ML16342D520
| ML16342D520 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D521 | List: |
| References | |
| 50-275-96-23, 50-323-96-23, NUDOCS 9701280375 | |
| Download: ML16342D520 (52) | |
See also: IR 05000275/1996023
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-275, 50-323
License Nos.:
Report No.:
50-275/96023, 50-323/96023
Licensee:
Pacific Gas and Electric Company
Facility:
Diablo Canyon Nuclear Power Plant, Units
1 and 2
Location:
Dates:
7 1/2 miles NW of Avila Beach
Avila Beach, California
November 10 through December 21, 1996
Inspectors:
M. Tschiltz, Senior Resident.Inspector
S. Boynton, Resident Inspector
D. Allen, Reactor Inspector
G. Good, Emergency Preparedness
Inspector
D. Corporandy,
Project Inspector
Approved By:
H. Wong, Chief, Branch
E
Division of Reactor Projects
ATTACHMENT:
Supplemental
Information
970i280375 970il7
- DOCK 05000275
8
0
-2-
EXECUTIVE SUMMARY
Diablo Canyon Nuclear Power Plant, Units
1 and 2
NRC'Inspection Report 50-275/96023; 50-323/96023
~Oerations
Control room operators
and fire brigade members responded
appropriately in
accordance
with approved procedures to a reactor trip and electrical fire on
November 22, 1996.
Operators promptly assessed,
identified, and dealt with
equipment anomalies.
Response
in combatting the fire was cautious with
appropriate concern for both personnel
and plant safety (Section 01.2).
Clearance
process weaknesses
were identified in that the authorization list was out
of date, training had not been provided even though recent changes
had been made
to the clearance
procedure,
and the transfer of the work between the shift foreman
and the plant operator was unclear in the clearance
procedure.
In addition,
corrective actions were delayed in response
to a previous action request because
the issue was categorized
as nonquality related and was being given a low priority
(Section 01.3).
The licensee's review of past surveillance test results raised concerns about the
basis for both the reliability and continued operability of the 4kV bus first level
relays (FLURs). Following identification of the concern, the licensee
carefully considered
the potential for common mode failure.
Licensee management
directed that confirmatory testing be conducted
promptly to fully assess
the
operability of the relays.
Investigation of the root cause of the problem led to the
implementation of a change
in the relay settings to improve reliability. Licensee
management's
response
to the issue was prompt and decisive and demonstrated
the appropriate concern for safety and sensitivity of the need for compliance with
Technical Specifications
(TS) (Section M1.1.2).
Maintenance
Mechanical maintenance
personnel identified a deficiency in a check valve being
installed in the auxiliary saltwater (ASW) system.
Identification and correction of
the problem by involved maintenance
and quality assurance
personnel demonstrated
an awareness
of potential problems associated
with the maintenance,
a questioning
attitude and appropriate follow through in resolving concerns
raised during
maintenance
activities (Section M1.1.1).
Since 1993, 4kV FLUR surveillance test results indicated that the relay response
to
degraded
voltage was found to exceed the TS allowed response
time on 8 separate
occasions.
This performance
had been considered
acceptable without performing a
-3-
root cause analysis and determining appropriate corrective actions.
A violation was
identified- (Section M1.1.2).
EnrnineerinE
Failure of maintenance
personnel to remove an information tag referencing
a
temporary gauge upon its removal, and failure of operators to remove the jumper
annotations
from the control room drawings were indicative of both inadequate
work practices and inadequate
control of temporary modifications.
A violation was
identified.
Untimely updating of control room drawings and procedures
requiring
revision
following the installation of a permanent
pressure
gauge demonstrated
a
lack of attention to detail in the implementation of the licensee's
minor modification
design change process
(Section E1.1).
The licensee took prompt action to correct inspector-identified fastener deficiencies
on the vital 480V switchgear.
However, follow-on actions to address the quality
problem were considered
weak in that engineering
failed to recognize the need to
document
in an AR the deficiencies for evaluation and resolution in accordance
with
plant procedures.
A violation was identified (Section E2.1).
The licensee identified past occurrences
where a degraded
230kV offsite power
source would have resulted in the component cooling water system being unable to
mitigate the consequences
of a design basis loss of coolant accident.
A noncited
violation was identified (Section E8.1).
TS required Plant Staff Review Committee (PSRC) reviews of safety evaluations for
core reloads and fuel sipping activities completed under the provisions of
10 CFR 50.59, were not performed.
A violation was identified (Section E8.2).
Plant Su
ort
~
The licensee's
emergency
plan and implementing procedures
did not clearly describe
their onshift dose assessment
capability.
Further evaluation of the information
obtained using the temporary instruction will be conducted
by NRC Headquarters
personnel
(Section P3.1).
Re ort Details
Summer
of Plant Status
Unit 1 began this inspection period at 100 percent power.
On November 22, 1996, the
unit tripped dae to an electrical fault associated
with a grounding transformer for unit
Auxiliary Transformer 1-1.
The unit remained in Mode 3 while repairs were made to the
affected buswork.
Unit 1 reentered
Mode
1 on November 30 and was returned to 100
percent power on December 2. The unit remained at full power for the balance of the
inspection period.
Unit 2 began this inspection period at 100 percent power.
The unit remained at full power
throughout 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
Unit 1 12kV Electrical Fault and Plant Tri
a.
Ins ection Sco
e 71707
On November 22, an electrical fault and fire in a grounding device associated
with
unit Auxiliary Transformer
1-1 resulted in a unit trip and reactor trip. The inspectors
responded
to the control room and observed
operator actions in response
to the trip
and to the electrical fire.
b.
Observations
and Findin s
The operating crew performed well in response
to the event.
The immediate actions
of Procedure
E-O, "Reactor Trip or Safety Injection," and Procedure
E-0.1, "Reactor
Trip Response,"
were taken in a timely manner.
The operators generally
communicated
these actions clearly and concisely.
The inspectors
noted several equipment anomalies that complicated operator
response.
These anomalies, which included loss of the main condenser
and failure
of one of the intermediate range nuclear instruments to properly track reactor
power, were promptly identified and addressed
by the operating crew.
In response
to the loss of the main condenser,
operators
closed the main steam isolation valves
and established
decay heat removal via the atmospheric
steam dumps in
accordance
with Procedure
E-0.1.
The failure of the intermediate range nuclear
instrument to track reactor power prevented
the source range instruments from
automatically reenergizing when power reached their permissive setpoint (P-6).
-2-
Operators manually reenergized
the source range instruments when power fell
below<h8" P-6 Setpoint.
The fire brigade responded
to the location of the electrical fault within 10 minutes
after the control room announced
the fire. The unit trip and the transfer of the
12kV busses to startup power isolated the fault within the first second of the event
and extinguished the electrical fire. Although some Class A material (e.g. cable
insulation) continued to smolder for several minutes, the fire was essentially out
when the fire brigade arrived.
Although no further firefighting efforts were required
at the scene, the shift supervisor directed the evacuation of the Unit 1 turbine
building until a thorough walkdown could be performed to assess
collateral damage
or hazards.
Licensee Event Report (LER) 50-275/96-017,
Revision 0, documented
the automatic reactor trip. The inspectors reviewed the
I ER and determined the specified
corrective actions were appropriate to prevent recurrence.
Based upon this review
the LER is closed.
c.
Conclusions
Licensee personnel
responded
well to the reactor trip and electrical fire on
November 22.
Operators promptly identified and addressed
equipment anomalies.
The operations staff also showed an appropriate sensitivity to personnel safety in
responding to the fire.
01.3
Review of the Diablo Can on Power Plant
Clearance
Process
a.
Ins ection Sco
e
In light of past problems with the licensee's clearance
process,
the inspector
reviewed Procedure
OP2.ID1, "DCPP Clearance
Process,"
and guidance
on
"Management Expectations for Supervisors"
issued on February 23, 1996.
The
inspectors
also reviewed the thoroughness
and quality of the licensee's review and
response
to Action Request
(AR) A0396913 which sought clarification on the
February 23 guidance
as it applied to Procedure
OP2.ID1 and which pointed to
potential problems with the guidelines as they applied to Procedure
OP2.ID1.
b.
Observations
and Findin s
The current revision of Procedure
OP2.ID1, Revision 5, consists of a master
clearance/ subclearance
concept.
A master clearance
is used to isolate work
boundaries
and track the status of plant equipment
as work is performed.
Work is
authorized by issuing a subclearance
to a group or department performing work
within the boundary of the master clearance.
0
-3-
In the clearance
process, the shift foreman (SFM) is responsible for reviewing
procedure's
to"Bear and restore cq.:ipment, and the Master Clearance
Holder is
responsible
for overseeing
the proper implementation of the procedures.
Procedure
OP2.ID1 allows for the Master Clearance
Holder to be the SFM or
another person qualified for such tasks.
The inspectors noted that Section 3.4 of
the procedure stated that "...the Master Clearance
Holder should have
documented
training on the clearance procedure
and be on the qualified Clearance
Requestor/Delegate
Authorization list." The inspectors briefly reviewed this list with
a licensee representative,
who noted that the list had not been updated
in years.
Some individuals on the list had long ago left the organization.
It was further noted
that training had not recently been provided to the individuals on the list even
though Procedure
OP2.ID1 had recently undergone
several revisions.
Section 4.4.12 of Procedure
OP2.ID1 requires routing of all Master Clearances to
the SFM for processing.
Section 4.6.1 requires that the senior control operator is
responsible for ensuring the plant operator assigned to process the clearance;
is
properly qualified.
The inspectors noted that Procedure
OP2.ID1 did not clearly
define how the clearance
processing
activities move from the SFM to the plant
operator.
At the time of the inspection, the licensee was in the process of revising
Procedure
OP2.ID1 to clarify the clearance process.
The licensee pointed out that
the draft of the upcoming revision to Procedure
OP2.ID1 contained wording to
require the Master Clearance
Holder to be the SFM.
When issued, Revision 6 of
Procedure
OP2.ID1 will be reviewed to verify that the Master Clearance
Holder is
the SFM and that responsibilities and delegation, where applicable, are clearly
delineated
in the procedure
(IFI 50-275(323)/96023-01).
During the review process,
the inspectors
noted that AR A0396913 was initiated
on March 26, 1996, and on the following day an individual was assigned to respond
to the AR. Procedure
OM7.ID1, "Problem Identification and Resolution - Action
Requests,"
defines
a Quality Problem as "...a deficiency which renders or could
render a quality related item or activity unacceptable
or indeterminate."
Action
request forms contain a "Quality Problem Checklist" section wherein each checklist
item is required to be answered.
The AR is automatically considered
a Quality
Problem, if anything other than a "N" appears
in one of the fields.
was determined not to be a Quality Problem.
The Quality Assurance
(QA) Class
field was marked as "N" indicating "not subject to QA requirements."
The
inspectors noted that the "N" in the QA Class field was inappropriate
because
Procedure
OP2.ID1, a QA-related procedure,
was one subject of the concerns
in the
AR.
For the period from March 27, 1996, to December
13, 1996, the licensee had not
formally documented
any action taken on AR A0396913.
According to the
licensee, dispositioning of an AR that was not a Quality Problem would not be of
high priority. According to the individual assigned
to the AR, work was being done
4
to address the concerns
raised in the AR, and this was evidenced
by the current
work'to revis'e Procedure
OP2.ID1.
c.
Conclusions
The inspectors considered
the lapses
in training on the DCPP Clearance process,
the
licensee's failure to keep the Requestor/Delegate
authorization list current, and the
ambiguities in the current revision of Procedure
OP2.ID1 to be evidence of a
weakness
in the licensee's
clearance
process.
The inspectors
also considered that
the licensee's
response to problems identified in AR A0396913 lacked formality and
timeliness.
II. Maintenance
M1
Conduct of Maintenance
M1.1
Maintenance
Observations
a.
Ins ection Sco
e 62707
The inspectors observed
all or portions of the following work activities:
C0147525
Replace ASW Vacuum Breaker
C0146910
Replace Centrifugal Charging (CC) Pump 1-1 Gear Drive Lube
Oil Heat Exchanger (Unit 1)
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.
Technicians were experienced
and
knowledgeable
of their assigned
tasks.
The inspectors observed the system
engineer monitoring job progress during the replacement
and testing of the gear
drive lube oil heat exchanger.
Additional observations
on the ASW vacuum breaker
replacement work are provided in the following section.
M1.1.1
Re lacement of ASW Vacuum Breakers
a.
Ins ection Sco
e 62707
On December 4, the inspectors
observed
portions of the activities associated
with
the replacement of two of the Unit
1 ASW piping vacuum breakers.
-5-
b.
Observations
and Findin
s
The ASW vacuum breakers were being replaced with identical swing check valves
with the exception that the new valves incorporated
a teflon surface to the valve
seat.
The teflon seating surface was installed to alleviate the potential for bonding
of the valve seat to disc mating surface which could occur over long periods of
inactivity of the valve.
The vacuum breakers
are located within a concrete vault outside of the plant
protected area.
The inspectors noted that proper security measures
were taken
while the vault was open and accessible.
Rigging equipment utilized for the vault
cover and the valves was in accordance
with plant procedures.
During installation of the first valve, the mechanical maintenance
personnel
noted
that the valve disc would not swing freely.
The maintenance
personnel
rejected
the valve and took action to obtain another valve from stock.
The system engineer
and mechanical maintenance
foreman responded
to address
corrective actions
following identification of the defective valve.
These actions demonstrated
a strong
questioning attitude.
c.
Conclusions
The replacement
of the ASW vacuum breakers
and the supporting activities were
performed in accordance
with plant procedures.
The identification of the defective
valve by the maintenance
personnel demonstrated
a questioning attitude and
appropriate follow through in resolving concerns
raised during maintenance
activities.
M1.1.2 4kV FLUR Re lacement
Ins ection Sco
e 62707
The inspectors reviewed the surveillance results from testing performed for the past
three outages
on the 4kV FLURs.
During the review the inspectors referenced the
following documents:
AR A0352900 documenting 4 kV undervoltage
relay out of tolerances
AR A0418008 documenting placement of the 4kV system in goal
setting
Surveillance Test Procedure
M-75, Revision 15, "4kV Vital Bus
Relay Calibration"
Maintenance
Procedure
E-50.10B, Revision 7, "General Electric Type
lAV55C Undervoltage
Relay Maintenance"
0
-6-
~
Design Criteria Memorandum S-63, Revision 1.3,"4160 System,"
Section 4.3.5.2
Nonconformance
Report 2007, 4kV Undervoltage Protection
4
DCPP TS Table 3.3.4, Engineered
Safety Features Actuation System
Instrumentation Trip Setpoints
LER 50-275(323)/96-018
Revision 0: "4kV Bus Undervoltage
Protection Relays Out of Specification Due to Setpoint Drift Due to
Unknown Cause."
b.
Observations
and Findin s
During the licensee's review of 4kV FLUR test results from previous outages,
the
licensee noted that the relays had failed TS required surveillance tests due to their
as-found time delays at 2583 volts exceeding the maximum 10 second interval
specified in TS Table 3.3-4.
Review of the test data revealed that during the
18 relay tests performed during the past 3 Unit
1 and 2 refueling outages,
eight
relays had as-found time delays of greater than the 10 second limit specified in TS.
Assessment
of 4kV FLUR 0 erabilit
After identification of the numerous test failures, the licensee wrote a prompt
(POA). The POA noted that the FLUR has two functions.
The first function is to detect
a low bus voltage at approximately 60 percent of the
nominal bus voltage and allow a maximum of 10 seconds
in order to allow transfer
from a degraded
auxiliary power source to startup power before starting the
Emergency
Diesel Generator
(EDG). The second function is to start the EDG which
supplies the associated
4kV bus within 0.7 seconds
of detecting
a dead bus.
The
operability of the first function of the relay was in question since the eight test
failures were due to exceeding the maximum allowed time delay of 10 seconds.
The delayed start of the EDG is also accomplished
by a separate
design feature, the
second
level undervoltage
relay (at approximately 3800 volts).
In a degraded
voltage condition, the secondary
relay actuation of the delayed start of
the EDG and the 4kV load shed would occur before the FLUR actuation.
Therefore,
the FLUR out of tolerance time delay would not have prevented the performance of
this safety function.
Mana ement
Res
onse to Historical Surveillance Test Results and the POA
Plant management's
review of the POA determined that the FLUR relays should be
considered
operable until testing was accomplished.
However, management
directed that the testing be performed as soon as possible since past data provided
strong evidence that some of the relays could be expected
be out of specification
0
-7-
during the operating cycle.
While making preparations for the relay testing it was
determined that there was only one spare relay of this type onsite.
The licensee
calibrated the spare relay on the bench and then removed
EDG 1-3 from service,
replaced its FLUR with the spare,
and tested the previously installed relay. Test
results indicated that the relay was set within the TS requirements.
Prior to
continuing, the licensee implemented
a design change to adjust the relay settings so
that the time delay feature would be less subject to change.
The licensee continued
with the one for one exchange
and testing of the relays until the FLURs for all six
EDGs were replaced with relays calibrated with the new settings.
Of the six relays
tested, one was found to be outside the TS specified time with an as-found time
delay of 11.8 seconds.
The licensee has initiated a nonconformance
report on this
problem.
Past Corrective Actions for 4kV FLUR Test Failures
Review of the ARs which documented
the previous surveillance test failures
revealed that in October 1994 the licensee noted that the FLURs had exhibited what
was characterized
as excessive drift for which there was no conclusive cause.
At
that point, the licensee planned on monitoring future performance of the relay in
order to determine if broader corrective action was warranted.
noted that a quality evaluation would not be issued until additional test results were
obtained which would allow for further trending of relay performance.
The licensee's justification for not issuing a QE noted that the relay functioned
properly for a dead bus condition and that the increase
in the time delay above that
allowed by TS did not impact safety.
The AR also had an action to track the future
relay performance
and evaluate whether broader corrective actions were warranted.
Although additional relay surveillance test failures occurred and were documented
in
the AR, no additional actions were taken for determining the root cause of the
failures until November 1996.
The failure of the licensee to assure that the cause
of the excessive
relay drift was determined
and take corrective action to preclude
recurrence
is a violation of 10 CFR Part 50 Appendix B Criterion XVI
(VIO 50-275 (3231/96023-02).
Conclusions
Management
responded
appropriately once concerns were raised regarding past
relay surveillance test results.
However, based
upon the number of tests with
out-of-specification results, the existing surveillance program did not provide
adequate
assurance
that the relay was capable of performing its required function
during an entire 18 month operating cycle.
In addition, corrective actions taken
following repeated
out-of-specification relay test results failed to identify and correct
the cause of the exceeding
TS specified limits.
-8-
M1.2
Surveillance Observations
a.
Ins ection Sco
e 61726
The inspectors observed
all or portions of the following surveillances:
STP R-2B2, Revision 5, "Manual Operator Heat Balance"
~
STP P-AFW-11, Revision 4, "Routine Surveillance Test of Turbine-Driven
Pump 1-1"
b.
Observations
and Findin
s
The inspectors found that the surveillance tests 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.
The inspectors
also
noted that test results were appropriately dispositioned.
M8
Miscellaneous Maintenance Issues (92902)
M8.1
Closed
IFI 50-275 96021-05:
During a review of the completed work order (WO)
that replaced the motor for residual heat removal (RHR) Pump 1-1, adequate
documentation
could not be found to demonstrate
that the motor had been properly
assembled
to the pump in accordance
with the new motor's seismic qualification
evaluation
(SQE) (PGRE Calculation SQE-46) using the required bolt torque of
124 ft-lbs.
The licensee also reviewed the calibration sheets for the maintenance
and test
equipment (MRTE) utilized during change out of the RHR 1-1 motor.
The licensee
found that maintenance
personnel
had requested
the calibration lab to verify a
torque value of 124 ft-Ibs for the torque wrench utilized in the pump/motor
reassembly activity. Since no other specified torque value was called out for the
MRTE used in that activity, the licensee concluded that hold down bolts had been
properly torqued.
The licensee has initiated several corrective actions in response
to the
inspectors'oncerns
regarding the WO documentation
and is tracking those actions through
The licensee will be:
(1) revising Procedure
MP M-10.1 to add line
items for the installation of the motor hold-down bolts, (2) reviewing
Procedures
MP M-10.1 and E-10.1 to assure that component nomenclature
is
-9-
consistent between them, and (3) adding the specified torque of 124 ft-Ibs to the
RHR.pump drawing.
Conclusions
WO C0116037 and Procedures
MP M-10.1 and E-10.1 were unclear in that they
failed to provide a link to the implementation of the requirements
specified in PGSE
Calculation SQE-46.
The inspectors considered
this to be a weakness
in the
documentation
of safety-related
maintenance
to assure continued seismic
qualification.
E1
Conduct of Engineering
E1.1
Reactor Coolant Letdown Filter Desi
n Chan
e
a.
Ins ection Sco
e
37551
The inspectors reviewed the licensee's activities associated
with the installation of
permanent
pressure
gauges downstream of the No. 2 reactor coolant letdown filters
for Units
1 and 2. The review included the licensee's evaluation and conclusions
on
the impact of the design change on plant drawings, procedures
and maintenance.
b.
Observations
and Findin s
Due to a historical design deficiency, direct measurement
of the differential pressure
across the No. 2 letdown filter could not be made when the No.
1 filter was
isolated.
Specifically, the common downstream
pressure
gauge for both filters was
located within the isolation boundary for the No.
1 filter. To provide for direct
measurement
of the differential pressure
across the No. 2 filter the licensee installed
a temporary pressure
gauge (PX-342) downstream of the No. 2 filter. This
temporary modification (jumper) was controlled under Procedure
CF4.ID7,
Revision 3, "Temporary Modifications - Plant Jumpers
and
M5TE." The design
change, documented
under maintenance
modification (AT-MM)AR A0367186 for
Unit
1 and A0367188 for Unit 2, was implemented to eliminate the need for the
temporary jumper.
The new pressure
(Pl-2505) were physically installed in
the units in October 1996.
Tem orar
Jum
er Controls
On November 4, 1996, the inspectors noted during a plant tour that the physical
installation of both permanent
pressure
was complete and that the
temporary gauges
had been removed; however, an information tag remained on the
root valve to the new pressure
gauge on Unit 2 indicating that temporary
Gauge PX-342 was still installed.
The Unit 2 control room operating valve
-10-
identification diagram (OVID) ¹ 107708, Sheet 4, also contained annotations
showing the. installation of the temporary gauge.
The Unit 2 jumper log, however,
documented
the removal of the temporary gauge on October 30.
The
documentation
available to the operators
did not reflect current plant configuration.
Procedure
CF4.ID7 requires all information tags and drawing annotation sheets to
be removed when a temporary modification is removed.
The failure of maintenance
personnel to remove the temporary jumper information tag on Unit 2 and the failure
of operations
personnel to remove the drawing annotations
indicate a failure in the
licensee's
configuration controls for temporary modifications and is a violation of
Procedure
CF4. ID7 (VIO 50-323/96023-03).
Plant Drawin s
On December 2, the inspectors attempted to verify that the control room copies of
the plant drawings affected by the design change
had been updated.
However, it
was identified that two of the three piping and instrument drawings (PKIDs)
affected on Unit
1 and all three of the PSIDs affected on Unit 2 contained only
temporary sketches of the modification without indication that the modification had
been completed.
Additionally, the affected Unit 2 chemical and volume control
system (CVCS) OVID did not reference the new gauge.
The licensees
processes
for updating plant drawings are described,
in part, in
Procedure
CF3.ID6, Revision 2, "Field Correction Transmittal (FCT) Processing,"
and
Procedure
OP1.DC21, Revision 1A, "Development and Control of Plant Operating
Valve Identification Diagrams and Instrument Prints."
Step 5.10.1 of
Procedure
CF3,ID6 states that Priority
1 drawings, such as PSIDs, should be
updated within 30 days of engineering
acceptance
of the FCT. AT-MM
AR A0367186 documented
engineering's
acceptance
of the Unit
1 FCT on October
24 while AT-MMAR A0367188 documented
engineering's
acceptance
of the Unit
2 FCT on November
1. The time delay between the acceptance
of the FCTs and
the update of the PSIDs in the control room did not meet the expectations
of
Procedure
CF3. ID6.
In accordance
with Procedure
OP1.DC21, OVID revisions are requested
via a OVID
change transmittal (OCT). The OCT, submitted by the sponsoring
engineer of a
design change,
is processed
by the OVID office supervisor and then forwarded to
Document Services for distribution to controlled copy holders.
An OCT is closed
out when the OVID office supervisor issues the revised OVID incorporating the
changes
of the OCT. The OCTs for this design change were completed by the
sponsoring
engineer and forwarded to the OVID office supervisor who processed
them on November 1.
On December
2, the inspectors found that the control room
copy of the Unit 2 CVCS OVID did not yet reflect the design change.
-1 1-
0 eratin
Procedures
and Lo s
As part of the design change process,
operations evaluated the impact of the new
pressure
on operating procedures.
The evaluation concluded that
Attachments 9.3 and 9.4 of Procedure
OP B-1A:IX, "CVCS - Valve Alignment
Verification Checklist for Plant Startup," required revision to reflect the new gauge
and its associated
valves.
An on-the-spot-change
(OTSC) to Procedure
OP B-1A:IX
was issued on November 20 to reflect those revisions.
However, Attachment 9.2
was also impacted by the design change,
but had not been revised.
Attachment 9.2 contained
a note to ensure that the downstream
isolation valve for
the No.
1 filter is open so that differential pressure
across the No. 2 filter can be
determined.
The design change eliminated the need for this action.
The operating logs utilized by the auxiliary operators were also identified by the
inspectors
as being impacted by the design change.
The daily rounds sheets
and
their associated
technical bases provide for documentation
and evaluation of various
plant process parameters,
including the differential pressure
across the letdown
filters. These documents
had not been updated to reflect the availability of the
permanent
Conclusions
The failure of maintenance
personnel to remove the information tag referencing
temporary Gauge PX-342 upon its removal, and the failure of operators to remove
the jumper annotations from the Unit 2 OVIDs indicated
a lack of attention to detail
by operations
in the implementation the licensee's temporary modification program.
The delays in updating plant drawings associated
with the installation of permanent
Gauge Pl-2505 and the failure to promptly identify and update all of the affected
procedures
and documents
used by operations demonstrated
a lack of rigor by
operations
in the minor modification design change process.
Reactor Coolant S stem
Flowrate Determination Test Chan
es
Ins ection Sco
e 37551
The inspectors reviewed the actions taken by the licensee when the change was
made to perform the measurement
of RCS flow at the end of cycle.
In addition, the
inspectors reviewed a TS interpretation for the setting of the RCS loss of flow
protection trip setpoints.
Observations
and findin s
The licensee measures
RCS flow by performing a heat balance (calorimetric) on
each side of the steam generator.
To avoid the potential for future derating of the
units due to reductions in the calculated
RCS flowrate due to the bias effect of hot
-1 2-
leg temperature
streaming, the licensee performed
a flow uncertainty analysis to
evaluate the possibility of changing the performance of primary flow calorimetrics
from the beginning of cycle (BOC) to the end of cycle (EOC).
Historically, the licensee has performed
a primary flow calorimetric at the BOC
during initial power ascension.
Based upon the results of the uncertainty analysis,
the licensee concluded that it was acceptable to perform primary flow calorimetrics
using EOC data.
Following 1R6 and 2R6 the licensee made the change to perform
primary flow calorimetrics at the EOC.
The licensee did not perform a safety
evaluation prior to making the change
and the PSRC was not required to review
since the technical review determined that the change
did not alter the intent of the
procedure.
Hot Le
Tem erature Streamin
Effects
Although the uncertainty associated
with performing the analysis at EOC was
greater than the uncertainty at BOC, the actual calculated flowrate was higher due
to the effect of the higher than actual measured
hot leg temperatures
at the BOC
caused
by hot leg temperature
streaming.
The hot leg temperature
streaming effect
is more pronounced
at the BOC than at the EOC due to the relative decrease
in the
difference in the power output of the inner and outer regions of the core during the
cycle.
Hot leg temperature
streaming occurs as a result of the combined affect of low
leakage core designs, that have a higher percentage
of core power produced
in the
inner core regions, and incomplete mixing of flow in the upper plenum.
Low
leakage core loading was first used in by the licensee
in 1R3.
However, up to 1R6
and 2R6 the hot leg temperature was measured
by resistance temperature
detectors
(RTDs) installed in the bypass lines.
This allowed for greater mixing of flow prior to
the measurement
of hot leg temperature.
Thus, the impact of low leakage cores
was offset by the greater mixing prior to 1R6 and 2R6.
Effect of RTD Thermowell Installation on Measured Tem erature
During 1R6 and 2R6 the licensee removed the RTD bypass lines and installed RTD
thermowells in both hot and cold legs at 120 degree intervals around the
circumference of the pipe.
These design changes
were performed in conjunction
with the installation of the Eagle 21 microprocessor-based
process protection
system.
Following the installation of the thermowells, the RTDs sensed
an
increased temperature
distribution across the cross section of the pipe.
The effect
of hot leg temperature
streaming is more prominent at Diablo Canyon,
as compared
to other Westinghouse
design facilities that utilize low leakage core loading,
because
the hot leg RTDs are installed closer to the reactor vessel due to physical
constraints.
-13-
The hot leg temperature
measurement
is biased by the temperature
streaming which
causes the measured
temperature to be greater than the actual temperature.
This
results in the measured
RCS flowrate being lower than the actual flowrate.
The net
effect of the hot leg temperature
streaming error was a reduction in the margin to
the TS minimum measured flow. Since hot leg streaming is less pronounced
at the
EOC the bias is less and the measured
RCS flowrate increases
so that there is less
difference between measured
and actual flowrates.
However, the performance of
the primary flow calorimetric at the EOC involves additional uncertainties that must
be accounted
for in the analysis which are not included as a part of the BOC
uncertainty.
RCS Flowrate Measurement
Uncertaint
The accuracy of performing RCS flowrate determination at the BOC using
a primary
flow calorimetric is based upon
a detailed flow uncertainty analysis for plant-specific
instrumentation.
A flowrate uncertainty of 2.4 percent of thermal design flow (TDF)
for Units
1 and 2 is noted in TS Figures 3.2-3a and 3.2-3b.
The licensee calculated
the total uncertainty or excess random error associated
with measuring
flowrate at the EOC was approximately 2.9 percent of TDF. Since the uncertainty
was approximately 0.5 percent greater than the 2.4 percent of TDF included in TS,
the licensee applied a flow penalty of 0.5 percent.
The licensee's
procedure for performing the primary flow determination was revised
to include the use of flow penalties to ensure that minimum measured flow and
safety.setpoint
analysis limit requirements
were met.
The licensee considered the
treatment of the excess flow measurement
uncertainty as a flow penalty to be
conservative.
RCS Low Flow Tri
Set pints
The primary flow calorimetric procedure
is also performed by the licensee to provide
a basis for calibrating the pressure
sensors
on the elbow taps for establishing the
setting of the RCS loss of flow (LOF) setpoints
in Table 2.2-1 of the TS.
STP R-26,
"RCS Primary Coolant Flow Measurements,"
specifies the LOF setpoints
be set at
90 percent of the actual loop flowrate, as measured
by the primary flow
calorimetric, but not less than the TS minimum setpoint of 90 percent of minimum
measured
flow. Therefore, the increased uncertainty or error in flow measurement
also affects the flow error contribution to the RCS LOF setpoint specified in TS
Table 2.2-1.
The licensee instituted a flow penalty methodology for accounting for
the uncertainty in excess of 2.4 percent to ensure that the reactor trip on LOF
occurs at or above the safety analysis limit. These uncertainty calculations were
updated following the installation of the ultrasonic feedwater flow measuring device
to reflect additional uncertainties
based upon vendor specifications on equipment
performance.
The calculation results were incorporated into STP R-26.
-14-
Based on the calculated uncertainties,
the TS minimum setpoint was increased to
90.5~rcent of the minimum measured'flow
on Unit 2 to ensure that TS
requirements
continued to be met.
TS interpretation 96-10 was approved by the
PSRC to establish the LOF setpoint at greater than or equal to 90.5 percent.
Although this was greater than the TS specified limit, the licensee considered it
acceptable
since the limit was more conservative than that specified by TS.
NRC Concerns
Re ardin
the Potential For Unreviewed Safet
Questions
Based upon inspector reviews of the licensee's justification for increasing the RCS
LOF trip setpoint above that specified in TS and the licensee's own internal
concerns regarding the acceptability of having a measured flow uncertainty greater
than the 2.4 percent referenced
in TS, a conference
call was conducted to discuss
the issues.
Participants in the call included licensee personnel, the senior resident
inspector,
NRR project manager,
and technical personnel from NRR.
During the
conference
call questions
were raised which indicated that the change
in measuring
RCS flow at the BOC to EOC potentially involved an unreviewed safety question or
involved a change to TS.
Following the conference
call the licensee decided to reset the instrumentation
by
performing primary calorimetric flow determinations,
for both units, based upon data
taken at the BOC. The Eagle 21 scaling constants
and the plant process computer
and vertical board RCS flow constants
were revised based upon BOC RCS flow
calorimetric results for both units.
Following completion of the calculations, the
PSRC TS interpretation that required adjustment of the LOF trip to 90.5 percent was
rescinded.
C.
Conclusions
The licensee's
change to measuring
RCS flowrate at the EOC that was performed
without a formal safety evaluation is being considered
as an unresolved
item
pending further NRC review of the issue (URI 50-275(323)/96023-04).
E2
Engineering Support of Facilities and Equipment
E2.1
480V Vital Switch ear Fasteners
Ins ection Sco
e 71707
37551
On November 19, during a routine tour of the Unit 2 480V vital switchgear rooms,
the inspectors identified a number of loose fasteners
associated
with the breaker
front panels.
These findings were discussed with the system
ngineer and the
onsite mechanical engineer responsible
for seismic qualification and evaluation of
plant equipment.
The inspectors
also reviewed Procedure AD4.ID8, Revision 1,
"Identification and Resolution of Loose, Missing or Damaged
Fasteners."
-1 5-
b.
Observations
and Findin s
The inspectors identified six breaker cubicles on vital Bus 2F, eight breaker cubicles
on vital Bus 2G, and ten breaker cubicles on vital Bus 2H, each with one loose front
panel fastener.
The system engineer took immediate action to verify the
inspectors'bservations
and tighten all of the fasteners.
The system engineer also performed
a
walkdown of the Unit 1 480V vital switchgear and identified a missing fastener on
one of the breaker cubicles for vital Bus 1G.
The system engineer initiated an
AR (A0417578) to replace the missing fastener on Unit 1. An AR was not initiated
to address the loose fasteners
on Unit 2.
On November 22, the system engineer stated that the licensee's
SQE for the 480V
vital switchgear (SQE-42) did address the front panel fasteners.
Specifically, a note
was included in SQE-42 which stated that one missing fastener on each of the
breaker cubicle front panels was acceptable.
This resolved the inspectors'oncerns
regarding the impact of the loose fasteners
on the seismic qualification of the
switchgear; however, it did not address the identified quality problem.
On December 2, the inspector questioned
the system engineer on the need to
initiate an AR to be able to trend the quality problem with the loose fasteners
on
Unit 2. A review of Procedure AD4.ID8 found that an AR is required to be initiated
when loose, missing, or damaged
fasteners
are identified on safety-related
equipment.
The system engineer initiated an AR (A0418696) documenting this
issue on December 3. The failure of the licensee to initiate an AR to address the
loose fasteners
in Unit 2 until prompted by the inspectors
is a violation of Procedure
AD4.ID8 (VIO 50-323/96023-05).
Conclusions
The licensee took prompt action to correct the identified deficiencies.
However,
follow-on actions to address
the quality problem were considered
weak in that
engineering
failed to recognize the need to document the identified deficiencies for
evaluation and resolution in accordance
with plant procedures.
E8
Miscellaneous Engineering Issues (92700, 92903)
E8.1
Closed
LER 50-275 323 95-07
Revisions 0 and 1: 230kV system may not be
able to meet its design requirements for all conditions due to personnel
error.
The
licensee identified 230kV system design vulnerabilities when assessing
the impact
of routine transmission
line maintenance
on 230kV system operability in June 1995.
Subsequent
licensee investigation of the problem identified 47 separate
occasions
during system maintenance,
between 1990 and 1995, when the voltage on the
230kV offsite power system was degraded
such that during a loss of coolant
accident (LOCA), engineered
safety feature (ESF) loads may have first started on
startup power and may have then shifted to the EDGs.
Of the 47 separate
occasions,
19 were less than 30 minutes duration and 26 were of a duration
-16-
between
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, with 3 occasions with durations of greater than
7249urs~
Double Se
uencin
Followin
Transfer From a De raded Bus
The starting, stopping, and restarting of ESF loads is referred to as "double
sequencing."
That is, the loads would first be supplied by 230kV startup power,
and subsequently,
following the slow transfer of 12kV loads to a degraded
source
of 230kV power, the EDGs would start due to the actuation of the second level 4kV
bus undervoltage
relays.
In turn, this would cause the ESF loads to shed from the
startup bus and resequence
back on to their respective 4kV busses after the busses
had transferred
and were being powered by the EDGs.
The consequence
of this condition is that component cooling water (CCW) flow to
the containment fan cooler units (CFCU) would be interrupted during the initial
stages of the LOCA. In containment,
the steam would continue to flow across the
CFCU cooling coils and transfer heat to the CCW system during the time the CCW
pumps were deenergized.
The continued heat transfer across the CFCU cooling
coils in combination with the delay of the restart of the CCW pumps would cause
the CCW in the CFCU coils to flash to steam.
Following the restart of the CCW
pump the steam void would collapse and cause
a substantial water hammer.
system pressure
would rapidly increase
as a consequence
of the collapse of the
steam void, after the restart of the CCW pump.
Conse
uences
of De raded 230kV Offsite Power Source
After performing an in depth evaluation of the consequences
of the degraded
voltage condition, the licensee determined that the peak CCW system pressure
following the collapse of the steam voids would have exceeded
the ultimate
strength of the CFCU cooling coils and result in failure of the system pressure
boundary.
Following failure of CCW system pressure
boundary the CCW system
would not have been able to perform its design safety function. The licensee noted
that although they were unable to demonstrate
with absolute certainty that the
CCW and CFCU systems would have remained operable when the 230kV system
was degraded,
that they continue to have
a reasonable
expectation that further
resource
intensive efforts could possibly reach the conclusion to the contrary.
Rather than continuing to pursue further evaluation,
PG&E has chosen to declare
that these systems were inoperable.
TS 3.7.3.1 requires that at least two vital CCW loops shall be operable
in Modes 1,
2, 3, and 4.
Contrary to this requirement,
during the time periods when the 230kV
system voltage was degraded,
both loops of the CCW system would not have been
able to perform their intended safety function if a design basis LOCA were to have
occurred.
-1 7-
Miti atin
Factors for Enforcement
The inability of a safety system designed to prevent or mitigate a serious safety
event under certain conditions is a violation that is normally considered
for
escalated
enforcement action.
However, in evaluating this particular situation there
are several factors that require consideration.
The degraded
230kV voltage
condition is a design issue that was in existence for more than 3 years and is not
linked to current licensee performance.
The issue involving the degraded
230kV
offsite power source was licensee identified as a result of the licensee's own
voluntary initiative. The potential for degraded
voltage on the 230kV system has
been reduced by procedural controls in the short term and will be further reduced
in
the long term by the installation of variable tap transformers scheduled
during each
unit's next refueling outage.
The vulnerability for flashing of CCW in the CFCUs
has been eliminated by a design change.
The vulnerability of the CCW system
during time periods of degraded
230kV system voltage would not have been
identified by routine efforts, such as surveillance or QA activities.
Consistent with
the guidance
in Section VII.B.3 of NUREG-1600, "General Statement of Policy and
Procedures
for NRC Enforcement Actions," enforcement discretion will be exercised
and the violation will not be cited (NCV 50-275(323)/96023-06).
E8.2
Closed
LER 50-275 323
96-015
Revision 0: TS 6.5.2.6 not met when cores
reloaded without PSRC review of safety evaluations
due to programmatic
deficiency.
During review of the licensee's Monthly Operating Report, the
inspectors questioned
the date listed for the PSRC review and approval of the
Unit 1.Cycle 8 core reload fuel design and core configuration.
The date listed in the
report was after the date for restart after completion of the refueling outage.
Upon
investigation of the issue, the licensee determined that the PSRC had not reviewed
the safety evaluation performed for Unit 1 Cycle 8 core reload. The core reload
'afety evaluations
are performed for the licensee by Westinghouse.
Further investigation by the licensee determined that the Unit 2 Cycle 8 and Unit
1
Cycle 7 reload safety evaluations
also had n'ot been reviewed by the PSRC.
Following discovery, the PSRC performed reviews of the Units
1 and 2 Cycle 8
safety evaluations
and determined that no unreviewed safety questions existed.
Prior to the Unit 2 sixth refueling outage (2R6) the licensee's practice was to attach
the core reload safety evaluations to design change packages
which required PSRC
review.
Following 2R6, the licensee revised their procedures
to include the safety
evaluations
as a part of a maintenance
modification package.
The licensee's
administrative procedures
governing maintenance
modification procedures
do not
require that they be reviewed by the PSRC.
The licensee has initiated a
nonconformance
report on this problem.
It should be noted that the PSRC did review the core operating limits reports for
Unit 2 Cycles 7 and 8 and Unit
1 Cycle 8 as required by TS 6.9.1.8.
The core
operating limits report is generated
by Westinghouse
and submitted to the licensee
as an attachment to the core reload safety evaluation.
The report documents
the
0
-1 8-
required core operating limits necessary
to ensure
all applicable limits of the safety
anaiy-sis are met."
During separate
and subsequent
review of the safety evaluation for fuel sipping
performed during the Unit 2 seventh refueling outage (2R7), the inspector
questioned
whether the safety evaluation had been reviewed by the PSRC and was
informed by the licensee that it had not.
The safety evaluation for fuel sipping
performed for the licensee by Westinghouse
concluded that there were no
unreviewed safety questions associated.
The PSRC review of the fuel sipping
safety evaluation has been scheduled
by the licensee.
The licensee also identified
that the PSRC failed to review safety evaluations for the UFSAR changes that were
incorporated into Revision 11 of the UFSAR.
TS 6.5.2.6 requires that the PSRC shall be responsible for the review of safety
evaluations for:
(a) changes to procedures
and (b) tests and experiments completed
under the provisions of 10 CFR 50.59, to verify that such actions do not constitute
an unreviewed safety question.
The failure of the PSRC to review safety
evaluations for the Unit
1 Cycles 7 and 8 and Unit 2 Cycle 8 safety evaluations
and
the 2R7 fuel sipping safety evaluation is a violation (VIO 50-275(323)/96023-07).
The corrective actions will be reviewed as a part of the review of the licensee's
response to the violation, therefore, the associated
LER 50-275(323)/96-015
Revision 0 is closed.
Conclusion
The licensee's
administrative controls that incorporate the administrative
requirements of TS 6.5.2.6 were ineffective in ensuring these requirements
were
met.
As a result, required PSRC review of safety evaluations performed under the
provisions of 10 CFR 50.59 were not always performed.
E8.3
Closed
LER 50-275 94006-01:
Centrifugal Charging (CC) pump outside of design
basis due to throttling of CCW to subcomponents.
This event was discussed
in
NRC Inspection Report 50-275/96-20; 50-323/96-20.
The inspection report noted
that, although the CCW flow to CC pump heat exchangers
was sufficient, the flow
was less than that recommended
by the vendor.
During the inspection period, the
inspectors observed the replacement
of the gearbox oil heat exchanger
on
CC Pump 1-1.
Due to a more efficient design, the replacement
heat exchanger was
able to provide the required gearbox oil cooling with approximately
10 gpm CCW
flow to the heat exchanger
versus the 32 gpm CCW flow required for the original
heat exchanger.
Post modification testing by the licensee verified that CCW flow to
each of the CC Pump 1-1 heat exchangers
was restored to the design basis cooling
requirements.
The licensee planned to implement the modification on the other
Unit
1 CC pump, as well as the Unit 2 CC pumps within a few weeks.
-19-
IV. Plant Support
P3
Procedures
and Documentation
P3.1
Licensee Onshift Dose Assessment
Ca abilities
Ins ection Sco
e
Tl 2515 134
Using Temporary Instruction 2515/134, the inspectors gathered information
regarding:
~
Dose assessment
commitments
in the emergency
plan
Onshift dose assessment
emergency
plan implementing procedure
~
Onshift dose assessment
training.
The DCPP Emergency
Plan Revision 3 and the following Einergency Plan
implementing procedures
were reviewed:
EP G-2, Revision 19, "Activation and Operation of the Interim Site
Emergency Organization (Control Room)"
EP R-2, Revision 19A, "Release of Airborne Radioactive Materials Initial
Assessment."
b.
Observations
and Findin s
On December 16, 1996, the inspectors conducted
an in-office review of the
emergency
plan and implementing procedures to obtain the information requested
by the temporary instruction.
The inspectors conducted
a telephone interview with
the licensee on December 18, 1996, to verify the results of the review.
Based on
the documentation
review and licensee interview, the inspectors determined that
the licensee had the capability to perform onshift dose assessments
using real-time
effluent monitor and meteorological data; however, their capability was not clearly
described
in the emergency
plan and implementing procedures.
C.
Conclusion
Although the onshift dose assessment
capability existed, the capability was not
clearly described
in the emergency
plan and implementing procedures.
Further
evaluation of the information obtained using the temporary instruction will be
conducted
by NRC Headquarters
personnel.
-20-
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 December 20, 1996.
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.
ATTACHMENT
SUPPLEMENTAL INFORMATION
Licensee
J. R. Becker, Director, Operations
T. A. Bennett, Director, Outage Services
K. H. Bych, Director, Nuclear Quality Services
S. G. Chestnut,
Senior Engineer, Nuclear Steam Supply Systems Engineering
T. F. Fetterman,
Director, Instrumentation
and Control Engineering
R.
Gray, Director, Radiation Protection
C. R. Groff, Director, Engineering Services
C. D. Harbor, Senior Engineer, Regulatory Services
B. C. Hinds, Shift Supervisor, Operations Services
S. C. Ketelsen, Supervisor,
Nuclear Quality Services
D. B. Miklush, Manager, Engineering Services
M. N. Norem, Director, Mechanical Maintenance
D. H. Oatley, Manager, Maintenance
Services
J. L. Portney, Supervisor,
Engineering Services
R. P. Powers, Manager, Vice President
DCCP and Plant Manager
0
-2-
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance
Observations
IP 71707: Plant Operations
IP 71750: Plant Support
IP 92700: Onsite LER Review
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
TI 2515/134: Licensee Onshift Dose Assessment
Capabilities
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-275(323)/96023-01
50-275(323)/96023-02
50-323/96023-03
50-275 (323)/96023-04
50-323/96023-05
50-275(323)/96023-06
50-275(323)/96023-07
IFI
review of revised DCPP clearance
process
failure to meet maintenance
rule requirements for 4kV
FLURs
failure to follow procedures
for temporary plant
modifications
change of RCS flow determination from BOC to EOC
without formal safety evaluation
failure to document switchboard fastener quality
problem on an action request as required by procedure
degraded
source of 230kV offsite power
PSRC did not review safety evaluations
as required by
TS
Closed
50-275(323)/96-01 5-00
LER
50-275/96-01 7-00
LER
50-275(323)/96-018-00
LER
50-275/96021-05
50-275/94006-01
IFI
LER
50-275(323)/96023-05
50-275(323)/95-07-00,01
LER
degraded
source of 230kV offsite power
230kV system may not be able to meet its design
requirements for all conditions due to personnel
error
TS 6.5.2.6 not met when cores reloaded without PSRC
review of safety evaluations
due to programmatic
deficiency
Automatic reactor trip due to 12kV fault
4kV bus undervoltage
protection relays out of
specification due to setpoint drift due to unknown
cause
RHR pump 1-1 motor hold down bolts torque
documentation
CC pump outside of design basis due to throttling of
CCW to subcomponents
~
~
I
0
-3-
LIST OF ACRONYMS USED
ASW
CFCU
FCT
FLUR
LER
LOF
M5TE
OCT
OTSC
OVID
POA
PSRC
PAID
SFM
SQE
TDF
TS
action request
American Society for Testing and Materials
auxiliary saltwater
beginning of cycle
centrifugal charging
component cooling water
containment fan cooler unit
chemical and volume control system
Diablo Canyon Power Plant
emergency
diesel generator
end of cycle
engineered
safety feature
field correction transmittal
first level undervoltage
relay
licensee event report
loss of coolant accident
loss of flow
maintenance
preventable functional failure
maintenance
and test equipment
OVID change transmittal
on the spot change
operating valve identification diagram
public document room
prompt operability assessment
plant staff review committee
piping and instrumentation
diagram
resistance temperature detector
shift foreman
seismic qualification evaluation
thermal design flow
Technical Specification
Updated Final Safety Analysis Report
work order