hope creek report; salem turbine trip report 1/06 - 3/06
SUMMARY
OF FINDINGS
IR
05000354/2006002; 01/01/2006 - 03/31/2006; Hope Creek Generating Station; Heat
Sink
Performance,
Maintenance Effectiveness, Other Activities.
The
report covered a 13-week period of inspection by resident inspectors and
announced
inspections
by regional reactor inspectors. Three Green non-cited violations (NCVs) were
identified.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone:
Mitigating Systems
C
Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
Appendix
B, Criterion XVI, “Corrective Action,” for PSEG’s failure to implement
corrective
actions for a condition adverse to quality involving inadequate
procedure
guidance for service water pump packing replacement. This resulted
in
a degraded condition on the 'B' service water
pump packing assembly that
was
identified by the inspectors on February 13, 2006.
PSEG's corrective
actions
included tightening the packing and revising maintenance procedures.
The
finding was more than minor because it was associated with the equipment
performance
attribute of the Mitigating Systems cornerstone and affected the
cornerstone
objective of ensuring the availability, reliability, and capability of
systems
that respond to initiating events. In accordance with NRC Inspection
Manual
Chapter 0609, Appendix A, "Significance Determination of Reactor
Inspection
Findings for At-Power Situations," the inspectors conducted a Phase
1
SDP screening and determined the finding to be of very low safety significance
(Green)
because the finding was not a design or qualification deficiency, did not
represent
a loss of system safety function, and did not screen as risk significant
due
to external events. The finding had a
cross-cutting aspect in the area of
problem
identification and resolution because PSEG did not identify that
corrective
actions were not implemented correctly during a corrective action
effectiveness
review. (Section 1R07)
C
Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion
XVI, "Corrective Action," when the ‘D’ service water strainer was
rendered
unavailable for 49 hours on November 6, 2005. On May 23, 2005,
PSEG
technicians reassembled the ‘D’ service water strainer with the backwash
arm
off-center and a packing gland machined from its original size to allow
assembly.
The resulting non-conforming condition was not entered into PSEG’s
iv
Enclosure
corrective
action program. The absence of this
documentation and evaluation
led
to the reuse of the machined gland, which resulted in a packing leak and the
unavailability
of the 'D' service water strainer in November
2005. PSEG initiated
actions
to address the problem associated with not entering the non-conforming
condition
into the corrective action program.
This
performance deficiency was more than minor because it was associated
with
the equipment performance attribute of the Mitigating Systems and Initiating
Events
cornerstone objectives and affected both cornerstone objectives. In
accordance
with NRC Inspection Manual Chapter 0609, Appendix A,
"Significance
Determination of Reactor Inspection Findings for At-Power
Situations,"
the inspectors conducted a Phase 1 SDP screening and determined
a
more detailed Phase 2 evaluation was required to assess the safety
significance,
because the finding affected two cornerstones. The inspectors
determined
that the finding was of very low safety significance (Green). The
performance
deficiency had a cross-cutting aspect in the area of problem
identification
and resolution because PSEG did not identify a condition adverse
to
quality by entering the issue into the corrective action program. (Section
1R12)
C
Green. A self-revealing, non-cited violation of 10 CFR 50 Appendix B, Criterion
XVI,
“Corrective Action," was identified when the guide vane pivot arm on the
'A'
control
room chiller was discovered to be operating incorrectly in May 2005,
rendering
the chiller unable to perform its design function. PSEG corrective
actions
included modifying applicable procedures and providing training to
maintenance
technicians.
This
finding was more than minor because it was associated with the equipment
performance
attribute of the Mitigating Systems cornerstone and affected the
cornerstone
objective to ensure the availability, reliability, and capability of
systems
that respond to initiating events. The improper use of setscrews on the
'A'
control room chiller guide vane arms resulted in the chiller not being able to
perform
its design function and unplanned unavailability of the chiller for about
85
hours to implement repairs. The inspectors completed a Phase 1 screening
using
Appendix A of Inspection Manual Chapter (IMC) 0609, “Determining the
Significance
of Reactor Inspection Findings for At-Power Situations,” and
determined
that the performance deficiency was of very low safety significance
(Green)
because the finding was not a design or qualification deficiency, did not
represent
a loss of system safety function, did not represent an actual loss of
safety
function of a single train greater than its technical specification allowed
outage
time, and did not screen as risk significant due to external events.
(Section
4OA3)
B.
Licensee Identified Violations
Violations
of very low safety significance, which were identified by PSEG have been
reviewed
by the inspectors. Corrective actions taken or planned by PSEG have been
entered
into PSEG's corrective action program. These violations and corrective actions
are
listed in Section 4OA7 of this report.
Enclosure
Note
that PSEG admits
this
event identified the potential vulnerability of the digital EHC system to RFI/EMI.
Tests conducted
on
the simulator EHC system demonstrated that interference could be induced into
the EHC system.
he
three turbine overspeed conductors (channels) are routed together in a single
cable.
7
a
PSEG
Nuclear LLC
P.O.
Box 236, Hancocks Bridge, New Jersey 08038-0236
PSEG
Nuclear
LLC MAY~ 0
B2006
LR-N06-0208
U.
S. Nuclear Regulatory Commission
Document
Control
Desk
Washington,
DC 20555
LER
272106-001-00
SALEM
- UNIT
I
FACILITY
OPERATING LICENSE NO. DPR-70
DOCKET
NO. 60-272
This
Licensee Event Report, "Salem Unit 1
Turbine Trip -
Reactor Trip with
Reactor
Power
Above P-9," is being submitted pursuant to the requirements of the Code of
Federal
Regulations 10CFR50.73(a)(2)(iv)(A).
O
YES
(If yes, complete 15. EXPECTED SUBMISSION
DATE) 10 NO DATE
ABSTRACT
(Limit to 1400 spaces, i.e., approximately
15 single-spaced typewdfiten lines)
n
March 8, 2006 at 1 109, with Salem Unit 1 at 100 % power, a turbine trip signal
was received in the
ain
control room with an immediate reactor trip. The reactor trip actions and plant
recovery were
erformed
without complications. Analysis of computer data indicated that the turbine over
speed
rcuit
initiated an overspeed signal at 103% and tripped the main turbine as designed.
Turbine speed
as
a constant 1800-rpm as controlled by the electric grid with the generator
synchronized to it.
he
most probable cause of the turbine trip reactor trip was Radio Frequency
Interference (RFI) or
lectro
Magnetic Interference (EMI) by an unknown source. Some of the corrective actions
taken were
he
following: (1) prohibiting the use of electric tools, radios, cellular phones,
portable radios, arc flash
welders
and other equipment that could result in EMI or RFI in relay rooms and (2)
posting warning
signs
in the effected areas.
This
report is being made in accordance with 10CFR50.73(a)(2)(iv)(A), "any event
or condition that
resulted
in manual or automatic actuation of
any
of the systems listed in paragraph (a)(2)(iv)(B)."
NR
IOM38820)PINE
NRCCE
AE
NRC
FORM 366 (ZM204) PRINTED
ON RECYCLED PAPER
NRC
FORM 366A U.S. NUCLEAR
REGULATORY
COMMISSION
(1-2001)
LICENSEE
EVENT REPORT (LER)
1.
FACILITY NAME 2. DOCKET 6. LER
NUMBER 3. PAGE
I
SEQUENTIAL
REVISION
Salem
Generating Station Unit 1 05000272 YEAR
I NUMBER
I
NUMBER
12006
-0 0
1- 00 2 OF 4
17.
NARRATIVE (if more space s
required,
use additional copies of NRC Form 366A)
PLANT
AND SYSTEM IDENTIFICATION
Westinghouse
- Pressurized Water Reactor
Electro-Hydraulic
Control System (TG){EHC}
Steam
Generator Feed Pump (BF/P) {SGFP}
Control
Rod System (AN-)
ndustry
Identification System (EIIS) codes and component function identifier codes
appear in the text
as
{SSICCC}.
DENTIFICATION
OF OCCURRENCE
Event
Date: March 8, 2006
Discovery
Date: March 8, 2006
CONDITIONS
PRIOR TO OCCURRENCE
Salem
Unit 1 was in Operational Mode 1 at 100% reactor power.
No
structures, systems or components were inoperable at the time of the discovery
that contributed to
the
event
DESCRIPTION
OF OCCURRENCE
n
March 8, 2006 at 1109, with Salem Unit 1 at 100% power, a "first-our
Overhead Alarm (F38) Turbine
rrip
& P-9
(Reactor above 49% power) was received in the main control room with an
immediate reactor
rip.
The reactor trip actions and plant recovery were performed without
complications; however, two
Dquipment
issues were
noted during the trip. The two issues were: (1) one control rod position
ndication
for shutdown rod 1SC1 indicated that the rod was at approximately 17 steps, and
(2) reports
rm
field operators (non-licensed personnel) indicated a leak on the condensate line
at the suction of
he
11 Steam Generator Feedwater Pump. Control room operators (Licensed personnel)
initiated a
ain
Steam Line Isolation to isolate steam flow to the secondary plant and controlled
Reactor Coolant
ystem
average temperature using the atmospheric dump valves. The leak on the
condensate line was
due
to the momentary secondary system pressure perturbation that caused a flange
gasket to fail. The
failed
gasket was replaced.
Later
assessments determined that control rod ISCI was fully inserted. The erroneous
ISCI position
indication
was the result of residual magnetic flux in the individual rod position
indicator coil that induced
a
voltage on the secondary side of the coil. The secondary coil voltage is used to
provide the relative
rod
position and as such any error introduced will directly affect the rod position
indication. The rod
position
indication would have eventually decreased to indicate full insertion through
natural decay of the
residual
magnetic flux. De-energizing the individual rod position indication system let
the residual flux
decay
almost immediately. The individual position indicator was calibrated during the
outage.
NRC
FORM 366A(1-2001)
NRC
FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
(1-2001)
I
LICENSEE
EVENT REPORT (LER)
1.
FACILITY
NAME 2. DOCKET 6. LER NUMBER 3.
PAGE
I
SEQUENTIAL
REVISION
Salem
Generating Station Unit 1
05000272 YEAR
NUBE N
2006
-0 0 1- 00 3 OF 4
1
17.
NARRATIVE
(If more space Is required, Use additional
copies of NRC Form 366A)
DESCRIPTION
OF OCCURRENCE (cont'd)
Analysis
of computer data indicated that the turbine over speed circuit initiated an
overspeed signal at
103%
and tripped the main turbine as designed. Turbine speed was a constant 1800-rpm
as controlled
by
the electric grid with the generator synchronized to it.
The
unit was returned to service the following day, March 9, 2006.
The
automatic initiation of the reactor trip and the manual initiation of the Main
Steam Line Isolation are
reportable
in accordance with 10CFR50,73(a)(2)(iv)(A), "any
event or
condition that resulted in manual
or
automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)."
PREVIOUS
OCCURRENCES
A
review of reportable events for Salem Generating Station in the last three years
identified five licensee
event
reports associated with manual or automatic reactor trips.
311/2004-006
"Salem Unit 2 Reactor Trip Due to a Malfunction of a Main Feedwater
Regulating Valve
(21BF19),"
dated September 13, 2004.
311/2004-007
"Salem Unit 2 Reactor Trip Due to a Malfunction of a Main Feedwater
Regulating Valve
(23BF19),"
dated September 13, 2004.
311/2003-001
Salem Unit 2 "Manual Reactor Trip Due to Degradation of Condenser Heat
Removal,"
dated
May 22, 2003.
11/2003-003
Salem Unit 2 "Manual Reactor Trip Due to Dropped Control Rod," dated
January 20, 2004.
72/2003-002
Salem Unit 1 "Reactor Trip due to Turbine Trip Caused by a 500KV Switchyard
Breaker Trip,"
ated
September 24, 2003.
Ilthough
these events involved a reactor trip, the root causes were different than the
one described in this
ER;
and therefore they could not have been prevented this occurrence.
.,R11W1-
ý"NJILA W=Afll
-XIM I
NRC
FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
(1-2001)
LICENSEE
EVENT REPORT (LER)
1.
FACILITY
NAME 2. DOCKET 6. LER NUMBER S.
PAGE
SEQUENTIAL
REVISION
Salem
Generating Station Unit 1
05000272
YEAR
NUMBER I
NUMBER
1
12006 -O
0 1 - 00 4
OF 4
17.
NARRATIVE
(if more space is required, use additional
copies of NRC Form 366A)
CAUSE
OF OCCURRENCE
The
investigation team explored several possible failure methods which could have
resulted in the turbine
overspeed
trip and determined that the most probable cause was Radio Frequency
Interference (RFI) or
Electro
Magnetic Interference (EMI) by an unknown source.
Efforts
to pinpoint the source of the interference signals are continuing. Due to the
length of cable
associated
with the turbine speed circuit and the transient nature
of the interference, the investigation
team
has not identified the specific device and location that initiated the EMI/RFI.
this
event identified the potential vulnerability of the digital EHC system to RFI/EMI.
Tests conducted
on
the simulator EHC system demonstrated that interference could be induced into
the EHC system.
he
three turbine overspeed conductors (channels) are routed together in a single
cable.
SAFETY
CONSEQUENCES AND IMPLICATIONS
There
was no actual safety consequences associated with this event.
As
stated earlier, later assessments following the reactor trip determined that the
control rod indication
was
erroneous and that the leak on the condensate line was due to the momentary
secondary system
pressure
perturbation caused by the trip. The licensing basis of the Salem plant includes
the assumption
that
the highest worth control rod is stuck completely out of the core; therefore,
the current licensing
basis
accident analyses bound this event.
A
review of this event determined that a Safety System Functional Failure (SSFF)
as defined in NEI
99-02,
Regulatory Assessment Performance Indicator Guidelines, did not occur.
4C
ORRECTIVE ACTIONS
Jse
of electric tools, radios, cellular phones, portable radios, arc flash welders
and other equipment that
luld
result in EMI or RFI in relay rooms has been prohibited.
aming
signs have been posted in the effected areas. Adherence to the posting is being
emphasized to
Irevent
EMI and RFI from interfering with or causing inadvertent actuation or response
of sensitive
nstruments
in the plant.
Longer
term actions such as additional cable shielding or cable separation are being
evaluated as well as
the
extent of the entire digital EHC circuit susceptibility to EMI/RFI.
COMMITMENTS