj t Engineer
ls
ection
le
Division of Reactor Projects
D te Si
ne
at
lgne
SUMMARY
Scope:
This routine resident inspection
was conducted onsite in the areas of plant
operations
review, maintenance
observations,
surveillance observations,
evaluation of licensee
self-assessment
capability, fire protection review,
preparation for refueling, review of special reports,
review of nonroutine
events,
followup of previous inspection findings,
and followup of regional
requests.
Results:
This inspection
found Unit 1 continuing to operate in a routine manner with an
obvious regard for safety.
Unit 2 set
a light water reactor world record of
502 days of continuous
power operation
when it shut
down on April 20 for
refueling.
During the Unit 2 shutdown,
the turbine did not trip automatically
or manually when the operators
tripped the reactor.
Immediate operator
response
was excellent
and subsequent
root cause investigation
has
been
vigorous.
Preparation
and control of entry into reduced inventory were quite
well controlled.
A number of surveillances
and maintenance activities were
well performed.
One procedure violation was 'observed while setting
steam
generator safety valves.
Another violation of technical specifications
was
observed
involving isolation of a containment
pressure
transmitter sensing
line.
920615003k
920529
ADOCK 05000335'PR
Within the areas
inspected,
the following violations were identified:
VIO 389/92-07-03;- Isolation of Containment
Pressure
Sensing
Line Without
Placing Effected Instrumentation
Channels
in Trip or Bypass
as Required,
paragraph
2a.
VIO 389/92-07-04,
Failure to Follow Procedure for Setting
Safety Valves, paragraph
5k.
Within the areas
inspected,
the following non-cited violations were identified
associated
with events
reported
by the licensee:
NCV 335/92-07-01,
Fuel Handling Building Ventilation Radiation Monitor
Out of Service
Due to Personnel
Error, paragraph
9a.
NCV 335/92-07-02,
Containment
Atmosphere Particulate
and
Gaseous
Radioactivity Monitors Out of Service
Due to Personnel
Error, paragraph
9b.
REPORT DETAILS
Persons
Contacted
Licensee
Employees
D. Sager,
St. Lucie Plant Vice President
G. Boissy, Plant General
Manager
J. Barrow, Fire/Safety Coordinator
H. Buchanan,
Health Physics
Supervisor
C.--Burton, Operations
Manager
R. Church,
Independent
Safety Engineering
Group Chairman
R. Dawson, Maintenance
Manager
R. Englmeier,
Nuclear Assurance
Manager
R. Frechette,
Chemistry Supervisor
J. Holt, Plant Licensing Engineer
C. Leppla, Instrument
and Control Supervisor
L. McLaughlin, Licensing Manager
G. Madden, Plant Licensing Engineer
A. Menocal, Mechanical
Supervisor
T. Roberts, Site Engineering
Manager
L. Rogers, Electrical Supervisor
N. Roos, Services
Manager
C. Scott,
Outage
Manager
M. Shepherd,
Operations Training Super visor
D. West, Technical
Manager
J. West, Operations
Supervisor
W. White, Security Supervisor
D. Wolf, Site Engineering Supervisor
E. Wunderlich, Reactor Engineering Supervisor
Other licensee
employees
contacted
included engineers,
technicians,
operator s, mechanics,
security force members,
and office personnel.
NRC Employees
- S. Elrod, Senior Resident
Inspector,
St. Lucie Site
- M. Scott, Resident Inspector,
St. Lucie Site
R. Schin, Project Engineer,
Division of Reactor Projects
- Attended- exit interview
2.
Acronyms=and=. ini:tial.-isms- used-throughout this report are listed in the
last paragraph.
Review of Plant Operations
(71707)
Unit-1 began
and ended the inspection period at power - day
131 of
continuous
power- operation-.-
Unit 2 began the inspection period at power and then shut
down on April 20
for a normal refueling outage.
The outage
was scheduled
to last until
June '27.
Unit 2 set
a light water reactor world record for continuous
power operation during this just completed
run of 502 days.
E
Plant Tours
The inspectors periodically conducted plant tours to verify that
monitoring equipment
was recording
as required,
equipment
was
properly tagged,
operations
personnel
were'ware of plant conditions,
and plant housekeeping
efforts were adequate.
The inspectors
also
determined that appropriate radiation controls were, properly
established,
critical clean areas
were being controlled in accordance
with procedures,
excess
equipment or material
was stored properly,
and combustible materials
and debris
were disposed of expeditiously.
During tours,
the inspectors
looked for the existence
of unusual
fluid leaks, piping vibrations, pipe hanger
and seismic restraint
settings,
various valve and.breaker.
positions,
equipment caution
and
danger tags,
component positions,
adequacy of fire fighting
equipment,
and instrument calibration dates.
Some tours were
conducted
on backshifts.
The frequency of plant tours
and control
room visits by site management
was noted to be adequate. "
'he
inspectors routinely conducted partial
walkdowns of ESF,
ECCS,
and support systems.
Valve, breaker,
and switch lineups
as well as
equipment conditions were randomly verified both locally and in the
control
room.
The following accessible-area
ESF system
and area
walkdowns were made to verify that system lineups were in accordance
with licensee
requirements
for operability and equipment material
conditions were satisfactory:
Unit 2
CCW platform,
Unit 1 AFW trestle
space,
Unit 1 mechanical
room,
and
Unit 2
ICW pump area.
On April 29, during
a tour of the Unit 2 containment,
the inspectors
observed
an instrument sensing line penetrating
the containment at
58.
The penetration
was labeled to indicate that.its
function involved differential pressure
between the containment
and
RAB.
The sensing line was capped.
Subsequent
pressure test
confirmed the sensing line to have indeed
been isolated.
Drawing
2998-8-231,
sheet
P136,
Instrumentation Installation Details Unit 2,
Rev 1, showed that this line served safety-related
PT-07-2C,
channel
"C" containment
pressure
transmitter.
This transmitter provided one
of four containment
pressure
signals for several
safety functions-
reactor trip, containment isolation actuation,
containment
spray
actuation,
and safety injection actuation.
When found, this sensing
line and associated
transmitter,
one of four, was not available to
perform its safety function for either the
The
pressure
transmitter would behave
as if the channel
were in "bypass."
Three conditions contributed to the probability of this occurrence:
(2)
(3)
The licensee
did not ensure
the sensing lines were open in
conjunction with equipment calibration or at the beginning of
operating cycles.
The licensee calibrated
containment
pressure
sensing
instrumentation
on
a refueling outage
basis
per
TS 4.3.1. 1 and
associated
table 4.3-1, Reactor Protective Instrumentation
Surveillance
Requirements,
and
TS 4.3.2. 1 and associated
table
4.3-2,
Engineered
Safety Features
Actuation System
Instrumentation Surveillance
Requirements,
which was
implemented
in part by ILC procedure
2-1400153C,
Reactor Protection System-
Engineered
Safeguards
System
Loop Instrumentation Calibration
for Containment Pressure..
This procedure
al,lowed test equipment
hookup near the pressure
transmitter in the
RAB, isolated
by
closing
a valve between
the test point and the containment
sensing point.
The sensing lines from the containment to the
pressure
transmitter were not specifically tested.
At the
conclusion of the
1989 refueling outage,
based
on an
NRC concern
that blockage of open-ended
sensing lines could exist yet be
undetected,
the licensee
blew down the sensing lines
and
verified air flow per plant work order 7826/62.
The licensee
did not subsequently
test the lines during the 1990 refueling
outage.
Drawings, procedures,
and labels did not clearly show the
function of sensing lines and differentiate between active
and
spare lines.
Two of the penetrations
involved had four lines in each.
Three
of the four lines were capped
and one
had
an open-ended
90
degree
male thread adaptor attached.
The other two penetrations
had
one line each with the open-ended
90 degree
male thread
adaptor attached.
One of these single lines
was the
one found
isolated.
Containment pressure
instrumentation
sensing
tubing
.and fittings penetrating
into the containment
were described
on
drawing 2998-B-231, sheet
P136.
Neither the drawing, nor
labels,
nor other reasonably
available information visually
showed which of the'ultiple lines were in service
and which
were the spares.
They all looked alike except for the end
fittings threaded
onto the pipes.
Drawings, procedures,
and labels did not clearly show the
acceptable
tubing and end-fitting configuration of sensing lines
inside containment.
Containment pressure
instrumentation
sensing tubing and fittings
penetrating into the containment
were described
on drawing
2998-B-231, sheet
P136.
Neither the drawing, nor labels,
nor
other reasonably
available information visually showed the
acceptable
tubing and end fitting configuration.
The bill of
material listed items that apparently
would result in an
open-ended
l'ine with an exposed
male tubing fitting thread at
the end.
In contrast,
the drawing did show, outside containment
in the
RAB, a 3/8 inch mud dauber
cap (item 70A) on the
transmitter high-side reference
sensing .line.. This. device was .-
intended to prevent blockage of the reference
sensing line by
for eign material
such
as
an insect.
The device also 'provided
a
finished appearance
.to the installation.
The inspector judged
that exposed
tubing threads
on the end of a line penetrating
containment,
coupled with poor labeling, would certainly invite
someone
to install
a cap during
a pre-startup
inspection.
Unit 2 TS addressed
this equipment in several
places
because
the
pressure
transmitter,
served: multiple safety. functions:.
~ 1
II
Unit 2 TS 3.3.2
and included Table,3.3-3 required that
instrumentation
be
OPERABLE for the Containment
Spray function
in Operational'odes
1, 2, or'3; including a minimum of three of
the four channels
of Containment
Pressure - High-High.
Action
Statement-
17 required that, with three of the four channels
OPERABLE, the inoperable
channel
must be placed in the tripped
condition within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
Action Statement
17 further stated
that-one additional
channel
may be bypassed for up to two hours
for surveillance testing.
Unit 2 TS 3.3.2 and included Table 3.3-3 also required that
ESFAS instrumentation
be
OPERABLE for the Safety Injection,
Containment Isolation,
and. Main Steam Line Isolation functions
in operational
Modes 1, 2, or. 3; including a minimum of three of
the four channels
of Containment
Pressure - High.
Action
Statement
13 required that, with three of the four channels
OPERABLE, power operation
may continue provided that the
channel is placed in the bypassed
or tripped
condition within one hour.
Action Statement
14 required that,
with two of the four channels
power operation
may
continue provided that one of the inoperable
channels
has
been
bypassed
and the other inoperable
channel
is placed in the
tripped condition within one hour.
Unit" 2 TS; 3.3..1
and .included--Table 3.3-1 required that
instrumentation
be
OPERABLE. in operational
Nodes
1 or 2,
including
a- minimum of three of the four channels of Containment
Pressure - High.
Action Statement
2.a required that, with three
of the four channels. OPERABLE, power operation
may continue
provided that. the inoperable.'channel
is placed
on the tripped or
bypassed- condition within one hour.
Action Statement
2.b
required that, with two of the four channels
OPERABLE, power
operation
may continue provided that one of the inoperable
channels
has
been
bypassed
and the other inoperable
channel
is
placed in the tripped condition within one hour.
Containment Pressure
Channel
C (High and High-High) was actually
inoperable during the previous operating cycle from about at least
December,
1990, to April 22, .1992,
and possibly from April 13,.1989,
when the sensing line was last blown out,
because its instrument
sensing line inside containment
was capped,
and Containment
Pressure
Channel
C was not placed in the tripped or bypassed
condition as
required.
During most of this time, St. Lucie Unit 2 was operated
in
Mode
1 or 2.
Additionally, between
December,
1990 and April 22,
1992, with Containment
Pressure
Channel
C inoperable,
another
channel
of containment
pressure
was placed in bypass
on April 19,
1992, for
three hours while the unit was operated
in Mode
1 or 2.
Between
April 13,
1989 and April 22,
1992, with Containment
Pressure
Channel
C inoperable,
another
channel of containment
pressure
was placed in
bypass
on six different occasions, for a total of approximately
97
hours, while the unit was operated
in Mode
1 or 2.
This is identified as
VIO 389/92-07-03,
Isolation of Containment
Pressure
Sensing
Line Without Placing Effected Instrumentation
Channels
in Trip or Bypass
as Required.
Subsequent
to discovery of the capped
sensing line, the licensee
has
expeditiously evaluated
the potential root causes
and consequences
of
the condition.
Activities included:
(1)
Analysis of maintenance
and operating history to:
(a)
Bound the inoperability of containment
pressure
channel
C.
The Unit 2 sensing
lines were blown out on
19 April, 1989-
two outages
ago.
(b)
Correlate other
equipment
outages
due to maintenance
or
test.
(2)
Engineering analysis of the potential
accident
consequences
of
this channel
being inoperable.
The analysis
assumed .the entire
containment
spray system
was inoperable.
The licensee's
analysis
concluded that no containment
breach nor additional
core
damage
would occur.
(3)
Development of a technique to use
on an operating plant to check
Unit 1 and Unit 2 to ensure that the
same conditions
were not
present
elsewhere.
The inspector
observed
these tests
per
NPWOs
7340/63 (Unit 1) and 7452/64 (Unit 2).
The test consisted of
blowing air from a hand-carried
low pressure
storage
tank
through the sensing lines from a test connection
near the
transmitter.
The pressure
gage would indicate while air was
flowing but would immediately drop to zero when the tank's
discharge ball valve was shut, thus
showing
a clear flow path.
All four sensing lines for each of Unit 1 and Unit 2 were clear.
(4)
Search of operating
records
from previous reactor plant heatups
to determine if the isolated pressure
sensing line could have
been detected
during startup;
The licensee
concluded that the
lack of indication .was reasonable
based .on the containment
volume of'about 2.5 million cubic feet*and the small
amount of
heatup due.to containment cooling in operation.
(5)
PSL-2JFR-92-004
dated
Hay 7,
1992
and evaluating the risk input to St. Lucie Unit 2 due to the
isolation of PT-07-2C.
It concluded that the loss of that
channel
represented
a 3.9E-8 per reactor year increase
in CDF
over having all channels
The frequency calculated
was
1.23E-7 per reactor. year.. This was
compared .to NRC.criteria
listed in GL 88-20:.-
It was less
than the 1.0E-6 screening
value;
A St. Lucie total
CDF has not been determined.
Even if it
were as low as
1.0E-5 per reactor year, the 1.27E-7
contribution would be less
than the
5X of total
screening
value referenced
in GL 88-20.
Even if the evaluated
sequence
were conservatively
assumed
to result in core
damage
and containment failure, the
estimated
CDF was still less
than the 1.0E-6 screening
value.
Loss of the spray function did not constitute
a containment
bypass function.
The 1.2E-7 per reactor year sequence
would not therefore
be
considered potentially important.
(6)
Physical
and procedural
changes
were being pursued to identify
sensing lines opening into the containment or annulus
and to
ensure
the required status
would be easily understood.
Identification tags to indicate the purpose
and required
condition of these
sensing lines.
Changes
to procedures
for surveillance
and plant startup to
verify that the lines are clear.
Drawing revisions
as necessary
to capture
the required line
status
and to install end covers
(mud dauber screens)
on
the ends of the'lines.
The inspector
had
no further questions at the time.
Plant Operations
Review
The inspectors periodically reviewed shift logs and operations
.
records,
including data sheets,
instrument =traces,.
and records of
equipment malfunctions.
This review included control
room logs
and
auxiliary logs, operating orders,
standing orders,
jumper logs,
and
equipment tagout records.
The -inspectors routinely observed
operator
alertness
and demeanor
during plant tours.
They observed
and
evaluated
control
room staffing, control
room access,
and operator
performance
during routine operations.
The inspectors
conducted
random off-hours inspections
to assure that operations
and security
performance
remained at acceptable
levels.
Shift turnovers
were
observed to verify that they were conducted in accordance
with
approved
licensee
procedures.
Control
room annunciator
status
was
verified.
Except as noted below,
no deficiencies
were observed.
During this inspection period, the inspectors
reviewed the following
tagouts
(clearances):
2-3-104
2B
EDG [12 cylinder diesel
fan shaft repair],
2-3-35
HVE 10B Motor Replacement
[routine maintenance],
2-4-9
2A HPSI
pump breaker repair (see the maintenance
paragraph),
2-4-24
2B1 circulating water
pump out for water box
cleaning,
and
2-4-222
HVE 6B Heater Control Inspection.
Unit 2 commenced
a shut
down for refueling
on April 20.
Since this
was the first Unit 2 shutdown in 502 days,
both the licensee
and
inspector
showed additional interest in operating staff performance
and equipment reliability.
The operating staff performed well during
both routine evolutions
and unexpected
occurrences.
The licensee
treated
the shutdown
as
an infrequently performed evolution per
0010020,
Rev 1, Conduct of Infrequently Performed Tests or Evolutions
at St. Lucie Plant,
and focused additional
management attention.
Pre-evolution briefings were held by the operations
supervisors
and
the procedures
were talked through at length
by the on-shift licensed
operators
during the shift prior to commencement.
Copies of needed
procedures
were -tabbed
and conveniently -placed in notebooks within
arm reach of the reactor control station.
The quality assurance
staff also provided extensive
coverage.
The licensee
performed initial power reduction per
OP 2-0030125,
Rev
14, Turbine Shutdown - Full Load to Zero Load.
Procedure
adherence
was excellent.
Reactor
plant and steam plant equipment generally
worked very well, with a few exceptions.
Prior to commencing
shutdown, the 2A train 6.9
KV circuit breaker
from the generator
auxiliary transformer would not open from the control
room to
transfer the switchgear
feed to the startup transformer.
The
shutdown
was delayed until the circuit breaker
was returned to
service in about
two hours.
During the power reduction,
the B-train
low-flow feedwater controller-level input failed, so an operator
manually controlled
2B
SG level from the control
room console.
At low power and late in core life, the licensee
found that axial
shape
index was difficult to keep within limits using the
controls allowed by TS.
The operators
had previously decided that,
if three of four pretrip alarms initiated, they would trip the
reactor manually rather than continue attempting
a manual
shutdown.
When these
alarms indicated at 2:38 a.m.
on April 21, the reactor
operator tripped the reactor from 12 percent
power and initiated
standard
post trip actions
per 2-EOP-01,
Rev 6, Standard
Post Trip
Actions.
Though the reactor trip itself was.uneventful .with reactor plant
safety equipment subsequently
performing as designed,
the turbine
trip function did not perform as designed.
The turbine did not trip
either automatically or,manually from the control board.
Operators
immediately carried out compensatory
actions,
including shutting the
main steam isolation valves, tripping the generator output circuit
breaker,
stopping the turbine control
DEH pumps,
and tripping the
turbine using the local manual control at the turbine front standard.
After the safety functions of 2-EOP-01 were met, the licensee
initiated 2-EOP-02,
Rev 5, Reactor Trip Recovery.
The licensee
subsequently initiated a root cause investigation
and maintained Unit
2 at normal no-load temperature for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
pending initial
investigation,
removal of certain
key components for dissection,
and
determination that no critical evidence
would be destroyed.
The licensee started reactor cooldown
on April 22 per
OP 2-0030127,
Rev 43, Reactor Plant Cooldown - Hot Standby to Cold Shutdown.
The
cooldown of about
35 degrees
per hour was plotted
as required using
data sheets
1, 2, and 3.
Unit 2 entered
operational
modes
4 and
5
later. that day.
During the inspection period, Unit 1 entered
a reduced
RCS inventory
condition to install
SG nozzle
dams.
The following items were
observed prior to or during this evolution:
Containment Closure Capability - Instructions were issued to
accomplish this; personnel
and tools were on station.
RCS Temperature
Indication - Four normal
mode
1 CETs were
available for indication.
Two were from train A and two from
train B.
RCS Level Indication - Independent
RCS wide and narrow range
level. instruments
which indicate in the control
room were
An additional
Tygon tube loop level in the
containment
was
manned during level changes
and checked
every
two hours during static conditions.
.
RCS Level Perturbations
When
RCS level
was altered, additional:
operational
controls were invoked.
At plant daily meetings,
operations
took actions to ensure that maintenance
did not
consider performing work that might effect
RCS level or shutdown,
cooling.
RCS Inventory Volume Addition Capability - Nominally one (of
three)
charging
pumps
and
a HPSI
pump were available for RCS
addition.
RCS Nozzle
Dams - Procedural
control
was via MMP-01.05,
Rev 0,
Steam Generator. Primary Side Maintenance.
This required the
pressurizer:manway
be removed prior to installation:of"nozzle
dams, that hot leg manways
be opened'rior to cold leg manways,
and that cold leg dams
be installed prior to hot leg dams.
The
removal of these
items is in the reverse
order.
Vital Electrical
Bus Availability - Both trains of vital power
were available.
Operations
would not release
busses
or
alternate
power sources for work.
Draindown was held
up pending
completion of emergent
work in the switchyard.
Overall, operational
controls were well planned
and executed.
The
off-normal Unit 2 turbine shutdown
was well handled.
c.
Technical Specification
Compliance
Licensee
compliance with selected
TS LCOs was verified. This included
the review of selected
surveillance test results.
These
verifications were accomplished
by direct observation of monitoring
instrumentation,
valve positions,
and switch positions,
and by review
of completed
logs and records.
Instrumentation
and recorder traces
were observed for abnormalities.
The licensee's
compliance with LCO
action statements
was reviewed
on selected
occurrences
as they
happened.
The inspectors verified that related plant procedures
in
use were adequate,
complete,
and included the most recent revisions.
d.
The inspectors verified by-observation
during routine activities that
security program plans were being implemented
as evidenced
by: proper
display of picture badges;
searching of packages
and personnel
at the
plant entrance;
and vital area portals being locked and alarmed.
e.
Jumpers
and Lifted Leads
The inspectors
reviewed the Jumper/Lifted
book in each unit and
AP 0010124,
Control
and
Use of Jumpers
and Disconnected
Rev.
10
25.
Each approved jumper/lifted lead request
had received extensive
review and approval, including technical
review by an STA, 50.59
review when appropriate,
approval
by an
NPS or
ANPS; and
FRG review
and Plant Manager approval
when appropriate.
Both electrical
and
mechanical
jumpers/lifted leads
were included.
Tags were
hung at the
location of the jumper/lifted lead (the inspectors verified two tags
located inside
an electrical cabinet).
The inspectors
noted that
a
total of about nine
in the two units were affected
by jumpers/lifted leads.
One or all of the inputs to these
were disabled.
However, this was not readily apparent
for operators.
There were
no sticker s
on the annunciators
or entries
in the related annunciator
panel status
books to ensure
operator
awareness.
This was identified .to the .licensee for review.
Jumpers/lifted
leads are temporary modifications*to the plant.
Several jumpers/lifted leads
had been in place for over two years.
The inspectors verified that these
were periodically reviewed
by the
licensee to ensure that permanent modifications were being pursued.
f.
Facility Review Group
The inspectors
attended
two
FRG meetings;
reviewed
FRG records;
reviewed
TS 6.5. 1, Facility Review Group;
and reviewed
AP 0010520,
- Rev. 21, Facility Review Group.
During the two meetings,
the
FRG
reviewed and approved four PCMs,
10 permanent
Procedure
Changes,
three Temporary
Changes
to procedures,
two Contractor
Procedures,
one
Instruction Manual
change,
two Jumper/Lifted
Lead requests,
one
NPWO,
and
one Work Process
Sheet.
The
FRG reviewed
items that
TS required
them to review and also many others,
such
as non-safety-related
procedure
changes.
A copy of each item to be reviewed
was present at
the
FRG meeting, with proposed
procedure
changes written clearly in
red to facilitate quick review.
A representative
from the sponsoring
department
was present
to describe the changes
and answer questions
.
as
needed.
If any
FRG member
was not satisfied with an item, it was
sent
back to the sponsoring
department for further answers
or
revisions to be presented
at
a future
FRG meeting.
The review of
each
item was
done quickly and efficiently.
The inspector verified that requirements for minimum
FRG meeting
quorum,
FRG member training, and appointment of alternate
members
were met.
TS requirements
were implemented
by AP 0010520.
FRG
member training records
and meeting minutes
were well organized.
The
inspector noted that the required written appointment of each
alternate
'member
was accomplished
by inclusion in the minutes of an
FRG meeting,
and that there
was
no approved list of alternate
members.
This was identified to the
FRG Chairman (Plant Manager) for
review.
As
FRG review of an item was completed,
the
FRG chairman ensured that
no member had any objections to approval,
then signed the item with
Plant Manager approval.
At one of the
FRG meetings,
the Plant
Manager
was the
FRG Chairman.
In the other
FRG meeting,
the Plant
Manager was not present
and the Operations
Superintendent
was
alternate
FRG Chairman.. The inspector
found. that it was.common
practice for an alternate
FRG chairman to sign
a required Plant
Manager approval
on documents.
However,
'AP 0010520 did not authorize
an alternate
FRG chairman to sign for required Plant Manager
approval.
This was identified to the Plant Manager, for..review.
Licensee Control of Important Equipment Not Included in Technical
Specifications.
During the inspection period,
as
a response
to IN 92-06, Reliability
of ATWS Mitigation System
and Other
NRC Required
Equipment Not
Controlled by Plant TS, the inspectors
reviewed implementation
aspects
of the
ATWS rule (10 CFR 50.62).
-The
IN addressed
perceived
problems at other utilities..in keeping the
ATWS equipment
in. service.
Notices of Violation against the'ule itself had
been
issued at other
sites
even
though
no TS had
been issued in the area.
ATWS equipment provides
an alternate
means for emergency insertion of
CEAs [rodsj to terminate nuclear power generation.
ATWS equipment
was not required to be safety-related.
At this site, the equipment
was bought as safety-related,
but was not addressed
as
safety-related.
Both units at this site have the
ATWS equipment installed
and
operational.
Routine plant tours of the control
rooms
and
RABs have
not indicated
problems with this utility maintaining their
equipment.
Daily and weekly tours
have found the equipment in
service
and functional.
Actuation circuitry and initiation
components
have
been found to be configured properly.
Procedures
existed that calibrated the
ATWS equipment
and checked its
functionality on
a routine b'asis.
Different features of the system
have been
checked
and calibrated
as required
on
a monthly, six month,
or outage basis.
Inspector analysis of the administrative features
surrounding the
ATWS equipment revealed that additional controls
may be necessary.
The rationale for the additional controls are discussed
below:
(1)
Unit 1 AP 1-0010123,
Rev 82,,Administrative Control of Valves,
.Locks and Switches,
provided control methods for selected
components.
At the time the
ATWS was
added,
the keys that
contr ol
ATWS bypass
features
were added to procedure
Appendix
"A", Key Locker Index.
This got the
ATWS keys accounted for on
a quarterly basis,
and the keys were required to be checked in
and out of the controlled key locker when used.
12
Procedure
section 7.3 discussed
the "Valve, Switch Deviation
Log".
The log was
used to maintain
a record of
other-than-normal
equipment configuration.
The
ATMS bypass
locks and associated
circuitry were physically
located in the
ESFAS cabinets,
which contained
many locks for
safety-related
channels,
and
had locked doors.
Section 8.11 of
the above procedure listed the
ESFAS cabinet lock and door keys
but neither it, nor other instructional sections
of the
procedure, listed or dealt with ATWS keys.
This omission meant
that the keys were not required to be entered in the "Valve,
Switch Deviation Log".
The equivalent Unit 2 procedure
required
ATWS bypass
key usage
be logged in the above mentioned
log for that unit for-
configurational. purposes;
'The
ATWS bypass
keys were-also
.
discussed
in the Unit 2 procedure's
instructional text.
The
operators
on both units, out of force of habit from the in-use
proceduralized
methodology for controlled
keys in general,
would
have utilized the log for the subject
keys in any case.
The licensee
agreed to change Unit 1 AP 1-0010123 to match the
Unit 2 procedure
regarding
ATMS bypass
key configuration
controls.
On both units, the placing of an actuation circuit in bypass
with a key would remove the
ATWS trip feature from one
set.
Since the
ATMS trip must open the output of both
sets to be effective, the probability of the
ATWS logic circuit
producing
a reactor trip would go to zero - essentially
placing
the
ATWS system out-of<<service.
Although the other
ATMS
actuation cir cuit would still be available for tripping the
second
MG set,
power from the first MG set would maintain the
CEAs'ositions
unless
the primary safety-related trip feature
(RPS)
had deenergized
the
CEAs.
This situation
was
a departure
from the logic change
associated
with the bypassing of a
trip channel
in that the
RPS trip logic changed
and the
proximity to trip was increased.
The above fact was not general
knowledge to the licensee staff.
There was
no general
information available/apparent
to the
operations staff.
INC personnel
were aware of the facts.
Operations
has
agreed to place plastic tags
on the
actuation circuit bypass
keys stating to the effect that bypass
of the circuit would place the
ATMS system out of service.
Further, the licensee
was considering
changing both
units'dministrative
control of valves, locks,
and switches
procedures
to indicate this information.
13
The above licensee
interactions
indicated
a positive commitment to
improvement.
Plant controls
and response
to events during various:evolutions
were
excellent.
One violation was identified .in this area concerning
a capped
containment
pressure
transmitter sensing line.
The inspector
had no-
further questions
at this time.
3.
Surveillance Observations
(61726)
Yarious plant operations
were verified to comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor coolant chemistry,
RWT conditions,
containment. pressure,
control
room ventilation,
and
AC. and
DC electrical
sources.
The inspectors
verified that testing
was performed in accordance with adequate
procedures,
test instrumentation was::calibrated,'.COs
were met,'emoval
and restoration of the affected
components
were accomplished
properly,
test results
met requirements
and were reviewed
by personnel
other than
the individual directing the test,
and that any deficiencies identified
during the testing were properly reviewed
and resolved
by appropriate
management
personnel.
The following surveillance tests
were observed:
a.
OP 1-0640020,
Rev 33,
ICW System Operation
[1B ICW pump]
b.
OP 1-2200050,
Rev 61,
Emergency Diesel Generator Periodic Test
and
General
Operating Instructions
[1B EDG, three separate
tests]
On April 3, the inspector
observed
the 20th weekly idle start test of
1B
EDG per OP-1-2200050B,
1B Emergency Diesel
Generator
Periodic Test
and General
Operating Instructions.
This test
was to be the last in
a series of 20 weekly starts to meet
TS Table 4.8-1 requirements-
based
on the previous failure history.
The
EDG started
and ran
properly at idle speed
and at rated
speed,
however following EDG
warmup, the control
room operator
was unable to close the
EDG output
circuit breaker.
The licensee
aborted the test
and subsequently
stopped
the
EDG per the procedure.
The inspector
had
no further
questions
concerning
these actions.
Troubleshooting at the
EDG control cabinet per
NPWO 5139/65 found the
"frequency relay" K49 not functional.
This relay's function was to
prohibit
EDG output breaker closure until an
EDG frequency near
60 Hz
(above
54 Hz) is reached.
The failed relay was subsequently
found to
function'properly in the shop.
Since the relay failure mode would
require detailed investigation,
a replacement
relay, identical but
not dedicated for the proper quality level, was tested for
installation.
The inspector
observed that the new relay performed
identically to the old one.
Relay test performance is further
discussed
below.
Following relay installation, the licensee's
successful
idle start retest
was also observed
by the inspector.
Following the
EDG retest,
the licensee
continued to declare the
"out of service" but functional
pending completion of the
new relay's
package.
During the shop testing of the
new K49 .relay, the inspector
observed
that the
new relay performed identically to the .old one (i.e., the
contacts
were closed at low.frequency
and opened at about 62.5 Hz).
Neither relay functioned in the manner the inspector
expected (i.e.,
relay contacts
would remain
open until a predetermined
frequency
was
reached - then close to enable the
EDG output circuit breaker to
close).
The inspector requested
the licensee to evaluate this
observation.
The existing relays were Westinghouse
style
177C717G03
60 Hz/120
V
over-frequency relays.
instruction sheet
I,.L. 14443
described
a 1-2 Hz .differential between
open
and close functions, but
was ambiguous
concerning whether or not the contacts
open or close
on
increasing
frequency.
Also, the relay specified in the
EDG vendor
manual,
on drawing 8770-2421,
was Westinghouse
relay style
117C717G03,
not 177C717G06.
The licensee
confirmed with
Morrison-Knutson,
and
EBASCO that:
The vendor manual
number was
a typographical error,
relay style
177C717G03
was intended to be
an
over-frequency
relay whose contacts
would be open above the
setpoint.
The design basis,
as described
in FSAR section 8.3.1.1.7.d.
and
Figure 8.3-5 was for the relay contacts to be open below the
setpoint to prohibit EDG output circuit breaker closure until
the
EDG reached at least
90 percent of rated voltage
and
frequency.
The relays,
as installed, failed to perform this function.
The
installation,
as installed, deviated from a written comoitment in the
FSAR.
Specification of improper relays
was considered
to be
a
generic design issue.
The
NRC vendor branch
and industry
organizations
were notified.
Further enforcement action was not
considered
because of the licensee's
extremely prompt and effective
corrective action and because
the existing installation's
actual
performance
met safety requirements.
The licensee-found=that
the
EDG frequency permissive function was
performed
on St. Lucie Unit 2 and at Turkey Point by a different.
relay,
a WILMAR ELECTRONICS model
20-050 relay.
That relay was also
qualified for safety-related
service.
The licensee
prepared
116-192M, procured
and tested
the relays,
and installed them on both
1A and
1B EDGs on April 4 per the
PCM and
NPWO 5141/65.
The
were subsequently
tested
per the
PCM package
and temporarily changed
versions of OP 1-2200050A and B.
Since the
EDGs were not fast start
tested,
the last fast start times were evaluated
as still bounding
by
15
adding
an increased
relay actuation time to the previous strip chart
data.
The licensee's
response
upon discovering this design error
was
notably swift and thorough,.involving coordination .of a number of
departments
and vendors.
1A EDG retest
on April 26 following replacement of the
16 cylinder
radiator fan idler shaft.
The fan belt appeared
loose
and flapped
excessively,
about two inches deflection
on each of the short spans.
The vibration analysis
crew measured
about
70 mils vibration.
The
EDG remained out of service for further corrective action.
OP 1-0700050,
Rev .37,:Auxiliary Feedwater
Periodic .Test
[1C AFW
pump].
I&C 2-1130050,
Rev 7, Loose Parts Monitoring System Periodic Test.
MP 2-0950184,
Rev 1, Fast
Dead
Bus Transfer Surveillance Test.
This
test
was properly aborted
when the B-train 4
KV circuit breaker for
the generator auxiliary transformer failed to close.
Subsequent
troubleshooting
per the recently written large breaker
troubleshooting
procedure
MP-0920069,
Rev 0, proved that the circuit
breaker
was satisfactory but the synchronizing switch in the control
room had failed.
A piece of trash
had gotten inside and jazzed the
switch action.
The inspector
observed
periodic- testing of the Main, Startup,
and
Auxiliary transformer control circuits and alarms per
OP 1-0910051,
Rev 8, Hain Transformer Periodic Test,
OP 1-0910050,
Rev 12, Startup
Transformer Periodic Test,
and
OP 1-0910052,
Rev 7, Auxiliary
Transformer Periodic Test; respectively.
During the test of 1A main transformer,
the operator closed
a wrong
switch by mistake but recognized
the error and corrected it.
There
were
no bad results
from- this error.
Review of the procedure
and
work site showed
a
human factors shortcoming in the procedure.
Procedure. section 8.6 listed switches
numbered
TS-2 through TS-15,
but the-procedure
step
numbers
were one number off [step
1 through
14], and easily mistaken for the switch number.
The switches
themselves
had adjacent
small text label plates but were numbered
on
the panel
face in pencil with incomplete nomenclature [just a
number].
- The numbers
resembled
the procedure
step
number more than
the switch number.
Step 8.7 then stated
"Place TS-7, 8, 9, 10, 11,
12 in TEST position." The operator placed TS-8, 9, 10, ll, 12,
and
13
in TEST..
Switch TS-13 involved a different function.
After reading
the label text, the operator
stopped
and corrected
the switch
alignment.
This was identified to the site procedures
group for
correction.
16
The
1A main transformer control cabinet contained
a number of devices
that had
a green colored
ooze
on the wire terminals.
.Examples
included undervoltage
relays
1 through 6, current transformers
1
through 6,
and relays
TR-1 and TR-2.
The green color came from
corrosion
caused
by breakdown of aging
PVC wire insulation found in
certain lots of such wire manufactured
about
20 years
ago.
The
insulation gives off a liquid that turns corrosive in air.
The
nonsafety-related
main transformer controls are serviced
by the
utility s system protection division.
This condition was identified
to the plant maintenance staff for'oordination of future repair.
During the test of the
2B startup transformer controls,
a large relay
hung up, causing
unexpected
indications.
The relay ultimately
started
smoking.
The operator recognized
the unusual
response
and
promptly summoned supervisory-aid.'hat
circuit was deenergized
pending repair.
The inspector
had
no further comments
on this surveillance.
The inspector
observed
the performance of OP 2-0400050,
Rev 12,
Periodic Integrated Test of the Engineered
Safety Features,
from the
control
room and
2B
EDG room.
This test
had
a number of sections
that were performed independently,
however the main body of the test
simulated
a loss of offsite power concurrent with a LOCA.
This
forced
EDGs to fast start
and automatically feed the safety busses,
and all the safety-related
pumps
and equipment to start.
EDG 2A
output circuit breaker
closed in 8.54 seconds
and
EDG 2B output
circuit breaker
closed in 9.86 seconds.
The standard
was
10 seconds.
Equipment not working during the test included:
2B Containment
Spray
Pump Automatic Actuation [The pump started
manuallyj,
2B1
RCP Oil Lift Pump [the circuit breaker
was faultyj, and
MFIV 09-1B operated
when tested with the AFAS test,
but failed
to fully close during the subsequent
MSIS test.
A sticky limit
switch limited valve closure to 90 per cent open.
The
1B
ICW pump was returned to service at the beginning of the
inspection period after being modified with a self lubricating
alteration.
PCM 281-189
removed the existing need for support
equipment to process
and to supply
pump discharge
water to lubricate
the water bearings
and
pump packing area.
The
1B pump became
the
third and final Unit 1'ump to be modified.
Post-modification
pump
surveillance
per
OP 1-01010020 established
new pump baseline
data
per
ASME Code Section XI.
AP 1-0010125,
Rev 87, Schedule of Periodic Tests,
Checks,
and
Inspections,
Check Sheet
6, Test Shield Building Ventilation System,
B-train.
This was
a 10-hour test run of the system
by plant
I
17
operators.
During the test,
the inspector
observed that the
6B fan
discharge
damper counterweight
arm was installed at
a different angle
than the equivalent item on the
6A fan,
and that it had
14 weights
while the
6A fan damper
had
2 weights.
After,,the surveillance
run
was complete,
the inspector
observed that the
6B damper would not
quite close,
though free,
because
of the amount of counterweight.
In
contrast,
the
6A fan damper required significant effort to open.
Both ventilation trains
have routinely demonstrated
that they would
perform their safety function in spite of the dampers.
The licensee
group developing
PMs reviewed the situation, relocated
the
6A
counterweight
arm to match the
6B arm and adjusted
the weight on both
Both dampers
now function well.
During this period the conduct of surveillance:activities
and response
to
unexpected
findings was excellent.
4.
Evaluation of Licensee
Self-Assessment
Capability (40500)
The inspector s. evaluated
the licensee's
self-assessment
programs to
determine whether they contributed to the prevention of problems
by
monitoring and evaluating plant performance,
providing assessments
and
findings,
and communicating
and following up on corrective action
recommendations.
'Portions of this evaluation
were accomplished
throughout the
SALP period
[November 1,
1990 to May 2, 1992] by various inspectors
and the results
are found in multiple IRs,
as follows:
IR 335.389/91-01,
paragraph
6 discussed
licensee
audit and reviews of
the Emergency Plan;
IR 335,389/91-03,
paragraph
1 and Appendix A (finding 91-03-09)
discussed
licensee self-audits prior to an EDSFI;
IR 335,389/91-04,
paragraph
2.b discussed
gA audit reviews in
performance monitoring, refueling activities,
and breaker
modification;
IR 335,389/91-09,
paragraph
7 discussed
10 CFR Part 21 closeouts
under the licensee's
Corrective Action Report program;
IR 335,389/91-10,
paragraph
2.b discussed
licensee
audits of
. operations;
and paragraph.7-discussed
CNRB review of plant
performance;
IR 335,389/91-16,
paragraph
9 discussed
management efforts in work
control programs;
IR 335, 389/91-18,
paragraph
3 discussed
the licensee
assessment
of
the
MOV program at the plant;
18
IR 335,389/91-201,
paragraph
2.5 discussed
licensee
audit findings in
the area of service water system;
IR 335,389/92-02,
paragraph
3 discussed
audit in the areas of offsite
dose,
process control,
and the. radiological environmental
program;
IR 335,389/92-03,
paragraph
2 discussed
implementation of changes
within the
ISEG program;
and,
IR 335,389/92-04,
paragraph
2.b discussed
licensee
audits in
surveillance,
gA program,
and performance monitoring.
The above
documents
reported
on diverse areas. under various
programs at
the site.
They noted that several-areas,
such
as the operations,
instrument
and control, electrical,
and chemistry were improving or
continuing to take positive .actions.--Two
team 'inspections
however
indicated areas
where improvement
was
needed
or weakness
was apparent.
The
NOV program was found to be in the early phases
of implementation
addressing
most generic letter
recommendations
but there were
some
concerns
about potential deviations
from the subject letters
and there
was
a lack of detail in some
NOV program aspects.
The service water team
found insufficient depth in certain areas of assessment.
In contrast,
an
EDSFI team inspection. considered
the licensee's
preparations
to be so
significant that they constituted
a safety
improvement.
Ouring the
day- to day inspections,
the licensee
had several
notable events
to which they. responded well. 'Unit 1 NSIV air control [support] solenoid
valves
had
a moisture entry problem that was resolved in a proper manner.
Engineering
and the electrical
department
had overall excellent corrective
action
on an, HFA relay latch manufacturing
problem that arose during the
Unit 1 refueling outage. and
a. diesel
generator
underfrequency
relay
problem that was identified in .1992 after the Unit 1 outage.
Although
they were slow- to. realize
a diesel fuel oil contamination
problem
initially, the licensee
responded
well with an extremely solid response.
On the whole, the licensee's
approach
to plant operations
during this
evaluation period was--very conservative
and demonstrated
continued
critical self assessment-.-.
Previous
inspection reports
have discussed electric motor failures at this
site in both safety
and non-safety related applications.
The failures
were- as follows:
Unit 1
1A ICW pump motor in Nay,
1990 (failed megger);
Unit 1
1A heater drain pump motor in April, 1990;
and Unit 1
1C
CCW pump
motor in February,
1991.
In response
to these failures to G.E. motors of
different model types, the licensee
has performed several
evaluations
and
developed
a methodology for rewinding these
motors utilizing a vendor,
their own electrical
department,
and site
gA personnel
to qualify the
rewind process
under-the extensive
EPRI guidance
documents.
To date,
the
above motors
and two additional
G.E. motors
have
been
rewound.
A suomary
of the. site's
analysis--and
planned activities inclusive of the Unit 2
~
~
lans are discussed
in FPL letter
JPN/ESI-92-086
dated
February 28,
1992
from A.R. Hall to W.N. Dean].
To date, the corrective actions
and
19
planned actions
have
been well thought out and well enacted.
The actions
have
been conservative
in maintaining plant reliability and demonstrate
excellent self assessment
at both the maintenance
and engineering levels.
The inspectors
conclude that the licensee
management
strongly supports
self identification of problems
and that the utility has
demonstrated
a
continuous pattern of success
in recognizing
and addressing
problems.
Individual exceptions
do not destroy this pattern.
5.
Maintenance
Observation
(62703)
Station maintenance activities involving selected
safety-related
systems
and components
were observed/reviewed
to ascertain
that they were
conducted in accordance
with requirements.
The following.items were
considered
during this review:
LCOs were.met; activities were
accomplished
using approved
procedures;
functional tests
and/or'alibrations
were performed prior to returning
components
or systems
to
service; quality control records
were maintained; activities were
accomplished
by qualified personnel;
parts
and materials
used were
properly certified; and radiological controls were implemented
as
required.
Work requests
were reviewed to determine the status of
outstanding
jobs and to assure
that priority was assigned
to
safety-related
equipment.
Portions of the following maintenance
activities were observed:
a.
NPWO 4883/66 - HVE 10B Fan Motor Replacement
(MP 0940062C,
R11,
The
Overhaul of Motors).
b.
NPWO 8361/62 - Sequence
of Events
Recorder
Repair
and
Troubleshooting.
c.
NPWO 7254/63 -
CEDM NO. 8 Control Element Drive Coil Power Supply
Troubleshooting.
d.
NPWO 0962/62 - 2B
EDG 12 Cylinder Diesel
Fan Shaft Replacement.
This
job was inefficient in that the procedure did not specifically
require all three fan belt drive hubs to be aligned following the
job, and shop personnel
ignored the driving hub by aligning only the
idler hub and the fan hub.
The procedure
also did not specify where
to measure belt tension.
In short, at the post-work test,
the belt
was loose
and misaligned, requiring further work.
The workmanship
was corrected prior to returning the
EDG to service.
The work
.documents
were identified to maintenance
shop engineers for generic
correction.
e.
NPWO 4633/66 - 2A LPSI
Pump Breaker
Change
Out [nine year cyclical
overhaul].
f.
NPWO 4953/66 - MOV 3517,
2A LPSI to
SDC Heat Exchanger Isolation
Valve,'Spring
Pack Replacement.
20
g.
h.'.
NPWO 4960/66 - 2A HPSI Breaker Anti-pumping "Y" Relay Replacement.
NPWO 5117/65 (Unit 1) and 4936/66
(Uni.t 2) - Inspection of
Latching-Type
HFA Relays.
The inspector,
observed testing
and
inspection of 14 of 16 Unit 1 relays
and
4 of 6 Unit 2 relays.
All
latched properly.
The remaining relays
had
been recently inspected
under other
NPWOs.
These relays
had
been previously inspected
during
the Fall
1991 refueling outage
and
some
had
been replaced
or
adjusted.
The potential for drift was considered
small but was
an
unknown factor.
This present
inspection
confirmed that the relays
. had not changed characteristics.
NPWO 7146/63 - Test Engineered
Safeguards
Cabinet
Power Supplies for
Voltage and Ripple - Replace.-Bad
Power, Supplies.
This work was
further corrective action for"a failed instrument
power supply
'erving
channel
The acceptance
criteria for
voltage
was per the component specification.
The ripple criterion of
200 mv peak-to-peak
was conservatively specified
by the shop
engineer.
Five of 24 power supplies failed and were replaced.
The
licensee
was considering
a possible replacement,
which would include
improved electrical
lead connections,
through their engineering
division.
This work was additionally controlled by AP 0010142,
Rev
8, Unit Reliability - Manipulation of Sensitive
systems.
The
inspector found that field activities were well performed
and
documented.
NPWO 7202/64 - Calibrate
ICW Flow Instruments
FIS-21-9A and
9B.
The specialist
also found
a broken face plate screw and
a rusted
terminal board, which he annotated
on the
NPWO.
was subsequently
generated
to initiate repair.
NPWO 1114/62 - Test Both A and
B Train Low Range
Main Steam Safety
Valves.
Each
SG had 8 safety valves under the cognizance of TS
3/4.7.1.
The TS required,
by specifying individual valve numbers,
that
4. safety valves per
SG be verified to be set at 1000 psia +/-
1
percent
[10 psi], and that the other 4 be verified to be set at 1040
psia +/- 1 percent.
This
NPWO addressed
the 8 total valves with the
1000 psia setpoint.
The
NPWO specified the controlling procedure to
be GMP-0705,
Rev 17, Main Steam Safety Valve Maintenance
and
Setpressure
Testing.
The cover
page boldly announced
the procedure
had
been recently been rewritten and should
be read completely - a
good practice.
The procedure
included well marked
gC hold points.
The inspector
observed test performance
on April 21.
The licensee
was using two test gages,
a 1500 psig gage
and
a 200 psig gage.
These were relatively small
gages with 4 1/2 inch diameter faces that
stated
on the face that they had 1/4 of 1 percent accuracy.
Though
1500 psig gage
M-195 had 5-psi divisions, implying that it could be
read to 2 1/2 psi or half a division, it had
a large label
on the
side stating that it had been calibrated to only 1 percent
accuracy
[+ - 15 psi7.
200 psig gage
M-201 also
had
a large
1 percent
21
calibration [+ - 2 psig] label
on its side.
Procedure
GMP-0705
'ection
8.0, Material
and Equipment Required, plainly-specified that
all test
gages shall
have
an accuracy of 0.5'i of full scale.
Worksite review of the of these gages'alibration
sheets
showed that
1500 psig gage
M-195 was actually calibrat'ed
much closer than
1
ercent,
but 200 psig gage
M-201 was actually varying over
a 2 psig
1%j range.
The test crew stopped work, obtained
another
200 psig
gage that met the requirements,
and retested
three valves previously
set using the out-of-specification
gage.
They also verified that the
Unit 1 safety valves set in the Fall of 1991, were in fact properly
set.
Failure to follow (implement)
GMP-0705,
Rev 17, Main Steam Safety
Valve Maintenance
and. Setpressure
Testing,.was
a violation of TS 6.8.l.c. which required procedures for safety. related activities
be
established,
implemented,
and maintained for surveillance
and test
activities of safety-related
equipment.
This is identified as
389/92-07-04; Failure to Follow Procedure for Setting
Safety Valves.
As a result of this occurrence,
the licensee
also planned to review
several relief and safety relief valve setting procedures
regarding
gage size,
range,
and type;
gage calibration range
and technique;
and
procedural verification of essential
parameters
at the time of the
test.
On April 3, during an attempt to fill a SIT, the
2A HPSI
pump failed
to start.
The pump's
4160 Volt breaker failed to close.
Operations
generated
NPWO 4960/66 for its repair.
Electrical maintenance
evaluated
the condition via the administrative
constraints
of above
NPWO and newly-generated
maintenance
procedure
MP 0920069,
Rev 0, Troubleshooting
4 KY/6.9 KV Breaker Failures.
The
procedure
was very useful in identifying the breaker
problem.
The
breaker
was repaired within hours of the failure, greatly limiting
the amount of time the component/train
was in an
LCO situation.
Referring to Unit 2 drawing 2998-327 for the
2A HPSI
pump breaker
2A3-1 cubicle, the Westinghouse
50-DHP-250 4160 Volt breaker for the
pump had
a failed "Y" anti-pumping relay.
With the failure of this
relay, the breaker would not close.
The relay had four contacts,
two
of which were not used.
One of the unused
contacts
had loosened in
the relay,
moved within the-relay,
and blocked further relay
operation.
A new relay was installed
and successfully
tested
(pump
started).
Electrical maintenance
and the operational
s'taff are reviewing the
situation for root cause.
Several factors
such
as breaker
use
and
breaker overhaul period were being considered.
The HPSI
pump was
being routinely used to fill two weeping SITs
on
a once to twice
daily basis.
The filling, which was
due to slow leaking valves,
had
22
been effect for most of the fuel cycle.
The breaker
was scheduled
for its nine year overhaul this upcoming (April 20) maintenance
and
refueling outage.
The electrical staff ..was planning to tear
down the
"Y" relay for investigation.
Most activities observed,
particularly the
HPSI circuit breaker
troubleshooting,
were acceptable
and conservative.
The licensee
promptly
initiated corrective action
on observations
d and
k above,
where
shop
performance
elements
were weak.
Receipt
and Handling of New Fuel (Unit 2)(60705)
During this period, the inspectors
observed
the receipt
and handling of
new fuel for Unit 2.
The review included .observation of truck unloading;
shipping cask operations;
fuel unpacking
and lifting into dry storage,
including crane operations;
repacking the empty containers;
and
cleanliness
inspection of dry storage.
The licensee's
reactor engineering
group had preplanned
and supervised
the receipt.
The operators
and
maintenance
crew handled
the shipping containers
and the fuel properly
with due care
and efficiency.
A vendor representative
and
a health
physics technician
were present
during the several
observations.
The
containers
inspected
were in good shape,
well preserved,
and properly
packed
by the vendor.
Records
being generated
at the time were
satisfactory.
Documents
reviewed at the worksite included:
OP 1610020,
Rev 8, Receipt
and Handling of New Fuel
and
CEAs, and
ONOP 2-1600030,
Rev 5, Accidents Involving New or Spent Fuel.
The licensee's
new fuel receipt process
was well polished.
The inspectors
had
no further questions
concerning the recei.pt of new fuel.
Fire Protection
Review (64704)
During the course of normal tours, the inspectors
routinely examined
facets of the Fire Protection
Program.
The inspectors
reviewed transient
fire loads,
flammable materials storage,
housekeeping,
control of
hazardous
chemicals, ignition source/fire risk reduction efforts,
and fire
barriers.
Fire protection program implementation
was apparent.
Review of Periodic 'and -Special
Reports
(90713)
The inspector reviewed spe'cial
report L-92-117 dated April 28,
1992.
It
was issued
per TS 4.8.1.1.3
and 6.9.2,
and addressed
a failure of the
1B
EDG to load on April 3.
This subject is discussed
in paragraph
3.b. of
this report.
The inspector
had
no further comment concerning the special
report.
This item is closed.
23
The inspector
reviewed
a
10 CFR Part 21 initial notification dated April
1, 1992.
The formal written notification was forwarded in letter L-92-119
dated April 28.
It addressed
crack-like indications found in a
3-inch-diameter
Monel 400 tee fitting supplied
by Tioga Pipe Supply Co.
The material did not meet requirements of'he
ASME SB564.specification.
Of the seven
items received,
one was analyzed in the laboratory
and six
were returned to the vender.
The inspector
had
no further questions
in
this area.
This item is closed.
9.
Onsite Followup of Written Nonroutine Event Reports
(Unit 1) (92700)
The following LERs were reviewed for potential
generic impact, to detect
trends,
and to determine whether corrective actions
appeared
appropriate.
The
LERs were reviewed in accordance
with the current
NRC Enforcement
Policy.
a.
(Closed)
LER 335-92-001,
Fuel Handling Building Ventilation Radiation
Monitor Out of Service
Due to Personnel
Error.
This
LER discussed
a
licensee-identified violation of TS 3.3.3.10,
Radioactive
Gaseous
Effluent Monitoring Instrumentation.
The fuel handling building
ventilation radiation monitor was required to be operable at all
times but was removed from service for about
23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />
by a series of
personnel
errors
and without knowledge of the control
room operators.
The licensee's
event analysis
and resultant corrective action plans
appear to be thorough
and consistent with corrections for LER
335-92-003
below.
This violation will not be subject to enforcement action because
the
licensee's
efforts in identifying and correcting the violation meet
the criteria specified in Section VII.B of the Enforcement Policy.
It is identified as
NCV 335/92-07-01,
Fuel Handling Building
Ventilation Radiation Monitor Out of Service
Due to Personnel
Error.
b.
(Closed)
LER 335-92-003,
Containment
Atmosphere Particulate
and
Gaseous
Radioactivity Monitors Out of Service
Due to Personnel
Error.
This
LER discussed
a licensee-identified violation of TS 3.3.3.1,
Radiation Monitoring Instrumentation
Channels,
and 3.4.6.1,
Leakage Detection Systems.
Containment isolation valves were
inadvertently left closed following periodic valve stroke testing.
The licensee
found several
contributing factors, including no
independent verification of restoration,
a burned out light bulb,
and
weakness
in reviewing the details of radiation monitor readings.
Corrective actions"addressed
all safety-related
valve stroke time
procedures,
including independent verification of post test
restoration.
Corrective actions also included
a significant upgrade
of the radiation monitor log sheets
to require checks of instrument
trends.
This violation will not be subject to enforcement
action because
the
licensee's
efforts in identifying and correcting the violation meet
the criteria specified in Section VII.B of the Enforcement Policy.
24
It is identified as
NCV 335/92-07-02,
Containment
Atmosphere
Particulate
and Gaseous
Radioactivity Monitors Out of Service
Due to
Personnel
Error.
The licensee
has taken extensive corrective action for these
two problems.
10.
Onsite Followup of Events
(Units
1 and 2)(93702)
A nonroutine plant event
was reviewed to determine
the
need for further or
continued
NRC response,
to determine whether corrective actions
appeared
appropriate,
and to determine that
TS were being met and that the public
health
and safety received primary consideration.
Potential
generic
impact and trend detection
were also considered.
On April 21, at 2:38 a.m., the reactor operator manually tripped Unit 2
from 12 percent
power during
a planned shutdown'or refueling.
The
turbine did not trip from remote signals
from the reactor trip switchgear
nor from the control board pushbutton.
The Nuclear Watch Engineer
manually tripped the turbine locally at the turbine stand.
This is
discussed
further in paragraph
2b.
The operators'esponse
to this unexpected
event
was excellent.
ll.
Followup (Units
1 and 2) (92701)
a. 'ollowup of Unresolved
Items
(Closed - Units
1 and 2) URI 335,389/92-03-01,
Evaluate Operability
of Containment Cooling System Relief Dampers.
This item concerned
an
ISEG surveillance finding in March, 1990, that
a number of Unit 1 containment ventilation pressure relief dampers
were painted shut.
The record did not indicate that the dampers
had
been determined to be operable during the time they were painted
.over..
FPL engineering
subsequently
performed engineering
evaluation
JPN-PSL-SEMS-92-002,
REV 0, assessing
the containment fan cooler
relief dampers'istorical
operability.
This study found that, at
design pressure,
the force to open
each relief damper would be about
55 pounds - far greater
than the force 'actually exerted
by the person
who opened
the dampers.
This study also found that, of the eight
damper assemblies
installed, if only one damper
assembly
opened,
the
ventilation system would not experience
excessive differential
pressure.
The computer
program used for the analysis
would not work
if all damper assemblies
were assumed failed closed,
so that more
extreme analysis
was not completed.
The inspector
had
no further
questions.
This URI is closed.
(Closed - Units
1 and 2)
URI 335,389/91-05-01,
Drug Testing Program
Elements.
f
25
I
This St. Lucie item concerned
weekend
and holiday drug testing.
During an inspection at the Turkey Point facility', the cognizant
security inspector determined that the item was satisfactory
throughout the corporate structure,
including both Turkey Point and
St. Lucie.
This is discussed
in IR 250, 251/91-40.
This URI is
closed.
b.
Followup of Regional
Requests
During this period, the inspectors
conducted
two surveys
per Region
II directions
and returned
the results to regional contacts:
Identification of present or past waste
dumps at reactor sites,
and
Completion of a licensee staffing matrix.
12.
Exit Interview
The inspection
scope
and findings were summarized
on May 8, 1990, with
those
persons
indicated in paragraph
1 above.
The inspector
described
the
areas
inspected
and discussed
in detail the inspection findings listed
below.
Proprietary material is not contained in this report.
Dissenting
comments
were not received from the licensee.
Item Number
Status
Description and Reference
335,389/91-05-01,
closed
URI - Drug Testing
Program Elements,
paragraph lla.
335,389/92-03-01
closed
URI - Evaluate Operability of Containment
Cooling System Relief Dampers,
paragraph lla.
335/92-07-01
closed
NCV - Fuel Handling Building Ventilation
Radiation Monitor Out of Service
Due
to Personnel
Error, paragraph
9a.
335/92-07-02
closed
NCV - Containment
Atmosphere Particulate
and Gaseous
Radioactivity Monitors
Out of Service
Due to Personnel
Error, paragraph
9b.
389/92-07-03
open
VIO - Isolation of Containment
Pressure
Sensing
Line Mithout Placing Effected
Instrumentation
Channels
in Trip or
Bypass
as Required,
paragraph
2a.
389/92-07-04
open
VIO - Failure to Follow Procedure for
Setting
Safety
Valves, paragraph
5k.
26
Abbreviations,
and Initialisms
ANPS
.AP
ASME Code
ATTN
CEA-
CFR
CNRB
EDSFI
FIS
FRG
GL
GMP
HFA
HVE
Hz
ICW
IR
ISEG
JPN
KV
LCO
LER
'MFIV
Auxiliary Feedwater Actuation System
(system)
Assistant Nuclear Plant Supervisor
Administrative Procedure
American Society of Mechanical
Engineers Boiler and Pressure
Vessel
Code
Attention
Anticipated Transient Without Scram
Cubic Centimeter
Component Cooling Water
Core
Damage
Frequency
Control
Element Assembly:
Control Element Drive Mechanism
Code of Federal
Regulations
Company Nuclear Review Board
Digital Electro-Hydraulic (turbine control system)
Demonstration
Power Reactor
(A type of operating license)
Emergency
Core Cooling System
Emergency
Diesel Generator
Electrical Distribution System Functional
Inspection
Emergency Operating
Procedure
Electric Power Research Institute
Engineered
Safety Feature
Engineered
Safety Feature Actuation System
Flow Indicator/Switch
The Florida Power
& Light Company
Facility Review Group
Final Safety Analysis Report
[NRC] Generic Letter
General
Maintenance
Procedure
A GE relay designation
High Pressure
Safety Injection (system)
Heating
and Ventilating Exhaust (fan, system, etc.)
Hertz (cycle per second)
Instrumentation
and Control
Intake Cooling Water
[NRC] Inspection Report
Independent
Safety Engineering
Group
.(Juno Beach)-Nuclear
Engineering
KiloVolt(s)
TS Limiting Condition for Operation
Licensee
Event Report
Loss of Coolant Accident
Low Pressure
Safety Injection '(system)
Main Feed Isolation Valve
Motor Generator
27
MHP
NSIS
NSIV
mv
NPF
NPWO
NRC
ONOP
OP
PN
PSIA
PSL
Pub
gA
gI
Rev
St.
TgR
TS
Mechanical
Maintenance
Procedure
Motor Operated
Valve
Maintenance
Procedure
Main Steam Isolation Signal
millivolt
Non-Cited Violation (of NRC requ
Nuclear Production Facility (a t
Nuclear Plant Supervisor
Nuclear Plant Work Order
Nuclear Regulatory
Commission
Off Normal Operating
Procedure
Operating
Procedure
Plant Change/Modification
Preventive Maintenapce
Pounds
Per Square
Inch
Pounds
Per Square
Inch Absolute
Plant St. Lucie
Pressure
Transmitter
Publication
PolyVinylChloride
guality Assurance
guality Instruction
Reactor Auxiliary Building
Pump
Revision
Reactor Protection
System
Reactor Turbine Generator
Board
Refueling Water Tank
Systematic
Assessment
of License
Safety Train
B
Shut
Down Cooling
.Safety Injection Tank
Saint
Topical guality Requirement
Temperature
Recorder
Technical Specification(s)
I NRC] Unresolved
Item
Violation (of NRC requirements)
irements)
ype of operating license)
e Performance