ML17352A250
| ML17352A250 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 09/17/1993 |
| From: | Butcher R, Binoy Desai, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17352A247 | List: |
| References | |
| 50-250-93-21, 50-251-93-21, NUDOCS 9309280239 | |
| Download: ML17352A250 (19) | |
See also: IR 05000250/1993021
Text
gp,R REC(g
~o
eo
I
0
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIEITASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report Nos.:
50-250/93-21
and 50-251/93-21
Licensee:
Florida Power
and Light Company
9250 West Flagler Street
Miami; FL
33102
Docket Nos.:
50-250
and 50-251
License Nos.:
and DPR-41
Facility Name:
Turkey Point Units 3 and
4
Inspection
Conducted:
July 24
hrough August 20,
1993
Inspectors:
R.
C. Butche
, Senior
sident
Inspector
Da
Si
ned
B. B. Desai,
esi
nt I
pector
D
e
S gned
L. Trocine,
esident
In
ector.
Da e S'gned
Accompanying Inspectors:
T.
P. Johnson,
Senior Resident
Inspector,
Salem
and
Hope Creek
George Schnebli,
Resident
Inspector,
Browns Ferry
Approved by:
lk~
K. D. Landis, Chief
Da
Si
ned
Reactor Projects
Section
2B
Division of Reactor Projects
SUMMARY
Scope:
This routine resident
inspector
inspection
involved direct inspection at the-
site in the areas of surveillance
observations,
maintenance
observations,
operational
safety,
and plant events.
Backshift inspections
were performed
on
July 24-25
and 27-28
and August
1 and 16-19,
1993.
Results:
Within the scope of this inspection,
the inspectors
determined that the
licensee
continued to demonstrate
satisfactory
performance to ensure
safe
plant operations.
The .following violation was identified:
Violation 50-250,251/93-21-01,
Failure to Follow a Procedure
Resulting
in a Feedwater
and Subsequent
Reactor Trip (paragraph 8.f).
9309280239
930'F17
ADOCK 05000250
8
During this inspection period, the inspectors
had
comments
in the following
Systematic
Assessment
of Licensee
Performance
functional areas:
Plant Operations
The approach
to criticality following the Unit 4 outage
was performed in
a professional
manner with good communications
(paragraph 8.c).
A
concern
was noted regarding the performance of procedural
steps
out of
sequence,
the lack of command
and control that resulted in a feedwater
and subsequent
reactor trip, and the lack of good
communications
needed to ensure that both control
room and field
personnel
were aware of the performances
of significant evolutions
(paragraph 8.f).
Engineering
A weakness
was noted in the lack of attention to detail
on the Unit 4
design
package for the elimination of the turbine runback
on
a dropped
rod (paragraph
8.e).
A strength
was also noted for Engineering's
quality perspective
in the identification of the inadvertent
removal of
a wire on the Unit 4 turbine runback circuitry during preparation for
the performance of the
same modification 'on Unit 3 (par agraph 8.e).
The following general
comment
was also noted:
Management's
decision to remove Unit 4 from service in order to
facilitate the replacement of a pressurizer
spray mini-flow bypass
valve
due to
a minor unisolable leak was conservative
(paragraph 8.c).
This
was noted
as
a strength.
The inspectors
reviewed the following outstanding
item:
(Closed)
License
Event Report 50-251/93-002,
Reactor Trip Due to Manual
Turbine Trip (paragraph
4).
REPORT DETAILS
Persons
Contacted
Licensee
Employees
Abbatiello, Site equality
Manager
Bohlke, Vice President,
Nuclear Engineering
Supe
Bowskill, Reactor Engineering Supervisor
Earl, equality Assurance
Supervisor
Geiger,
Vice President,
Nuclear Assurance
Gianfrencesco,
Support Services
Supervisor
Goldberg,
President,
Nuclear Division
Hayes,
Instrumentation
and Controls Maintenance
Heisterman,
Hechanical
Maintenance
Supervisor
Higgins,
Outage
Manager
Hollinger, Operations Training Supervisor
Hosmer, Director, Nuclear Engineering
Jernigan,
Operations
Manager
Johnson;
Operations
Supervisor
Kaminskas,
Services
Manager
Kirkpatrick, Fire Protection/Safety
Supervisor
Knorr, Regulatory Compliance Analyst
Kundalkar, Engineering
Manager
Lindsay, Health Physics Supervisor
chese,
Site Construction
Hanager
Paduano,
Acting Director, Nuclear Licensing
Pearce,
Plant General
Manager
Pearce,
Electrical Maintenance
Supervisor
Plunkett, Site Vice President
Powell, Technical
Hanager
Rose,
Nuclear Materials Manager
Steinke,
Chemistry Supervisor
Timmons, Security Supervisor
Wayland,
Haintenance
Manager
Weinkam, Licensing Manager
T. V.
W. H.
H. J.
R. J.
J.
E.
R. J.
J.
H.
E.
F.
R.
G.
P.
C.
G.
E.
J.
B.
D.
E.
H. H.
V. A.
J.
E.
J.
E.
R.
S.
J.,D.
J.
Har
H.
N.
L.
W.
M. 0.
T.
F.
D.
R.
R.
E.
R.
N.
F.
R.
H.
B.
E. J.
rvisor
Supervisor
Other licensee
employees
contacted
included construction
craftsman,
engineers,
technicians,
operators,
mechanics,
and electricians.
NRC Resident
Inspectors
R.
C. Butcher,
Senior Resident
Inspector
B. B. Desai,
Resident
Inspector
L. Trocine,
Resident
Inspector
Other
NRC Personnel
on Site
T.
P. Johnson,
Senior Resident
Inspector,
Salem
and
Hope Creek
G. A. Schnebli,
Resident
Inspector,
Browns Ferry
Attended exit interview on August 20,
1993
Note:
An alphabetical
tabulation of acronyms
used in this report is
listed in the last paragraph
in this report.
Other
NRC Inspections
Performed During This Period-
None
Plant Status
Unit 3
At the beginning of this reporting period, Unit 3 was operating at
approximately
15% power in order to facilitate the repair of a steam
leak on the
3B MSR drain line, cleaning of the
3A north and
3A south
waterboxes,
and cleaning of the 3A and
3B TPCM heat exchangers.
(Refer
to paragraphs
3 and 8.i of NRC Inspection
Report
No. 50-250,251/93-19.)
The unit had
been
on line since January
20,
1993.
The following
evolutions occurred
on this unit during this assessment
period:
At 3: 15 a.m.
on July 24,
1993,
power ascension
was
commenced
following the repair of a steam leak on the 3B MSR drain line.
In
order to facilitate cleaning of the 3A TPCW heat exchanger,
reactor
power was stabilized at
50% at approximately 6:40 a.m.
At
6:00 p.m., the licensee
commenced
a slow power increase
and
removed the
3B TPCW heat
exchanger
from service for cleaning.
This heat exchanger
was returned to service at 9:30 a.m.
on July
25,
1993.
Power ascension
from 75% was re-commenced
at
a rate of
10% per hour,
and
100% reactor
power was achieved
at 12:15 p.m.
(Refer to paragraph 8.a,for additional information.)
At 12: 15 p.m.
on July 25,
1993, Unit 3 broke the previous Turkey
Point record for continuous
days
on line.
This record
(185 days,
15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />,
and
43 minutes)
was set
on March 20,
1988.
Unit 4
At the beginning of this reporting period, Unit 4 was operating at
100%
power and
had
been
on line since June
27,
1993.
The following
evolutions occurred
on this unit during this assessment
period:
At 5:55 p.m.
on August 12,
1993,
a load reduction
was
commenced
in
order to facilitate the replacement. of the pressurizer
spray mini-
flow bypass
valve (4-524A) around pressurizer
spray valve PCV-4-
455B.
(Refer to paragraph
8.c for additional information.)
Unit
4 was taken off line and entered
Mode
2 at 8:34 p.m.,
and
Mode 3
was entered
at 8:44 p.m.
On August 13,
1993, Unit 4 entered
Modes
4 and
5 at 5: 10 a.m.
and 10:55 a.m., respectively.
Following RCS filling and venting,
RCS heatup
was
commenced
at
1:45 a.m.
on August 15,
1993.
A pressurizer
bubble
was
established
at 11:40 a.m.,
Mode 4 was entered
at 1:36 p.m.,
and
Mode
3 was entered
at 10:30 p.m.
Normal operating
pressure
(2235
psig)
and temperature
(547'F) were established
at 3:40 a.m.
on
August
16,
1993.
Reactor
startup
was
commenced
at 4:22 p.m.,
Hode
2 was entered
at 5:03 p.m.,
and critical'ity was achieved
at 5:20
p.m.
Hode
1 was entered
at 7:55 p.m., Unit 4-was placed
back on
line at 9:27 p.m.,
and reactor
power was increased
to
approximately
28K for a chemistry hold.
(Refer -to paragraph
8.c
for additional information.)
At 10:33 p.m.
on August 16, 1993,'nit
4 experienced
a turbine
trip and subsequent
reactor trip from approximately
28K power due
to high narrow range level in the
4C steam generator.
(Refer to
paragraph 8.f for additional information.)
Reactor startup
was
commenced
at 9:17 a.m.
on August 17,
1993.
Hode
2 was entered
at 9:50 a.m., criticality was achieved
at 10:04
a.m.,
Hode
1 was entered
at 1:01 p.m.,
and Unit 4 was placed
back
on line at 1:28 p.m.
Reactor
power was stabilized at
100% at 6:00
a.m.
on August 18,
1993.
(Refer to paragraph 8.f for additional
information.)
Onsite Followup and In-Office Review of Written Reports of Nonroutine
Events
and
10 CFR Part 21 Reviews
(90712/90713/92700)
The Licensee
Event Reports
and/or
10 CFR Part 21 Reports
discussed
below
were reviewed.
The inspectors verified that reporting requirements
had
been= met, root cause
analysis
was performed, corrective actions
appeared
appropriate,
and generic applicability had
been considered.
Additionally, the inspectors verified the licensee
had reviewed
each
event, corrective actions
were implemented, responsibility for
corrective actions not fully completed
was clearly assigned,
safety
questions
had
been evaluated
and resolved,
and violations of regulations
or TS conditions
had
been identified.
When applicable,
the criteria of
10 CFR Part 2, Appendix C, were applied.
(Closed)
LER 50-251/93-002,
Reactor Trip Due to Hanual Turbine
Trip.
This event
was discussed
in detail in paragraphs
3 and 10.d of NRC
Inspection
Report
No. 50-250,251/93-17
and in paragraphs
3 and 8.a
of NRC Inspection
Report
No. 50-250,251/93-19.
On June
22,
1993,
the licensee
performed
a turbine trip test
on Unit 4 while it was
operating at
100% reactor power,
and operators
were unable to
relatch the turbine trips after the successful
completion of this
test.
As a result,
a load reduction
was
commenced with the
intention of ta'king the turbine off line to troubleshoot
and
repair the turbine trip latching mechanism.
During this load
reduction,
a loss of turbine control oil pressure
occurred with
reactor
power at approximately
33%.
This in turn resulted
in a
turbine anti-motoring trip followed by a generator
lockout.
Based
on the turbine anti-motoring indication
and the generator lockout,
operators
manually tripped the turbine,
and
a subsequent
reactor
trip occurred
because
reactor
power was greater
than IÃ.
The
1.1 ~
'licensee's
subsequent
investigations
concluded that the cause
was
an inadvertent operation of the..auxiliary governor trip lever by
personnel
restoring the turbin'e controls to normal after the
turbine trip test.
As a result,
the licensee'-installed
a guard to
prevent the inadvertent operation of the auxiliary governor trip
lever.
The unrelated inability to relatch the turbine trips was
caused
by incorrect clearances
in the overspeed trip block between
the trip relay and the relay bushing
and between
the relay cup
valve and the relay cover plate.
These clearances
were corrected,
and Unit 4 was returned to service
on June
26,
1993.
This
LER is
closed.
Surveillance Observations
(61726)
The inspectors
observed
TS required surveillance testing
and verified
that 'the test procedures
conformed to the requirements
of the TSs;
testing
was performed in accordance
with adequate
procedures;
test
instrumentation
was calibrated; limiting conditions for operation
were
met; test results
met acceptance
criteria requirements
and were reviewed
by personnel
other than the individual directing the test; deficiencies
were identified,
as appropriate,
and were properly reviewed
and resolved
by management
personnel;
and system restoration
was adequate.
For
completed tests,
the inspectors verified testing frequencies
were met
and tests
were performed
by qualified individuals.
The inspectors
witnessed/reviewed
portions of the following test
activities:
procedure
3-SHI-064. 1, Accumulator Level
and Pressure
Loop Analog
Tests;
and
procedure
3-0SP-022.4,
EDG Fuel Oil Transfer
Pump
and Valve
Inservice Test.
The inspectors
determined that the above testing activities were
performed in a satisfactory
manner
and met the requirements
of the TSs.
The flow gage associated
with the
EDG fuel oil transfer
pump test
was
observed to be functioning erratically during the first run of the test.
A PWO was written to troubleshoot
and repair the gage.
The test
was
rerun satisfactorily.
Violations or deviations
were not identified.
Haintenance
Observations
(62703)
Station maintenance activities of safety-related
systems
and components
were observed
and reviewed to ascertain
they were conducted
in
accordance
with approved
procedures,
regulatory guides,
industry codes
and standards,
and in conformance with the TSs.
The following items were considered
during this review,
as appropriate:
LCOs were met while components
or systems
were removed from service;
approvals
were obtained prior to initiating work; activities were
accomplished
using approved
procedures
and were inspected
as applicable;
procedures
used
were adequate
to control the activity; troubleshooting
activities were controlled
and repair..records
accurately reflected the
maintenance
performed; functional testing and/or calibrations
were
performed prior to returning components
or systems- to service;
gC
records
were maintained; activities were accomplished
by qualified
personnel;
parts
and materials
used
were properly certified;
radiological controls were properly implemented;
gC hold points were
established
and observed
where required; fire prevention controls were
implemented;
outside contractor force activities were controlled in
accordance
with the approved
gA program;
and housekeeping
was actively
pursued.
The inspectors
witnessed/reviewed
portions of the following maintenance
activities in progress:
cleaning of Unit 4
TPCW heat exchangers
and
troubleshooting
and weld repair of an unisolable leak on
pressurizer
spray mini-flow bypass
valve 4-524A, the bypass
valve
for pressurizer
spray valve PCV-4-455B (Refer to paragraph
B.c for
additional information.).
For those maintenance activities observed,
the inspectors
determined
that the activities were conducted
in a satisfactory
manner
and that the
work was properly performed in accordance
with approved
maintenance
work
orders.
Violations or deviations
were not identified.
Operational
Safety Verification (71707)
The inspectors
observed control
room operations,
reviewed applicable
logs,
conducted
discussions
with control
room operators,
observed shift
turnovers,
and monitored instrumentation.
The inspectors verified
proper valve/switch alignment of selected
emergency
systems,
verified
maintenance
work orders
had
been submitted
as required,
and verified
followup and prioritization of work was accomplished.
The inspectors
reviewed tagout records, verified compliance with TS LCOs,
and verified
the return to service of affected
components.
By observation
and direct interviews, verification was
made that the
physical security plan was being implemented.
The implementation of
radiological controls
and plant housekeeping/cleanliness
conditions were
also observed.
In addition, the inspectors
reviewed portions of the
licensee's
GET training program.
Tours of the intake structure
and diesel, auxiliary, control,
and
turbine buildings were conducted to observe plant equipment conditions
including potential fire hazards,
fluid leaks,
and excessive
vibrations.
The inspectors
walked
down accessible
portions of the following safety-
related systems/structures
to verify proper valve/switch alignment:
A and
B emergency diesel
generators,
Vs~
6
control
room vertical panels
and safeguards
racks,
intake cooling water structure';
4160-volt buses
and 480-volt load
and motor control centers,
Unit 3 and
4 feedwater platforms,
Unit 3 and
4 condensate
storage
tank area,
area,
Unit 3 and
4 main steam platforms,
and
4
auxiliary building.
I~
The licensee routinely performs
QA/QC audits/surveillances
of activities
required
under its
QA program
and
as requested
by management.
To assess
the effectiveness
of these
licensee
audits,
the inspectors
examined the
status,
scope,
and findings of the following audit reports:
Audit Number
QAO-PTN-93-013
QAO-PTN-93-014
QAO-PTN-93-015
QAO-PTN-93-016
QAO-PTN-93-018
Number of
~Findin
s
T
e of Audit
Control of Computer Software
Per
Procedure
QP 2.15
Radioactive effluents
(Process
Control
Program)
TSs 6.1, 6.2,
and 6.5.1
and
TQR 1.0
June
Performance
Monitoring Audit
Radwaste Audit
No additional
NRC followup actions will be taken
on the finding
referenced
above
because it was identified by the licensee's
QA program
audits
and corrective actions
have either been completed or are
currently underway.
Plant management
has also
been
made
aware of this
issue.
As a result of routine plant tours
and various operational
observations,
the inspectors
determi'ned that the general
plant and system material
conditions were satisfactorily maintained,
the plant security program
was effective,
and the overall performance of plant operations
was good.
Violations or deviations
were not identified.
Plant Events
(93702)
The following plant events
were reviewed to determi.ne.facility status
and the need for further followup action.
Plant parameters
were
evaluated
during transient
response.
The significance of the event
was
evaluated
along with the performance of the appropriate
safety
systems
and the actions
taken
by the licensee.
The inspectors verified that
required notifications were made to the
NRC.
Evaluations
were performed
relative to the need for additional
NRC response
to the event.
Additionally, the following issues
were examined,
as appropriate:
details regarding the cause 'of the event; event chronology; safety
system performance;
licensee
compliance with approved
procedures;
radiological
consequences, if any;
and proposed corrective actions.
'a ~
b.
C.
At 3: 15 a.m.
on July 24,
1993;
power ascension
was
commenced
following the repair of a steam leak on the
3B HSR drain line.
In
order to facilitate cleaning of the
3A TPCW heat exchanger,
reactor
power was stabilized at 5Ã at approximately 6:40 a.m.
At
6:00 p.m., the licensee
commenced
a slow power increase
and
removed the
3B TPCW heat exchanger
from service for cleaning.
This heat
exchanger
was returned to service at 9:30 a.m.
on
July 25,
1993.
Power ascension
from 75K was re-commenced
at
a
rate of i@A per hour,
and 10% reactor
power was-achieved
at 12:15
p.m.
The inspectors
witnessed portions of the power ascension.
At 1:15 a.m.
on August 3,
1993,
ISC personnel
identified that the
RC-1 relay in train
B reactor protection relay rack gR37 was in
the de-energized
(fail safe) condition.
With loop A RCS flows
greater
than
90K, the
RC-1
and
RC-2 relays should
be energized.
An investigation
was initiated,
and
a replacement
relay was found.
At 5:35 a.m. the licensee
closed reactor trip bypass
breaker
B in
order to facilitate the replacement
and testing of relay RC-1.
This action placed Unit 3 in a 2-hour action statement
per TS
Table 3.3-1,
item 19, Reactor Trip Breakers,
action statement
8.
This action statement
requires that with the number of operable
channels
1 less
than the minimum channels
requirement,
the unit be in at least
Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
This action
statement
also states that
1 channel
may be bypassed for up to
2
hours for surveillance testing per
TS 4.3. 1. 1 provided that the
other channel
is operable.
The relay was replaced
and tested
per
procedure
3-OSP-049. 1, Reactor Protection
System Logic Test; the
B
reactor trip bypass
breaker
was re-opened
at 6:50 a.m.; the 2-hour
action statement
was exited.
On August 11,
1993, the licensee
performed
an operability
assessment
because
pressurizer
spray mini-flow bypass
valve 4-524A
was blowing steam out of a bellows rupture
and body-to-bonnet
0-ring leak,
and
an increase
in leakage
was noted from an
inspection
performed
two weeks prior.
The steam blowing out of
the weep hole was impinging only on the insulation of spray valve
PCV-4-455B which was located
12 inches
overhead.
The resulting
steam condensation
and boric acid crystal
accumulation
was being
deposited
on the insulation or dripping directly onto the floor.
There were
no other components
involved..
The apparent rate of
steam condensation
on the overhead
valve".insulati.on
was about
70
to 80 drops per minute,
and the results of a leak rate calculation
performed from 9:00 a.m. to 10:00 a.m.
on August ll, 1993,
were
.08 gpm gross
leakage
and
.03
gpm unidentified leakage.
This was
consistent with current
and past leakage trends which were within
TS limits.
The leakage
was minor in nature
and was coming from a
mechanical joint.
Although any increase
in the leakage
would have
been readily detectable
by
RCS leakrate calculations,
Rll/R12
levels,
and
sump level; licensee
management
elected to remove Unit
4 from service in order to facilitate the replacement
of valve 4-
524A.
This action
was conservative
and was noted
as
a strength.
. At 5:55 p.m.
on August 12,
1993,
a load reduction
was
commenced
in
order to facilitate the replacement of the pressurizer
spray mini-
flow bypass valve (4-524A) around pressurizer
spray valve PCV-4-
-455B.
Unit 4 was taken off line and entered
Mode
2 at 8:34 p.m.,
and
Hode
3 was entered
at 8:44 p.m.
On August 13,
1993, Unit 4
entered
Modes
4 and
5 at 5: 10 a.m.
and 10:55 a.m., respectively.
The inspectors
attended
many of the
ERT meetings
and followed up
on the licensee's
troubleshooting
and planning activities.
Following the replacement
of the mini-flow bypass
valve, the
was filled and vented,
a pressurizer
bubble
was established,
and
RCS heatup
was
commenced
ahead of schedule.
On August 15,
1993.
Hode
4 was entered
at 1:36 p.m.,
and
Hode
3 was entered
at 10:30
p.m.
Normal operating pressure
(2235 psig)
and temperature
(547'F) were established
at 3:40 a.m.
on August 16,
1993.
Reactor
startup
was
commenced
at 4:22 p.m.,
Hode
2 was entered
at 5:03
p.m.,
and criticality was achieved at 5:20 p.m.
Mode
1 was
entered
at 7:55 p.m., Unit 4 was placed
back on line at 9:27 p.m.,
and reactor
power was increased
to approximately
28K, for a
chemistry hold.
The inspectors
witnessed
the licensee's
approach
to criticality.
The evolution was performed in a professional
manner with good communications.
At 3:42 p.m.
on August 13,
1993,
an
IKC Specialist
experienced
respiratory
problems while picking up his children at the
licensee's
Child Care Facility.
Initial CPR was provided by
individuals in the imnediate vicinity.
The site's
medical
group
was called
and responded
in approximately three minutes.
Hetro-
Dade was also called
and arrived on site at 4:02 p.m.
Hetro-Dade
tran'sported
the individual to South Hiami Hospital of Homestead
at
4:45 p.m.,
and the individual was declared
dead at 5:20 p.m.
Preliminary results
indicated possible
asthmatic
bronchial
spasms
which may have led to cardiac arrest;
The licensee notified the
NRC Resident
Inspector at 5:30 p.m.,
and notified the
NRC Opera-
tions Center of a Significant Event per
5:40 p.m.
Because
the fatality was not work-related,
the licensee
elected not to issue
a press
release,
and the State of Florida was
not notified.
The
NRC Resident
Inspectors will followup on the
results of the autopsy
and the 'ticensee's
investigation
as they
become available.
On August 13,
1993, the licensee identified aMisconnected
wire
associated
with the TDRL-X relay which had caused
the cycle
program in the
OThT and
OPBT turbine runback logic to become
dysfunctional.
The TDRL-X relay normally sends
a turbine runback
signal to the governor for 1.5 seconds
at
a rate of 20(C per
minute every 30 seconds until the initiating signal clears.
Mith
the wire associated
with TDRL-X disconnected,
there would be no
timing function,
and the runback would occur continuously until
the bT initiating condition clears.
The OTbT and
OPBT runback
setpoint at Turkey Point is currently the
same
as the
OThT and
OPBT reactor trip setpoints.
Therefore,
a turbine runback of any
. duration or frequency would be masked
by the reactor trip.
The licensee identified the disconnected
during
a field walkdown
to ensure similarity between
the units in preparation of Unit 3
PC/H 93-005, Elimination of Turbine Runback
on Dropped
Rod.
PC/H
92-181
had implemented this
same modification on Unit 4 during the
last refueling outage.
The licensee
had performed
a 10'FR 50.59
safety analysis of this modification.
A lack of attention to detail contributed to the problem in that
the "before" drawings were not included in the
PC/H in combination
with the implementor not correctly interpreting the
PC/H drawing.
Additionally, with the TDRL-X relay outside the scope of the
PHT,
the problem went unnoticed.
In order to address this issue,
the
licensee
developed
Condition Report
No.93-740.
As corrective action, the licensee
plans to train appropriate
personnel
on the gI requirements
with regard to "before" and
"after" drawings in PC/H packages
by approximately
September
15,
1993,
and
on reading
and interpretation
of various electrical
design
and production drawings
by approximately September
29,
1993.
The licensee
also plans to issue
a TDI by approximately
December
31,
1993, in order to clarify scope of PHT procedures.
The cognizant design engineer will be directly involved with the
preparation
and performance of PHT procedures
for complex tasks
as
determined
by engineering.
The inspectors
reviewed the licensee's
interim disposition of
Condition Report
No.93-740
and also verified that the OTbT and
OPBT runbacks
are not taken credit for in the accident analysis
and, therefore,
are not required
by TSs.
Additionally, with the
runback setpoint the
same
as the trip setpoint,
the runback
as
such serves
minimal purpose.
The inspectors
noted
a weakness
in
the lack of attention to detail
on the Unit 4 design
package for
the elimination of the turbine runback
on
a dropped rod and noted
a strength for engineering's
quality perspective
in the
identification of the inadvertent
removal of a wire on the Unit 4
turbine runback circuitry during the preparation for the
10
performance of the
same modification on Unit 3.
The inspectors
will continue to monitor licensee
performance
in this area.
Unit 4 experienced
a reactor trip from approximateTy 2N power at
10:33 p.m.
on August 16,
1993.
The reactor trip was caused
by a
tur bine trip which was caused
by high-high
SG level
(80X on narrow
range)
in the
4C SG.
A feedwater oscillation during the evolution
involving valving in of the
6A and
6B high pressur e feedwater
heaters
located
downstream of the main feedwater
pumps resulted in
the high
SG level.
Unit 4 had
been placed
on line at approximately 9:27 p.m following
the forced shutdown discussed
in paragraph
8.c of this report.
Power was increased
and held at approximately 2N for secondary
chemistry cleanup.
SG level
was appropriately
being controlled
with the feedwater flow control/regulation valves in automatic
and
one main feedwater
pump in operation.
With the
6A and
6B
heaters still in bypass,
the next step in the evolution
was to place the two high pressure
in service.
The
ANPS for Unit 4 directed the
NWE to place the feedwater
heaters
in service in accordance
with procedure
4-0P-081.1,
Heater,
Vents,
and Drains Valve
Alignment.
The
NWE, along with a balance of plant non-licensed
operator,
simultaneously initiated section 7.8, Restoration of the
6A
Heater
Tube Side,
and section 7.9, Restoration of the
6B
'eedwater
Heater
Tube Side, of procedure
4-OP-081. 1.
The sequence
of steps
to restore is specifically outlined in procedure
4-OP-
081. 1 with a sign-off following completion of each step.
For each heater,
the 3-way heater
bypass/normal
valve is required
by the procedure to be cracked
open off the seat followed by
verification of filling of the tube side of the heater.
Then the
tube side outlet valve is required to be slowly opened
followed by
the 3-way valve taken from the bypass to the normal position.
Performing the steps
in this sequence
would minimize changes
in
feedwater flow to the
SG.
The inspectors
noted that the procedure
was silent
on whether both the feedwater
heaters
can
be valved in
simultaneously.
Contrary to the steps outlined in procedure
4-OP-081. 1, the two
personnel
performing the feedwater lineup first cracked
open both
the feedwater tube side outlet valves
(4-30-123
and 4-30-223).
Then they opened the 3-way feedwater heater normal/bypass
valves
(4-20-121
and 4-20-221) to the normal position.
With the outlet
valves only cracked
open
and the 3-way valves
now in the normal
position (i.e. feedwater flow through the heaters)
the feedwater
flow to the
SGs started to drop
as
the= running feedwater
pump was
essentially
dead-heading.
The
RCO observed
the decreasing
SG levels
and was advised
by the
ANPS to start another condensate
pump
as. well as the other main
pump.
The main feedwater flow control..valves
were also
taken in manual with demand for full open.
SG level recovered to
approximately
25%.
The oncoming
ANPS,
who enroute to the control
room had observed
the
NWE and the turbine operator
open the 3-way valves,
recognized
the cause of the perturbation in the feedwater
system.
He
requested
to be unisolated.
6A feedwater
heater
was unisolated first by opening valve 4-20-223.
flow.was recovered,
and
SG levels started to increase.
The 4A
pump was stopped,
and attempts
were
made to reduce
'eedwater
flow.
During this time, the
6A feedwater
heater
was also unisolated
by
opening valve 4-20-123.
This caused
feedwater flow to increase
rapidly,
and the
RCO was unable to adequately
control
SG levels.
The high-high level setpoint
was reached
on the
4C
SG causing the
turbine
and consequently
the reactor trip.
The post-trip response
by the operators
was
as expected.
The
overfeeding of SGs caused
Tave to go below the no load setpoint of
543'F.
The cooldown was slowed by shutting the HSIVs.
Letdown
was manually isolated
due to the decrease
in pressurizer
level
caused
by the cooldown.
Additionally, AFW actuation
had also
occurred following the loss of both feedwater
pumps
due to the
high-high
SG level.
A notification pursuant to the requirements
of 10 CFR 50.72 was
made in a timely manner.
The resident
inspectors
were also
notified.
The resident
inspectors
reviewed the Post Trip Review
Restart
Report
and discussed
the event with several
key utility
personnel
including the Plant Manager.
The resident
inspectors
expressed
concern
over the lack of command
and control that
resulted
and subsequent
and the lack of good communications
needed to ensure that both
control
room and field personnel
were aware of the performance of
significant evolutions.
This was evidenced
by the fact that the
decision
and the subsequent
request
by the
ANPS to valve in the
high pressure
was not properly communicated to
the
RCO.
This resulted
in the
RCO not'eing fully aware of the
activities that affected his ability to control
SG levels.
Concern
over performing steps
out of sequence
was also discussed
with the licens'ee.
The licensee
was in full agreement with the concerns
expressed
by
the resident
inspectors.
Corrective actions to prevent recurrence
will.include briefing control
room supervisors
as to the need for
proper communication prior to initiation of major activities,
counseling of the operators
involved,
and review for further
enhancement
to procedure
4-0P-OSl.l in light of this event.
The
12
licensee
expects to complete these corrective actions
by. September
30,
1993.
While the licensee's. initial. corrective actions
were
prompt and thorough, this violation is being .cited because
deficiencies
in command, control,
and comaunications
allowed
a
procedural violation to escalate
into a challenge to reactor
safety
and because
a previous event also involved
a procedural
violation and
a lack of proper communication
between
operators
(VIO 50-250,251/93-01-02).
The failure to follow steps
as written
in procedure
4-0P-081.1 will be tracked
as
VIO 50-250,251/93-21-
01, failure to follow a procedure resulting in a feedwater
and subsequent
The resident staff observed
a majority of the activities
associated
with the reactor startup which was
commenced
at 9: 17
a.m.
on August 17,
1993.
Criticality was achieved at 10:04 a.m.,
Mode
1 was entered
at 1:Ol p.m., Unit 4 was placed
back on line at
1:28 p.m.,
and reactor
power was stabilized at
100K at 6:00 a.m.
on August 18,
1993, without any complications.
One Violation was identified.
Exit Interview
The inspection
scope
and findings were summarized during management
interviews held throughout the reporting period with the Plant General
Manager
and selected
members,.of his staff.
An exit meeting
was
conducted
on August 24,
1993.
The areas
requiring management
attention
were reviewed.
The licensee
did not identify as proprietary
any of the
materials provided to or reviewed
by the inspectors
during this
inspection.
Dissenting
comnents
were not received
from the licensee.
The inspectors
had the following findings:
Item Number
Descri tion and Reference
50-250,251/93-21-01
Strength
Weakness
Strength
VIO - Failure to follow a procedure resulting in
and subseque'nt
reactor
trip (paragraph 8.f).
Management's
decision to remove Unit 4 from
service in order to facilitate the replacement
of a pressurizer
spray mini-flow bypass
valve
due to a minor unisolable leak was conservative
(paragraph 8.c).
The lack of attention to detail
on the Unit 4
design
package for the elimination of the
turbine runback
on a dropped rod (paragraph
8.e).
. Engineering's quality perspective
in the
identification of the inadvertent
removal of a
wire on the Unit 4 turbine runback cir cuitry
~
~
0
10.
ANPS
CFR
ERT
F
gpm
IKC
LCO
LER
HSIV
HSR
NRC
NWE
OP
OPBT
OTBT
PC/H
PHT
pslg
PTN
PWO
QAO
QI
RCO
SHI
Tave
TDI
TPCW
TQR
TS
13
during the preparation for the performance of
the
same modification. on Unit 3 (paragraph 8.e).
and Abbreviations
Assistant Nuclear Plant Supervisor
Code of Federal
Regulations
Cardiopulmonary Resuscitation
Emergency Diesel
Generator
Event Response
Team
Fahrenheit
General
Employee Training
Gallons
Per Hinute
Instrumentation
and Control
Limiting Condition for Operation
Licensee
Event Report
Hain Steam Isolation Valve
Hoisture Separator
Reheater
Nuclear Plant Supervisor
Nuclear Regulatory
Commission
Nuclear Watch Engineer
Operating
Procedure
Overpower Delta Temperature
Overtemperature
Delta Temperature
Operations
Surveillance
Procedure
Plant Change/Hodification
Pressure 'Control Valve
Post-Hodification Test
pounds per square
inch gauge
Project Turkey Nuclear
Plant Work Order
Quality Assurance
Quality Assurance
Organization
Quality Control
Quality Instruction
Quality Procedure
Reactor Control Operator
Surveillance Haintenance
- ISC
Average Temperature
Technical
Department Instruction
Turbine Plant Cooling Water
Topical Quality Report
Technical Specification
. Violation
Delta Temperature
0
I