Human Error Report 9/2007
A.
NRC-Identified and Self-Revealing Findings
Cornerstone:
Initiating Events
•
Green. A self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion
V, “Instructions, Procedures, and Drawings,” occurred when technicians
did not follow a procedure
during undervoltage relay testing on the normal supply breaker for the 10A401 4
kV bus. This
resulted in a momentary loss of power
to the 10A401 4kV vital bus that
caused the loss of two reactor feed pumps (RFPs) and required the manual
insertion of all control rods (scram).
PSEG’s corrective
actions
included changing the procedure guidance for the sequence of breaker testing and
adding independent verification steps for the removal of test equipment.
The
finding was greater than minor because it affected the human
performance attribute of the Initiating Events
cornerstone and impacted the cornerstone
objective
to limit the likelihood of those events that upset plant stability and challenge
critical safety functions during plant operations. Specifically, failure to
follow
surveillance test procedures resulted in the momentary loss of power to the
10A401 vital bus and a reactor scram. The inspectors determined the finding
was
of very low safety significance (Green). The
finding had a cross-cutting aspect in the area of human performance
because personnel did not follow procedures (H.4.b). Specifically, maintenance
technicians failed to remove test equipment in accordance with the test
procedure. (Section 4OA3)
Cornerstone:
Mitigating Systems
•
Green. The inspectors identified a non-cited violation of 10 CFR Part
50.65(a)(4) when PSEG did not assess and manage the increase in risk for
corrective maintenance activities on the ‘C’ SSW pump following an emergent
failure of a ‘B’ SSW ventilation supply fan. PSEG updated the risk
assessment, implemented appropriate risk management actions, repaired and
restored the ‘B’ SSW fan to service, and created notification 20326624 to
address the inadequate risk assessment.
iv
The
finding was greater than minor because PSEG’s
risk assessment had errors or incorrect assumptions
that changed the outcome of the plant risk assessment.
Specifically,
PSEG’s risk assessment did not consider the emergent failure of the ‘B’
SSW supply fan risk prior to performing planned maintenance on the ‘C’ SSW
pump.
The inspectors determined that the finding was of very low safety significance
(Green) because the incremental core damage probability deficit
was
in the low E-8 range. The finding had a
cross-cutting aspect in the area of human performance
because PSEG did not appropriately plan work activities by
incorporating
risk insights (H.3.b). Specifically, PSEG did not adjust the work schedule to
ensure overall plant risk was minimized because PSEG did not
evaluate
the change in plant risk caused by the emergent failure of the ‘B’ SSW
ventilation supply fan. (Section 1R13)
============
This
one is an “LER” report, a deeper review of a previous problem; in this case,
from 05/29/07: PSEG ignored corrective actions from 2003, which would have
prevented the problem below:
ABSTRACT
On
May 29, 2007 while operating with the reactor at 100% power and the main
generator synchronized to the grid, a manual scram was initiated in anticipation
of a low reactor water level condition.
An
unexpected slow (dead bus) transfer of a 4 KV Class 1
-E bus from the normal to alternate source occurred during monthly
relay testing. The slow (dead bus) transfer and subsequent loss of a non-safety
related
motor control center (MCC) resulted in a loss of feed water followed by a
reactor scram. A potential personnel error or faulty relay initiated the slow
bus transfer and a low margin condition
associated
with the reactor feed pump oil system design caused a loss of 2 reactor feed
pumps. As a result of these conditions reactor level could not be maintained and
operators took the action to
manually
scram the reactor. After the scram, reactor water level lowered to Level 2 and a
valid ECCS initiation signal caused HPCI and RCIC to start and inject to the
core. The ECCS injection required a 4-hour report that was transmitted to the
NRC in accordance with 10 CFR 50.72 (b)(2)(iv)(A)
an
open breaker and to verify that the relay contacts are in the correct state upon
completion of the surveillance. Operating procedures were revised to maintain
both Reactor Feedwater Pump (RFP) Lube
Oil
pumps operating for each RFP. NRC FORM 366(6-2004)
CAUSE
OF OCCURRENCE
The
root cause of the unexpected bus transfer could not be conclusively determined
by the investigation. There are two potential causes to the initiating event
that are being addressed. The timer stop timing
module
test leads may have been left in place from a previous procedure step creating a
low impedance path to satisfy the logic path. It was noted that if the test
leads had not been properly removed in the
correct
sequence, then the unexpected slow (dead bus) transfer would occur. The
maintenance personnel performing the surveillance stated that they believed they
followed the procedure correctly.
The
investigation concluded from simulated testing of the conditions that the actual
alarm chronology contradicted personnel statements. This human performance
failure is the most likely root cause.
A
stuck channel 1(A-B) 27X 7-8 contact along with the HFA channel 2(B-C) 27X HFA
relay being tested would satisfy the logic to cause a slow transfer. The root
cause for this problem cannot be verified
without
a vital bus outage, which will be performed at the next refueling outage.
Multiple tests were performed to ensure operability. The surveillance was
re-performed satisfactorily. An additional -
surveillance
was later performed and the contacts were visually verified to function
correctly. The RFPT oil system design is not adequate to assure that the standby
lube oil pump will start and
maintain
minimum operating pressure on loss of the operating oil pump. This is an
original equipment manufacturer design deficiency. This deficiency was
identified in 2003 and two modifications were
installed
to improve system performance. Corrective actions were inappropriately closed
for the 2003 event without having implemented one of the corrective actions as
planned, and without having
performed
the CAPR effectiveness review as planned.
NRC
FORM 366A (1-2001)
PREVIOUS
OCCURRENCES
A review of previous reportable events at Hope Creek was performed to determine if a similar event had occurred. 09/19/03 - Hope Creek, LER 2003-007-00 Reactor Scram Due To Electrical Transient, Low Reactor Water Level And Loss Of Reactor Feed Pumps A and C. Corrective actions from this event were not completed in a timely manner and could have prevented the partial loss of feedwater during this 2007 event.