ML16342D670
| ML16342D670 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/21/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D668 | List: |
| References | |
| 50-275-97-03, 50-275-97-3, 50-323-97-03, 50-323-97-3, NUDOCS 9706020127 | |
| Download: ML16342D670 (52) | |
See also: IR 05000275/1997003
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
50-275
50-323
DPR-82
50-275/97003
50-323/97003
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Units
1 and 2
7 1/2 miles NW of Avila Beach
Avila Beach, California
March 16 through April 26, 1997
M. Tschiltz, Senior Resident Inspector
D. Allen, Resident Inspector
S. Boynton, Resident Inspector
Approved By:
H. Wong, Chief, Reactor Projects Branch E
ATTACHMENT:
Supplemental
Information
9706020127
970521
ADOCK 05000275
8
-2-
EXECUTIVE SUMMARY
Diablo Canyon Nuclear Power Plant, Units
1 and 2
NRC Inspection Report 50-275/97003; 50-323/97003
~oerationa
o
Operator response to a partial loss of feedwater event and subsequent
plant t;ip
was generally very strong with only one notable exception.
During posttrip
activities for realigning plant systems, operators failed to recognize that the actions
being taken would cause the atmospheric steam dump valves to close and the
procedure
did not alert operators to this.
As a result, two main steam safety valves
(MSSVs) lifted after operators took actions that caused the atmospheric
steam
dumps to close (Section 01.2).
A noncited violation was identified involving,an operating crew failing to follow
procedural guidance which required that a power production engineer
(PPE) be
involved with the surveillance that performed stroke time testing of a main steam
isolation valve (MSIV). The lack of involvement of engineering was a key
contributor to the installation of improper test equipment'and
the resultant failure of
solid state protection system (SSPS) Train A (Section 01.2).
Plant management
promptly initiated actions to shutdown Unit 2 following the
discovery of a crack'in cold reheat steam piping.
Overall operator performance
during the shutdown was good; however, during times of increased activity in the
control room operators reverted to less formal communications
and the shift
foreman did not approve changes
in reactivity as expected
by management
(Section 01.3).
~
Unit 2 plant startups, following both the plant trip due to the partial loss of main
feedwater and the shutdown following discovery of the throUgh-wall crack in the
cold reheat steam piping, were well controlled with closed-loop communications.
Operations shift management
was involved with the direction and oversight of the
evolutions and the control room environment was appropriately controlled to limit
the distractions to operators
(Sections 01.2 and 01.3).
Maintenance
The licensee's troubleshooting
and repair activities associated
with the failure of the
control oil system for main feedwater Pump (MFP) 2-1 and the excessive
stroke
time of MSIV FCV-41 were both methodical and comprehensive.
The results of the
troubleshooting
provided
a clear basis for the conclusions drawn in the root cause
analyses
(Section 01.2).
-3-
A violation was identified related to inadequate
controls over painting
activities,'hich
resulted
in painters improperly painting the mechanical governor linkage to
auxiliary feedwater (AFW) Pump 1-1.
The licensee failed to take adequate
corrective actions in response
to previous events and audit findings involving
painting activities (Section M8.1).
Activities associated
with the installation of temporary power jumpers prior to the
replacement of Battery,1-3 were well planned and executed.
Both the maintenance
and operations
personnel were knowledgeable
of their assigned
tasks and the
assigned
engineer maintained close oversight of the activity in order to resolve any
questions that arose during the work (Section M1.1.1).
~ncnineerinq
A violatiori was identified involving errors in the licensee's
calculation for minimum
containment flood level following a loss of primary coolant.
This resulted in an
~
incorrect translation of the plant's design basis into the emergency operating
procedures
(Section E8.1)
~
System walkdowns by engineering
personnel continue to identify issues affecting
equipment operability.
The AFW system engineer identified a concern over the
operability of AFW Pump 1-1, after noting new paint had.been
applied to the
mechanical governor linkage (Section M8.1).
A violation for failure to take prompt and effective corrective actions was identified.
Following identification of abnormally high concentration
of water in the governor of
the Unit
1 turbine-driven AFW pump, knowledgeable
personnel failed to initiate an
action request
(AR) to document the problem until a second sample was taken
approximately 8 months later.
In addition, no additional monitoring or evaluations
were performed until the second sample yielded the same results (Section M1.1.2).
Engineering's
investigation of the cracked cold reheat piping was thorough and
focused on determining the potential cause of the crack and the technical basis for
the repair.
In addition, the Engineering organization was self-critical of a previous
missed opportunity to identify the cracked pipe when a small leak was noted at the
same location (Section 01.3).
Re ort Details
Unit 1 began'this inspection period at 100 percent power.
On April 19, a normal plant
shutdown was commenced
in preparation for the unit's eighth refueling outage.
The unit
was in Mode 6 at the end of the inspection period.
Unit 2 began this inspection period at 100 percent power.
On March 29, a failure of the
control oil system for MFP 2-1 resulted
in a reactor trip on low steam generator
(SG) water
level in SG 2-2.
The plant was stabilized in Mode 3 while the licensee investigated the
failure of the control oil system and affected repairs.
While the unit was in Mode 3, the
licensee also identified during testing of the MSIV for SG 2-1 (Valve FCV-41), that the
valve failed to meet its Technical Specification (TS) specified stroke time. The repair of
Valve FCV-41 delayed restart of the unit until April 4. The unit was returned to 50 percent
power on April 5, where it remained while the licensee continued troubleshooting
the
control oil problems with MFP 2-1.
On April 9, following cleanup of the oil system on both
MFPs, the unit began ramping up in power and attained 100 percent power on April 10.
On April 11, the unit was shutdown to repair a small leak in a cold reheat line. The
investigation of the leak found an 11 inch circumferential crack in the toe of a weld.
The
unit returned to 100 percent power on April 14 and remained there for the balance of the
inspection period.
I. 0 erations
01
Conduct of Operations
01.1
General Comments
71707
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
In general, the conduct of operations was professional
and safety conscious.
01.2
Loss of MFP 2-1 and Reactor Tri
a.
Ins ection Sco
e 71707
92901
92902
The inspectors reviewed the operators'esponse
to the March 29, 1997, event,
which involved the. loss of MFP 2-1 and
a reactor trip, and observed
portions of the
licensee's
activities associated
with troubleshooting
equipment problems and
preparing Unit 2 for restart.
The inspectors
also observed
portions of the unit
startup on April 4,
b.
Observations
and Findin s
~Descri tion of Event
On March 29, Unit 2 trippeo ~n low SG water level due to the loss of MFP 2-1.
'The event began with operators
receiving a high differential pressure
(dP) alarn
for
-2-
the standby control oil filter for MFP 2-1.
Immediately following replacement
of the
standby filter element,
a second
alarm was received for high dP across the inservice
control oil filter. The licensee decided to transfer to the standby filter. Upon
transfer to the standby filter, the speed of MFP 2-1 dropped rapidly to around 2300
rpm. At that speed, the MFP did not produce sufficient discharge
pressure to feed
the SGs.
Recognizing the condition and attributing the change
in speed of MFP 2-1
to the transfer of the control oil filter, operators attempted to transfer the control oil
system back to the original inservice filter without success.
Operators then entered
their abnormal procedure for loss of an MFP.
To compensate
for the partial loss of feedwater, unit load was rapidly reduced to
50 percent and all three AFW pumps were started.
However, the loss of feedwater,
coupled with the load reduction caused water level in SG 2-2 to fall below the low
SG water level reactor trip setpoint and a reactor trip was initiated.
0 erator Res
onse
A review of the actions taken by the onsh)ft crew in response
to the loss of
MFP 2-1 and the subsequent
reactor trip found those actions to be both timely and
in accordance
with abnormal and emergency
operating
procedures.'uring
the plant recovery from the trip, approximately
1 1/2 hours after the trip, the
operators closed the reactor trip breakers and the 10 percent steam dump valves
unexpectedly
closed.
Main steam pressure
increased
until MSSVs MS-2-RV-3 and
MS-2-RV-7 lifted. The licensee evaluated this transient and determined that the
10% steam dump valve closure was the result of operators
closing the reactor trip
breakers, which satisfied the logic for the control of these valves to transfer from
their individual pressure
controllers to the load reject controller, which had a zero
demand output, thus closing the valves.
During the loss of feedwater transient, generator
load decreased
rapidly sealing in
the 50 percent load rejection interlock (C-7b) in the steam dump control system.
When the reactor tripped, the P-4 input transferred control of. the 10 percent steam
dump valves to their individual pressure
controllers and transferred control of the
40 percent steam dump valves to the reactor trip controller.
Following the trip,
operators
closed the MSIVs to limit the cooldown of the reactor coolant system.
The 10 percent steam dump individual pressure
controllers were adjusted,
per the
emergency procedures
to maintain main steam pressure
at normal no-load pressure.
Operations reclosed the reactor trip breakers
in accordance
with Operating
Procedure
(OP) L-7, "Plant Stabilization Following Reactor Trip," Revision OA, in
order to relatch the Main Turbine.
This action cleared the P-4 input and caused the
10 percent steam dump valves to close.
Steam, pressure
increased to the setpoint
of the MSSVs and two of the four safety valves opened
and stabilized pressure.
All
equipment operated
as designed.
After approximately 4 minutes the operators
regained control of the 10 percent steam dump valves by placing the steam dump
control switch in the Steam Pressure 'Mode.
-3-
The procedures
used by the operators to respond to this transient did not direct the
C-7b interlock to be reset nor direct that the steam dump control switch to be
placed in the Steam Pressure
Mode prior to reclosing the reactor trip breakers.
The
operators
also did not recognize that closing the reactor trip breakers would cause
the 10 percent steam dump valves to close.
The licensee did not expect the
operators to recognize this situation nor anticipate the loss of control of the
10 percent steam dump valves and did not train on this scenario.
E ui ment Problems and Associated Troubleshootin
and Repair Activities
Two equipment problems were identified as a result of the event.
The first was the
failure of the control oil system on MFP 2-1 which initiated the event.
The second
was the failure of Valve FCV-41 (SG 2-1 MSIV) to meet its TS required stroke time.
MFP 2-1
The licensee determined that the failure of the MFP control oil system was
due to excessive
particulates
in the control oil. These particulates caused
the high dP alarms received on the control oil filters and the failure of several
solenoid actuated
shuttle valves to properly reposition on demand.
Specifically, particulates
in the body of the shuttle valve used in transferring
control between the two redundant control oil trains caused the valve to fail
in a midposition.
This prevented
adequate
control oil pressure from reaching
the MFP turbine governor valve and resulted in the governor valve drifting
closed.
The failure is consistent with the observed
speed reduction in
MFP 2-1.
The root cause evaluation was found to be methodical and
technically sound.
The most likely source of the particulates was determined to be from
corrosion buildup in the system's carbon steel piping.
The licensee suspects
that a known high water content in the control oil system () 1000 ppm) at
the beginning of the cycle resulted in the excessive
corrosion buildup.
The
failure of the control oil filters to capture the particulate and protect the
shuttle valves was determined to be, in part, a design deficiency.
Specifically, internal tolerances of the shuttle valves were found to be
smaller (approximately 1pm) than the filtration media (3ym).
Several flushes were performed to remove the particulate in the system prior
to returning MFP 2-1 to service.
The failed shuttle valves were also
replaced.
The licensee is considering options for improving the reliability of
the control oil system, including the use of a finer filter media and the
implementation of routine maintenance
to periodically exercise the shuttle
valves.
The particulate in the control oil also resulted in the failure of the MFP
turbine stop valves to close when the MFP was tripped.
Similar performance
0
problems had been noted in the past with the valves.
The licensee's quality
organization determined that accident analysis relied uoon these valves to
close within 2 seconds
as a backup to the shutting of the feedwater
reoulating valves which close in less than 10 seconds.
Further review
identified that the MFP stop valves were not tested to verify that they would
satisfy the requirement to close in less than 2 seconds.
The licensee
performed
a prompt operability assessment
which concluded that the valves
were operable based upon startup tests performed on the MFPs.
The
licensee's
resolution of testing of the stop valves is considered
an inspection
followup item (IFI 50-275;323/97003-01).
Valve FCV-41
Following the identification of the longer than specified stroke time on
Valve FCV-41, the licensee restroked the valve several times in attempt to
isolate the root cause.
The response
time testing was performed in
accordance
with several different surveillance procedures,
includina
Surveillance Testing Procedure
(STP) V-8, "Slave Relay Test and Time
Response
and SG Blowdown Valves."
During the
performance of STP V-8, an improper configuration of test equipment
resulted in the failure of Train A of the SSPS.
Specifically, an incorrect timer
isolation interface box was installed across the SSPS slave relay coil for
closing Valve FCV-41. When technicians attempted to energize the slave
relay coil, the isolation interface box presented
a low impedance
around the
coil and caused the 10 amp SSPS slave relay power fuse to fail. The
licensee replaced the fuse and performed
a post maintenance
test to verify
the operability of SSPS Train A.
The inspector noted that Step 2.1 of STP V-8 places the responsibility for
coordination of the test and obtaining test data on a designated
PPE.
However, from discussions
with surveillance engineering. personnel,
it was
identified that a designated
PPE was not involved with testing of
~ Valve FCV-41 until after the failure of SSPS Train A. Step 12.2.1 of
STP V-8 directs the, installation of "a timer isolation interface box (or
equivalent) across slave relay K616 operating coil..." The lack of
specificity in the procedure
places the responsibility on the personnel
involved with the test to determin
the proper equipment needed.
Without
the presence
of the PPE, that responsibility fell upon the technical
maintenance
personnel who failed to recognize the incompatibility of the
installed isolation box.
To prevent recurrence
of the event the licensee took several corrective
actions.
Each of the test isolation interface boxes have been given a
measurement
and test equipment
(MSTE) serial number for tracking and
identification.
The isolation boxes were not previously being controlled as
MSTE.
The procedures
that utilize these interface boxes are being revised to
-5-
include steps for recording the MSTE serial number of the isolation box.
The
operations director also issued
an incident summary to the operations
department describing the event and the lessons
learned.
The failure of the
operating crew to involve a designated
PPE in the testing of Valve FCV-41 is
a violation of TS 6.8.1.a.
This licensee-identified
and corrected violation is
being treated as a noncited violation, consistent with Section Vll.B.1 of the
NRC Enforcement Policy (NCV 50-323/97003-02).
Upon further investigation of the stroke time of Valve FCV-41, the licensee
identified the need to refurbish both of the valve's associated
air-operated
actuators.
Wear of the actuators'omponents
and hardening of the
actuators'ubricating
grease were determined to be contributing factors to
the slow stroke of the valve.
Refurbishment of the actuators was successful
in reducing the stroke time to within the TS limits.
Based upon the licensee's findings, plans were established
to refurbish the
air actuators
on each of the MSIVs on Unit 1 during the current Refueling
Outage
1R8.
Similar actions are planned for Unit 2 during its next refueling
outage scheduled for January 1998.
Unit Restart
The inspectors reviewed the licensee's
mode transition checklist for transitioning to
Mode 2 and independently verified that the licensee had met the procedural
requirements for returning the unit to power.
The preevolution tailboard, conducted
by the shift foreman (SFM) and senior control
operator, properly covered the precautions
and limitations to be observed
during the
startup.
A review of the specific steps in the procedure was highlighted by the
SFM, to emphasize
areas of concern and to discuss potential contingency actions.
Proper consideration was given to designating
responsibilities to individuals and to
limit the distractions to the control operator
(CO) manipulating the control rods.
A cautious "pull-and-wait" approach was taken in withdrawing control rods to
criticality. Rods were withdrawn a specific number of steps,
as recommended
by
the PPE, and then held to allow the neutron flux level to stabilize.
This allowed
evaluation of the expected critical rod height following each rod pull, based upon
the change
in source range counts.
The expected critical rod height was then
communicated
to the operators prior to the subsequent
rod pull. The use of
closed-loop communications
and peer checking by the operators was also noted.
The turbine roll and generator synchronization
were also observed.
Prior to starting
the evolution, the SFM and senior control operator reviewed the procedure
steps,
assigned
responsibilities to specific individuals during each significant evolution,
reviewed previous industry and site experiences,
specified the communications
and
coordination expected
during the evolution, and discussed
potential problems and
-6-
the expected
operator response.
During the evolution, the operators demonstrated
good three-way communications
and appropriate
use of peer review for each
operator action.
As problems were encountered,
they were addressed
and resolved
prior to proceeding.
These problems included the failure of the exciter field breaker
to close, failure of the backup turbine lube oil to automatically start when tested,
and the generator
load controller picked up less load than expected when the
generator
breaker was closed.
Although these nonsafety related equipment
problems were distra'ctions, the operators anticipated the problems and, thus,
were'repared
to resolve them.
Conclusions
Overall operator response
to the trip was good, with the exception that the
operators did not recognize,
and the procedures
did not address,
the impact of
resetting the reactor trip breakers on the 10 percent ste'am dump control system.
The licensee's troubleshooting
and repair efforts of the MFP 2-1 control oil system
and Valve FCV-41 were methodical and generally comprehensive.
However, a
procedure
noncompliance
during stroke time testing of Valve FCV-41 resulted in a
loss of SSPS Train A. The root cause analyses for the equipment failures were
technically sound.
The unit restart was conducted
in a safe and methodical manner with good
interaction between operations
and engineering
during the approach to criticality.
As a result of this review, licensee event report (LER) 50-323/97-002-00
is closed.
01.3
Unit 2 Shutdown Followin
Discover
of a Crack in Turbine Exhaust Cold Reheat
a ~
~Pi
~in
Ins ection Sco
e 71707
92901
92903
The inspectors observed
portions of the reactor shutdown
and subsequent
startup
following identification of a crack in the Unit 2 cold reheat piping.
The inspectors
also observed
management
control of restart activities.
b.
Observations
and Findings
Descri tion of the Event
On April 11, 1997, Unit 2 was shutdown and maintained
in Mode 3, following
discovery of a circumferential crack in the high pressure
turbine exhaust
line to the
moisture separator
reheater
(cold reheat piping).
The crack was noted after piping
insulation was removed to investigate
a small leak (20 drops-per-minute).
The
decision to shutdown the unit was made after a partial inspection of the pipe.
-7-
The cold'reheat piping is 62 inches in diameter with
1 inch pipe wall thickness.
The
design pressure
of the piping is 160 psig.
The crack was noted to be 11 inches
long (8 percent of'circumference)
and was located in the toe of a weld. A small
section of the crack, approximately 1/2 inch in length, was through-wall and the
remaining 10 1/2 inches was near-through-wall.
A separate
2 inch indication was
noted in the pipe which was separated
from the 11 inch crack by a 4 inch ligament.
The licensee determined that the weld had been performed by Westinghouse
and as
.a result they did not have the associated
work documents.
The licensee's
preliminary fracture mechanics
analysis indicated that, with the loads that existed
on the piping, a crack 38 percent of the pipe circumference,
or approximately five
times the size of the crack noted, would be required for the pipe to rupture during
operation.
Although the cold reheat piping is considered
as a part of the high pressure
turbine,
a nonsafety-related
system not subject to ASME/ANSI requirements,
it was
originally designed to meet or exceed the requirements of ANSI B31.1.
The
licensee reviewed the design of the cold reheat piping and performed additional
inspections of the piping without any significant problems being noted.
The
licensee determined that the stresses
on the system are less than 10 percent of the
ANSI B31.1 code allowable.
The licensee performed
a 1/2 inch thick "weld overlay" repair of the crack.
The
weld overlay thickness as well as the supporting stress analysis were based upon
maintaining an ANSI B31.1 design utilizing engineering judgement.
The licensee
plans to continue to monitor both the weld overlay and the crack during the
remainder of the Unit 2 operating cycle; and the licensee intends to replace the weld
during the next refueling outage.
Mana ement Oversi ht of 0 erations and 0 erator Performance
After the initial characterization
of the crack in the cold reheat piping, management
acted promptly in deciding to shut down Unit 2.
Operator response
during the
shutdown was good; however, the inspector noted that recently established
management
expectations,
for the use of three way communications
and SFM
approval of reactivity changes,
were not always followed. Specifically, during times
of increased
control room activity, operators reverted to less formal communications
and the CO moved control rods without the concurrence
of the SFM. Operations
management
was present
in the control room to provide oversight of the shutdown.
The Operations Director noted that the CO was not obtaining the concurrence
of the
SFM prior to initiating rod motion and corrected the problem on the spot.
-8-
En ineerin
Evaluation of the Cold Reheat Line Pi
e Crack
Engineering investigation of the cracked weld appeared
1o be both thorough and
comprehensive.
Although the licensee did not have access to vendor records for
the pipe weld in question, insp~ction of the pipe indicated that at some time in the
past there had been a modification or weld repair in the area of the leak.
The
licensee's
preliminary evaluation indicated that a flaw in the weld had caused
the
crack and that the probable cause was improper heat treatment of the weld repair.
The licensee intends to perform a formal cause analysis during the next Unit 2
refueling outage.
During the investigation, the licensee noted that there had been
a one drop per
minute leak coming from the pipe insulation in the same area as the pipe crack in
July 1996. At that time, a limited investigation had been performed; however, no
piping insulation had been removed and when the leakage stopped
no further
investigation was performed.
Engineering was self-critical in looking back at the
potential missed opportunity to identify the crack at that time and is developing
actions to more thoroughly investigate similar indications of leakage
in the future.
Conclusions
Licensee management
promptly decided to shutdown Unit 2, after discovering
an
11-inch crack in a cold reheat pipe.
Subsequent
engineering
evaluation of the issue
was thorough and the licensee has
implemented monitoring of the weld repair
during the remainder of the operating cycle.
Engineering was self-critical in noting that the leak could have been identified earlier
through a more proactive response
to noted leakage.
Operations performance
during the unit shutdown
and the subsequent
restart was
good; however, during times of increased activity in the control room, operators
used less formal communications
and the CO moved control rods without the
concurrence
of the shift foreman.
08
Miscellaneous Operations Issues (92901)
08.1
Closed
Violation 50-275/96014-01
and LER 50-275196-010-00:
both trains of the
residual heat removal (RHR) system were inoperable due to coincident maintenance
and surveillance testing.
The licensee determined that the root cause of the
violation was personnel
error (cognitive), in that the SFNI thought RHR Pump 1-2
was an SSPS Train B component
and did not verify whether this was correct.
Contributing causes
were:
(1) the SFM did not follow the working level procedure
that requires this test not to be run if any Train A component
is known to be
and (2) changes
in the maintenance
schedule
were not fully evaluated
with regard to TS requirements.
To prevent reoccurrence
of the violation, the
Operations Scheduling
Supervisor and the Daily Scheduling Supervisor issued an
-9-
amended
scheduling policy that directs work planners to identify in weekly work
schedules
those components
that could create engineered
safety feature train
related conflicts.
The licensee also implemented
a new Department Level Administrative Procedure,
AD7.DC6, "On-Line Maintenance
Risk Assessment,"
which requires evaluation of
probabilistic risk and safety function degradation
prior to removing any risk
significant system, structure, or component from service for maintenance.
These
actions appeared
to adequately
address the concerns identified by the violation.
II. Maintenance
M1.1
Maintenance
Observations
Ins ection Sco
e 62707
The inspectors observed
all or portions of the following work activities:
o
MP E-64.1A, Rev 28
AC and DC Molded Case Circuit Breaker Test
Procedure
(Unit I, 480V Bus F)
Work Order C0148835
Emergency
Diesel Generator 1-3 Exhaust Bellows
Connector Replacement
b.
Observations
and Findin
s
The inspectors found the work performed under these activities to be accomplished
in accordance
with procedures.
All work observed was performed with the work
package present
and in active use.
The inspectors observed
system engineers
monitoring job progress
and that quality control personnel were present when
required by the procedure.
M1.1.1 Jum
er Installation for Batter
1-3 Re lacement
a.
Ins ection Sco
e 61726
The inspectors
observed. the installation of jumpers to provide temporary power to
selected
loads, per temporary Procedure
(TP) TD-9703, Revision 0, "Implementation
of DCP E-49297 Battery 13 Replacement."
b.
Observations
and Findin
s
The operations department
developed
a comprehensive
plan for the alignment of
equipment necessary
to allow deenergizing
selected circuits for the installation of
the jumpers.
The implementation of the plan was well coordinated with the onshift
operators to accommodate
the existing plant configuration and with engineering
and
-10-
electricians to install the jumpers.
Involved technical maintenance
and operations
personnel
were knowledgeable
of the operation of the plant equipment
and the
configuration of the temporary electrical power jumpers.
Personnel demonstrated
good communications
as well as self-checking and independent
verifications.
The
system engineer provided direct oversight of the activities in order to resolve
questions if they were to arise during the work.
Conclusions
Significant preplanning of the work was evident.
Involved personnel were
knowledgeable
of assigned
tasks and the system engineer provided guidance
and
direct feedback to questions
about the work.
M1.1.2 Investi ation of Debris Clo
in
Turbine Driven AFW Pum
1-1 Governor
SiciSht lass
a
~
Ins ection Sco
e 62707
37551
During performance of a periodic pump test on turbine driven AFW Pump
1-1 on
April 10, 1997, licensee personnel observed the governor oil level, as indicated by
the sightglass, to be low. An AR was written to have oil added.
After adding oil to
the governor, no increase
in sightglass
level was noted and foreign material was
noted in the sightglass.
The licensee declared the pump inoperable
and initiated
investigative actions to determine the cause.
The inspectors observed portions of
the work and reviewed the analyses that were performed.
b.
Observations
and Findin s
Following disassembly
of the sightglass,
the licensee determined that the sightglass
had become clogged by a small piece of varnish like material in the flowpath from
the sightglass into the governor housing.
A sample of the oil in the governor was
analyzed
and the water content of the oil was determined to be 500 parts per
million (ppm), significantly above the normally expected water content of 100 ppm
or less.
The licensee drained and inspected the governor and clear.ed the
sightglass.
The inspector reviewed the maintenance
history associated
with the
AFW pump governor and found that the results of the previous periodic governor oil
sample, taken in August 1996, also showed
a high water content in the oil.
In
response
to the August 1996 results, maintenance
personnel drained and refilled
the governor oil; however, an AR was not written to document the equipment
problem.
Diablo Canyon Interdepartmental
Administrative Procedure
OM7.ID1, "Problem
identification and Resolution
- ARs," requires that problems be documented
on an
AR. Appendix 7.2 specifies that conditions that could negatively impact structures,
systems,
or components,
if left uncorrected,
shall be considered
problems.
Following the abnormal oil sample results in August 1996, the source of the water
-11-
in the governor was not investigated.
In addition, although the oil had been
changed,
no additional monitoring or evaluations were performed until the second
sample on April 10, 1997, yielded the same results.
Following the second
oil sample with abnormal water content in the oil, the licensee
initiated an AR to document the problem.
Investigation revealed that the only
source of water was leakage from-the cooler attached to the governor housing.
The
AR was annotated that the contamination
level of 500 ppm water in the oil should
not impact pump operability since it had taken 8 months to attain that level of water
in the oil. The inspectors questioned this evaluation,
in that it did not address
some
of the pertinent factors impacting operability.
In particular, the following aspects
were not evaluated,
The licensee had failed to determine the maximum allowable
water content in the oil that would ensure operability of the governor.
This value
was later determined to be 5000 ppm after contacting the vendor.
The effect of
pump run time (four hours since August 1996) on the water content also had not
been evaluated.
The failure to evaluate the impact of pump run time is important
since there is only flow through the oil cooler when the pump is running and as
pump run time increases the expected
level of water contamination
in the oil would
also be expected to increase.
After these issues were questioned
by the inspectors,
the licensee determined that it would be prudent to perform an operability
assessment
of the pump for the degraded
conditions that were noted.
The licensee initiated a work order to inspect the cooler and replace associated
o-rings.
In addition, engineering
has been requested
by operations to determine the
frequency of oil sampling to assure that the problem has been corrected.
The failure to take adequate
corrective action after identifying abnormally high
concentrations
of water in the governor oil in August 1996, and the subsequent
inadequate
assessment
of the impact on operability until questioned
by the
inspectors,
was considered to be a violation of 10 CFR Part 50, Appendix B,
Criterion XVI, "Corrective Action" (VIO 50-275/97003-03).
Conclusions
The licensee failed to take adequate
corrective actions following identification of
abnormally high concentration
of water in the governor of the Unit
1 turbine-driven
AFW pump, in that knowledgeable
personnel initially failed to write an AR to
document the problem until a second sample was taken which yielded similar
results.
In addition, no additional monitoring or evaluations of the potential impact
on operability were performed until the clogged sightglass initiated further
investigation.
-1 2-
M1.2
Surveillance Observations
a.
Ins ection Sco
e 61726
Selected surveillance tests required to be performed by the TS were reviewed on a
sampling basis to verify that:
(1) the surveillance tests were correctly ir.eluded on
the facility schedule;
(2) a technically adequate
procedure existed for the
performance of the surveillance tests; (3) the surveillance tests had been performed
at a frequency specified in the TS; and (4) test results satisfied acceptance
criteria
or were properly dispositioned.
The inspectors observed
all or portions of the following surveillance:
STP M-16HA1
Slave Relay Test for Operation of Interposing Relay for
Containment Spray Pump 2(K645AX), Revision
1
~
STP P-CSP-12
Routine Surveillance Test of Containment Spray
Pump 1-2, Revision 3A
STP V-313B
~
Full Stroke Exercise of Containment Spray
Valve CS-9001A, Revision 0
STP P-23A
Acceleration Timing of Safety-related'Pumps
Actuated
By SSPS Train A, Revision 5
STP M-83A
STP R-1B
STP P-AFW-11
Overcurrent Protection, Revision 16
Rod Drop Measurements,
Revision 17
Routine Surveillance of Turbine-Driven AFW Pump 1-1,
Revision 4
b.
Observations
and Findin s
The first four surveillance procedures
listed above were performed concurrently on
April 14, 1997.
During the testing, the SFM coordinated the efforts of Operations,
Technical and Predictive Maintenance
personnel,
and the PPE to perform the
surveillance concurrently.
The SFM also ensured that the required plant conditions
for the testing were consistent.
The procedures
satisfied the referenced
TS
requirements.
The test results were satisfactory, the test instrumentation was
verified to be within the specified calibration frequency, equipment manipulation
was properly and cautiously performed, and a temporary jumper was installed and
verified.
The proper use of clearances
and valve seals was noted. Adequate
radiological controls were exercised when venting instrumentation.
Operations
conside.ed
Train A of containment spray inoperable during the performance of the
surveillance.
-13-
Conclusions
The inspectors found that the surveillance reviewed and/or observed were being
scheduled
and performed at the required frequency.
The procedures
governing the
surveillance tests were technically adequate
and personnel
performing the
surveillance demonstrated
an adequate
level of knowledge.
MS
Miscellaneous Maintenance Issues (92902)
a.
Inspection Sco
e 92902
In response
to the licensee's
identification of the painting of the governor linkage for
turbine driven AFW Pump 1-1, the inspector reviewed the licensee's corrective
actions to restore the operability of AFW Pump
1-1 and actions to preclude
recurrence.
The review also included the actions taken by the licensee
in response
to previous similar issues at Diablo Canyon and in the industry.
The specifics of the
event were discussed
with the manager of outage services, the AFW system
engineer,
and the painting crew general foreman.
In support of the inspection, the
following documents
were reviewed:
LER 1-97-004, Revision 0, "TS 3.7.1.2 Not Met Due to Paint Applied to
AFW Pump Turbine Governor Linkage Due to Personnel
Error."
AR A0425266, AFWP1: Inoperable - Remove Paint From Governor Cam
PGSE Calculation File:
E.2, AFW System
- PRA System Analysis, Revision 6
PGRE Calculation File: PRA97-04, Revision 0, Increase
in Core Damage
Frequency
(CDF) Due to AFW Pump 1-1 Painting
. Diablo Canyon Power Plant TS
Instructor Lesson Guide:
Insulation and Coatings Section General Orientation
Historical ARs: A0259073, A0332340
Licensee closeout of INPO Significant Event Report (SER) 18-88, Potential
Failures of Motor-Operated Valves Due to Missing, Painted Over, or
Improperly Installed T-Drains.
DCPP Operating Experience Assessment
Evaluation on Painting Practices,
dated October 10, 1994.
-1 4-
b.
Observations
and Findin s
Descri tion of Event
On February 24, ",997, paint crews were performing paint preservation
activities on
the 100 foot elevation of the Unit
1 auxiliary building.
The painting was being
performed under Activity 08 of Work Order C0149250, "Prep/Touchup
Paint, Unit
".
RCA Areas."
During work in the AFW pump rooms, the paint crew took the
initiative to touchup areas of the turbine-driven AFW pump, including the linkage
'etween
the turbine mechanical governor a'nd governor valve, Valve FCV-"<5.
On February 28, ".997, during a system walkdown conducted
by the system
engineer, it was identified that paint had been applied to the governor linkage and
that the paint could impede the proper operation of the mechanical governor.
The
possible impact of the binding of the linkage would be that the governor would not
be able to adjust the position of the governor valve.
Since the governor valve is
normally full open and closes significantly on a pump start to prevent turbine
a bound up governor valve would cause
an overspeed
trip of the pump
turbine.
The system engineer notified the unit SFM who declared the turbine driven
AFW pump inoperable.
The paint was cleaned from the governor linkage and the
pump was successfully tested that same day.
The system engineer documented
the quality problem in AR A0425266.
The quick identification of the problem
demonstrated
the benefits of periodic system engineer monitoring of both system
condition and performance.
Licensee Corrective Actions
As a result of the event, on February 28, 1997, the paint crew general foreman
issued
an e-mail to the paint department to highlight the event and to mandate that,
in all cases,
when painting safety-related
equipment, the responsible
system
engineer will be contacted for guidance.
Discussions were also conducted with the
paint crews to emphasize
the need for specific guidance when painting
safety:related
equipment.
The licensee determined that the quality problem warranted
a nonconformance
report (NCR) and initiated NCR N0002014 to track corrective actions.
Lacking
sufficient information to demonstrate
operability of the turbine driven AFW pump
while the linkage was painted, the licensee initially conservatively concluded that
the pump was inoperable for the duration the paint was applied (approximately
100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />).
This duration exceeded
the pump's allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as
provided in TS 3.7.1.2.
As a result, the licensee issued
LER 50-275/97-004,
Revision 0.
The licensee determined that the root cause of the event was personnel
error, in that inadequate
work instructions were provided to the painters and that
the painters lacked the specific knowledge to determine what areas of the pump
should not be painted.
As described
in the LER,:he licensee plans to implement
procedure
changes
to require appropriate
levels of guidance to be provided to
-15-
personnel
assigned
to plan or perform painting activities on safety-related
equipment.
From discussions
with the licensee, the "appropriate level of guidance"
will be at the system engineer level, consistent with the policy provided by the paint
-crew general foreman.
Safet
Si nificance
In AR AO425266, the system engineer provided a qualitative evaluation of the
ability of the turbine-driven AFW pump to perform its safety function with the
observed
amount of paint applied to the governor linkage.
The governor servo has
the capability of applying over 600 lbs of force to the mechanical linkage to operate
Valve FCV-16. That amount of force was viewed by the system engineer as more
than adequate
to overcome the frictional forces of the applied paint.
Thus, although
the pump had been declared inoperable, the system engineer concluded that the
governor would likely have performed its.safety function if called upon.
Both
motor-driven AFW pumps were operable during the period that the paint was
applied to the governor linkage.
Each motor driven AFW pump is capable of
providing 100 percent of the required AFW flow under accident conditions.
The
only exception to having both motor-driven AFW pumps available was during
surveillance testing of SSPS Train B. This testing rendered AFW Pump 1-2
inoperable for approximately
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
AFW Pump 1-3 was operable for the entire
100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> period.
The licensee also evaluated the increase
in risk (core damage probability (CDP))
associated
with the pump being inoperable from February 24-28.
The additional
CDP was calculated by the licensee by first determining the increase
in the CDF
from the inoperable AFW pump for each hour the pump was considered
The calculation then summed the hourly changes
in CDF and divided the sum by the
number of hours in a year to yield the increase
in CDP.
The calculated increase
in
CDP for the time of interest was 4.33E-7.
The EPRI Probabilistic Safety
Assessment
Guide, TR-105396, utilized by the licensee, defines an increase
in risk
as significant when the increase
in CDP is greater than 1.0E-6.
Thus, the licensee
concluded that this event was not risk significant.
The turbine-driven AFW pump plays its most important role in an event where there
is a total loss of all vital AC power.
However,
a review of the licensee's
analysis in
coping with loss of vital AC power, in accordance
with 10 CFR 50.63, found that
the licensee provided adequate
justification for crediting the availability of one of the
emergency
diesel generators
to be able to provide alternate AC power to vital
equipment needed to bring the plant to a safe shutdown condition.
This appears
to
indicate that there are sufficient redundancies
in the plant's vital AC power system
and that the probability of a total loss of vital AC power is very low. The results of
the licensee's
individual plant examination show that events initiated from a total
loss of vital AC power comprise about 5 percent of the total CDF. Therefor, the
licensee's
conclusion that the painting of the turbine-driven AFW pump was not risk
significant was considered
reasonable.
J,
-1 6-
Paintin
Pro ram and Historical Performance
In addition to the subject event, the inspectors
also reviewed several historical
painting related events and the licensee's
associated
corrective actions.
In general,
very few substantive
actions have been taken by the licensee to improve the
painting process for safety-related
equipment.
In response
"Potential Failures of Motor-Operated
Valves Due to Missing, Painted Over, or
Improperly Installed T-Drains," the licensee concluded that current preventive
maintenance
procedures,
performed on an 18-month frequency, were adequate
to
address
the concerns of the SER.
However, the licensee failed to consider that
painting of motor-operated
valve actuators
is typically performed following
preventive maintenance.
Thus, if a T-drain had been improperly painted, the
condition could have gone undetected
for up to 18 months.
In response
to NRC
Information Notice 91-46, '-'Degradation of Emergency
Diesel Generator Fuel Oil
Delivery Systems," the licensee noted that their practice was to have the system
engineer walk down the diesel engine with the painters prior to the start of work
and again after completion of work to verify no inappropriate items were painted.
However, this practice was neither formalized nor considered for application to
other safety-related
equipment.
The licensee's
response
Information Notice were narrowly focused
and failed to address
the broader adverse
impact that painting activities may have on safety-related
components.
Nuclear quality services
(NQS) personnel performed an evaluation of painting
practices in October 1994 in response
to a number of events involving painting
activities that impacted equipment.
As a result of the findings, NQS concluded that
the overall quality and attention to detail by the painters was appropriate.
The
evaluation resulted in only a few recommendations
with none of the
recommendations
being implemented.
In response
to NRC Information Notice 93-76, "Control of Paint and Cleaners," the licensee determined that no
plant-specific evaluation was needed
based upon the results of the 1994 NQS
evaluation.
Additionally, following criticisms of the paint department,
the paint
crew general foreman issued an e-mail to maintenance
planners
in May 1996,
outlining his expectations
for painting equipment.
These expectations
Included the
desire to provide a specific step in the work order to cor.tact the responsible
system
engineer to walkdown the system with the painters and identify any concerns prior
to starting the work. However, these expectations
were not formalized and th
practice of involving the system engineer has not been consistent.
The failure to take adequate
corrective actions in response
to prior events was
considered
a key contributor to the improper painting of AFW Pump
1-1 and was
identified as a violation of 10 CFR Part 50, Appendix B, Criterion XVI
(VIO 50-275/97003-04).
Conclusions
-1 7-
The event highlighted the importance of the system engineer's
involvement in
maintenance
activities associated
with their system and demonstrated
a strength in
the licensee's
material condition monitoring program.
The licensee missed several prior opportunities to improve the painting process for
plant equipment and preclude this event.
The failure to formally incorporate the
expectations
of the. paint crew general foreman into the work planning process was
considered to be a violation of 10 CFR Part 50, Appendix B, Criterion XVI, and
a
key contributor to the, event.
As a result of this review, LER 50-275/97-004-00
is closed.
III. En ineerin
EB
Miscellaneous Engineering Issues (92903)
E8.1
Closed
Unresolved Item
URI 50-275 323/96024-01:
deficiencies in a design
calculation supporting
an emergency operating procedure
(EOP) decision criterion
could direct operators to take inappropriate actions following a loss of coolant
accident (LOCA). Specifically, following a LOCA, the indicated flood level in th'
containment could be less than the EOP criterion for transition to recirculation
cooling due to the available water in the refueling water storage tank (RWST) and
the accuracy of the containment recirculation sump water level instruments.
This
could result in operators inappropriately entering an emergency contingency action
(ECA) for loss of emergency recirculation cooling (ECA 1.1).
ln response to the inspectors'oncerns,
the licensee reevaluated
the minimum flood
level in the containment following a spectrum of LOCA break sizes (small,
intermediate
and large breaks)
~ The evaluation took into account the estimated
volume of water that would not reach the sump (e.g., water condensed
on
containment surfaces, water in the form of steam, etc.).
Based upon the results of
the new evaluation, the licensee determined that for intermediate
and large break
LOCAs, the flood level in the containment,
including water level instrument
accuracy, would meet or exceed the EOP criterion and allow operators to take
actions to transfer the emergency
core cooling system
(ECCS) to the recirculation
mode.
This conclusion was based upon crediting some portion of the reactor
coolant system inventory that would be lost to the containment sump and not
recovered
by ECCS flow (e.g., SG u-tubes, reactor vessel head).
However, for
small break LOCAs, reactor coolant system inventory could not be credited and the
TS volume available from the RWST was found to be insufficient to ensure that the
indicated flood level would. meet the EOP criterion.
f
The inspectors reviewed the specific actions of ECA 1.1 to evaluate the impact on
emergency
core cooling from an inappropriate transition to the ECA.
For small
-18-
break LOCAs, the transition to recirculation cooling would not be expected to occur
until several hours after the initiation of the event.
This would result in a lower core
decay heat load at the time of transition and, thus, a lower ECCS flow rate would
be required to maintain core cooling.
The lower ECCS flow rate would provide
operators with some time to take actions to either raise containment flood level to
greater than the EOP criterion or evaluate the existing level as adequate
to transition
to the recirculation phase.
The inspectors judged that the actions of ECA 1.1 would
not, by themselves,
threaten core cooling.
Therefore, the safety significance of
transitioning to ECA 1.1 following a small break LOCA was consid
red to be low.
To preclude an inappropriate transition to ECA 1.1, the licensee initiated a
compensatory
measure of raising the minimum RWST level to greater than
93 percent.
This action provided an additional 45,000 gallons of borated water for
the ECCS injection phase to ensure that when recirculation cooling is required,
indicated containment flood level would be greater than the EOP criterion for the full
spectrun. of LOCAs. The failure to adequately
address
and quantify the impact of
LOCA phenomena
on the minimum containment flood level resulted in the improper
translation of the plant's design basis into the EOP criterion.
This failure was
identified as a violation of 10 CFR Part 50, Appendix B, Criterion III, "Design
Control"
(VIO 50-275;323/97003-05).
(Closed
VIO 50-275 95014-03:
inadequate
compensatory
actions taken in
response
to an identified degraded
condition of the 230 kV offsite power system.
The licensee determined the root cause of the violation to be personnel
error in that
the personnel
responsible for determining the appropriate compensatory
measures
did not adequately
evaluate the possible consequences
of,degraded
voltage on the
230 kV system.
To preclude recurrence of the violation, the licensee highlighted the issue in a case
study provided to the plant staff.
The case study described the sequence
of events
and included the lessons
learned.
Training was also provided to the technical staff
to reinforce management's
expectations
on approaching
operability concerns
in a
conservative
manner.
These actions are. sufficient to address
the concerns.
Closed
Violation 50-275 323 96002-02 and LER 50-275/96-001-01: between
September
15, 1994, and January
15, 1996, the licensee discovered that closing
the centrifugal charging pumps (CCPs) common recirculation flow path isolation
valves during periodic pump performance tests potentially impacted the operability
of both CCPs.
The licensee failed to consider the effect of closing the valves on
the accident arialyses for over one year after the initial concerns were identified.
Failure to take prompt and comprehensive
corrective actions resulted
in both units
being unnecessarily
placed in an unanalyzed
condition for a short period during the
periodic CCP surveillance testing.
0
-19-
The licensee determined that the cause of the violation was the initial plant design
and the narrow focus of the technical review group assigned to investigate and
resolve the initial NCR generated
in September
1994.
The licensee added the common recirculation valves to the list of TS valves required
to remain open.
The licensee submitted an inservice testing relief request to the
NRC to allow the surveillance to be performed with the valves open.
The NRC
approved the relief request
and the licensee revised the test procedures
accordingly.
These actions appear sufficient to address
the concerns.
E8.4
Closed
LER 50-275 323 95-001 Revision 1: engineered
safety feature actuation
outside of design basis due to high energy line break interaction with SSPS circuits.
Following the licensee's discovery of this vulnerability in design the NRC opened
unresolved
items 50-275;323/95-02 to track the issue.
A noncited violation was
issued
in NRC Inspection Report 50-275;323/95-11
for inadequate
separation
between safety and nonsafety-related
circuits.
Revision
1 to the LER documents
the results of the root cause evaluation and additional actions initiated to prevent
recurrence.
The licensee reported that an extensive review of existing Class
1E
electrical circuit isolation was conducted with no additional concerns
being
identified.
The corrective actions taken appear to have focused on both the
identification of additional instances
of similar discrepancies
and the preventing
inadequate
electrical separation
in future design changes, by incorporating specific
requirements
in the review process to verify adequate
separation
exists where
required.
These actions appear to appropriately address
concerns involving the
adequacy of electrical separation.
V. Mana ement Meetin
s
X1
Exit Meeting Summary
The inspectors presented
the inspection results to members of licensee management
at the
conclusion of the inspection on May 1, 1997.
The licensee acknowledged
the findings
presented.
The inspectors
asked the licensee whether any materials examined during the inspection
should be considered
proprietary.
No proprietary information was identified.
0
'I
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
Licensee
J. R. Becker, Director, Operations
W. G. Crockett, Manager, Nuclear Quality Services
T. L. Grebel, Director, Regulatory Services
T. F. Fetterman,
Director, Instrumentation
and Control Engineering
S. R. Fridley, Manager, Outage Services
S. C, Ketelsen, Senior Engineer, Regulatory Services
D. B. Miklush, Manager,
Engineering
Services
D. H ~ Oatley, Manager, Maintenance
Services
R. P. Powers, Manager, Vice President
DCCP and Piant Manager
J. A. Shoulders,
Director, Support Engineering
D. A. Taggart, Director, Nuclear Quality Services Engineering
and Procurement
R. L. Thierry, Director, Balance of Plant Systems
D. A. Vosburg, Director, Nuclear Steam Supply Systems
Engineering
-2-
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance
Observations
IP 71707: Plant Operations
IP 92901: Followup - Plant Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-275;323/97003-01
~
IF I
periodic testing requirements
for MFP turbine stop
valves
50-323/97003-02
failure to follow surveillance procedure
requirements
for
testing MSIVs
50-275/97003-03
failure to take adequate
corrective actions after
identifying water in the turbine-driven AFW pump
governor
50-275;323/97003-04
failure to take adequate
corrective actions for
controlling the conduct of painting activities
50-275;323/97003-05
failure to adequately
incorporate design basis into EOPs
Closed
50-323/97003-02
failure to follow surveillance procedure
requirements for
testing MSIVs
50-323/97-002-00
50-275/96014-0]
LER
partial loss of main feedwater and plant trip
both trains of RHR inoperable due to coincident
maintenance
and surveillance testing
50-275/96-01 0-00
LER
both trains of RHR inoperable
due to coincident
maintenance
and surveillance testing
50-275/97-004-00
LER
TS 3.7.1.2 not met due to painting of AFW pump
turbine governor valve mechanical linkage
50-275;323/96024-01
-3-
deficiencies in a design calculation for minimum
containn ent flood level following a LOCA
50-275/9501 4-03
50-275;323/96002-02
inadequate
corrective actions to address
degraded
offsite power
'I
inadequate
corrective actions to address
the impact of
closing the CCP recirculation valves on the accident
analyses
50-275/96-001-01
50-275;323/95001-01
LER
LER
inadequate
corrective actions to arldress the impact of
closing the CCP recirculation valves on the accident
analyses
lack of separation
of ESF circuitry
LIST OF ACRONYMS USED
CO
DP
LER
MSTE
NQS
SFM
SSPS
TS
Action Request
centrifugal charging pump
core damage frequency
core damage
probability
control operator
differential pressure
emergency contingency action
emergency
core cooling system
Emergency Operating Procedure
Licensee Event Report
loss of coolant accident
measurement
and test equipment
main feedwater pump
nonconformance
report
noncited violation
nuclear quality services
Public Document Room
power production engineer
pounds per square inch gage
refueling water storage tank
significant event report
shift foreman
solid state protection system
surveillance test procedure
Technical Specification
unresolved
item
il