ML16154A596
| ML16154A596 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/15/1994 |
| From: | Harmon P, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A595 | List: |
| References | |
| 50-269-94-08, 50-269-94-8, 50-270-94-08, 50-270-94-8, 50-287-94-08, 50-287-94-8, NUDOCS 9405230165 | |
| Download: ML16154A596 (16) | |
See also: IR 05000269/1994008
Text
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REGI
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-08 50-270/94-08 and 50-287/94-08
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.:
50-269, 50-270 and 50-287
and DPR-55
Facility Name: Oconee Units 1, 2 and 3
Inspection Conducted:
bruar 27 - March 26, 1994
Inspectors:
P. E. Harmon, Senior Resid
In ector
D/te Signdd
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G. Humphrey, Resident Inspector
Approved by:
7 §
~
'4i
M. V. Sinkule, Chief,
Ddte 3igned
Reactor Projects Branch 3
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
engineering and technical assistance.
Results:
One violation was identified that involved an inoperable emergency
feedwater pump for a period of time greater than that allowed by
Technical Specifications (paragraph 4.a). A non-cited violation
was documented that resulted from the licensee's reporting of a
potential piping interaction in which the Condenser Circulating
Water discharge vents could be damaged in a seismic event by
buoyancy restraints; thereby, rendering the system inoperable
(paragraph 4.b). A third issue, identified as an Unresolved Item,
related to a lack of documentation for fatigue analysis for the
auxiliary piping connections to the reactor coolant system
(paragraph 4.c).
During this .inspection period, equipment failures resulted in: a
Unit 1 runback to 65 percent power, a Unit 3 plant trip due to a
failed moisture separator reheater level control switch, and a
Unit 3 shutdown because of a steam generator tube leak.
9405230165 940415
PDR ADOCK 05000269
G
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- B. Peele, Station Manager
- M. Bailey, Regulatory Compliance
S. Benesole, Regulatory Compliance Manager
- D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
- B. Dolan, Safety Assurance Manager
W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site
- D. Hubbard, Component Engineering Manager
C. Little, Superintendent, Instrument and Electrical (I&E)
- S. Perry, Regulatory Compliance
- G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
2. Plant Operations (71707)
a.
General
The inspectors reviewed plant operations.throughout the reporting
period to verify conformance with regulatory requirements,
Technical Specifications (TS), and administrative controls.
Control room logs, shift turnover records, the temporary
modification log, and equipment removal and restoration records
were reviewed routinely. Discussions were conducted with plant
operations, maintenance, chemistry, health physics, instrument &
electrical (I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost
daily basis. Inspections were conducted on day and night shifts,
during weekdays and on weekends.
Inspectors attended some shift
changes to evaluate shift turnover performance. Actions observed
were conducted as required by the licensee's Administrative
Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were cognizant of plant
conditions.
Plant tours were taken throughout the reporting period on a
routine basis. During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
practices were observed.
2
b.
Plant Status
At the beginning of the reporting period, Unit 1 was being
restarted following a unit trip that had occurred on February 26,
1994. The generator was placed on-line at 1:37 a.m., on
February 27, 1994. On March 26, 1994, the unit experienced a
runback to 65 percent power due to a loss of the 1A main feedwater
pump (paragraph 2.f).
The unit was returned to full power at
4:10 a.m., on March 27, 1994.
Unit 2 operated at 100 percent power during the reporting period
with no significant problems.
Unit 3 operated at 100 percent power until March 1, 1994, when the
unit tripped on an anticipatory turbine trip/reactor trip
(paragraph 2.c).
The unit returned to power on March 2 and
remained at 100 percent until March 19 when the unit was shutdown
due to a steam generator tube leak (paragraph 2.d).
It was still
shut down at the end of the reporting period.
c.
Unit 3 Trip
At approximately 10:14 a.m. on March 1, 1994, Unit 3 experienced a
reactor trip due to a turbine trip. The turbine trip resulted
from a high moisture separator reheater (MSRH) level signal.
The
invalid high MSRH level signal was the result of shorted contacts
in a corroded mercury switch. The inspectors reviewed the post
trip report and transient monitor traces, and concluded that the
unit's response was normal.
While at hot shutdown the licensee
corrected a problem with a faulty hot leg level transmitter for
train "B" of the Inadequate Core Cooling Monitor (ICCM) which
allowed the unit to exit a 7-day Limiting Condition for Operation
(LCO) associated with TS 3.5.6. The unit returned to power on
March 2, 1994.
d.
Unit 3 Forced Shutdown Due To A Steam Generator Tube Leak
On March 18, 1994, at approximately 11:17 p.m., a high activity
alarm was received on the Unit 3 steam jet air ejector radiation
monitor (RIA-40). Subsequent steam line radiation measurements
and chemistry samples indicated a steam generator tube leak from
the "A" once through steam generator (OTSG).
The count rate on
RIA-40 increased from 1000 cpm to 130,000 cpm (equivalent to a
0.11 gpm tube leak) over a 9 hour1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> period. T.S. 3.1.6.4 states
that when the leakage through any one steam generator equals or
exceeds 0.35 gpm, a reactor shutdown shall be initiated within 4
hours and the reactor shall be in cold shutdown within the next 36
hours. Even though the leakage was below the TS limit, the
licensee began a controlled shutdown on March 19 at approximately
9:30 a.m. The resident inspectors observed portions of the
shutdown. The inspectors noted that the leak rate stabilized and
- 0*
3
began to decrease as the licensee reduced power. All activities
observed during the shutdown were satisfactory.
After shutting down the reactor, the licensee discovered that
there was one leaking tube. This was determined by pressurizing
the secondary side of the "A" OTSG with nitrogen and observing,
via a remotely controlled camera through the upper primary manway,
the location of bubbles exiting the tube(s). The inspectors
observed this test and noted that one tube was leaking. The
leaking tube was at location 92-01 which is on the outer periphery
of the steam generator, just outside the "wedge" area.
Eddy
current testing using Motorized Rotating Pancake Coil (MRPC)
revealed that the leak consisted of a 160 degree circumferential
crack at the upper edge of the fifteenth tube support plate. The
nature and location of the flaw indicated that the failure was due
to flow induced vibration. This tube had been eddy current tested
during the previous outage using a bobbin coil.
That test did not
reveal any flaw indications.
The licensee subsequently conducted extensive eddy current testing
of over 400 tubes in the "A" OTSG. Included were tubes
surrounding the failed tube and tubes around either side of the
wedge and lane area. In addition to the one tube that was
leaking, two tubes (72-15 and 72-17) were found with volumetric
indications and were plugged. Steam generator activities were
completed at the end of the inspection period.
e.
Unit 3 Midloop Operations
Due to the steam generator tube leak discussed above, the licensee
drained down to mid-loop in order to perform MRPC inspections and
to plug tubes as necessary. It was not necessary to install
nozzle dams for this work. A readiness for reduced inventory
inspection was conducted prior to the drain down per NRC policy.
Additionally, the inspectors observed activities in the control
room during portions of the drain down and while at reduced
inventory. The inspection revealed that the licensee met the NRC
expectations for reduced inventory. Specifically:
-
The inspector reviewed the licensee's procedure for reduced
inventory operations. Operations Procedure, OP/3/A/1103/11,
Draining And Nitrogen Purging Of RC System, Enclosure 3.6,
Requirements For Reducing RXV Level To < 50" on LT-5,
stipulated the sequence and steps required for reduction of
RCS inventory and mid-loop operation. It further specified
the precautions and limitations to be adhered to while in
mid-loop. The inspector concluded that the procedure was
adequate.
S-
The inspector noted that containment closure was maintained
while at reduced inventory.
The inspector verified that at least two independent,
continuous temperature indications that were representative
of core exit conditions were available (i.e., both trains of
core exit thermocouples, hot leg temperature, and low
pressure injection (LPI) pump suction temperature were
available).
There were at least two independent, continuous water level
indications available (i.e., both channels of LT-5, and the
hot and cold leg ultrasonic level detectors were available).
Reactor coolant system (RCS) perturbations were avoided.
At least two makeup flow paths were available to maintain.
RCS inventory without assistance from the LPI pumps.
Licensee had contingency plans to repower vital busses from
an alternate source if primary source was lost. All sources
of offsite power, as well as both Keowee units, were
available.
The licensee made a substantial effort to ensure time spent
at reduced inventory was minimized. The time spent at
reduced inventory for this evolution (16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />) was
substantially less than that for past evolutions.
f.
Unit 1 Runback
On March 26, 1994, Unit 1 experienced a runback to 65 percent
power following the loss of the 1A main feedwater (MFW) pump. The
1A MFW pump tripped during the performance of procedure
PT/1/A/290/05, Secondary Systems Performance Test. Plant response
was normal during the runback. The licensee was unable to
determine the exact cause of the MFW pump trip and was unable to
duplicate the event during subsequent testing. The MFW pump was
returned to service and the unit returned to 100 percent power at
4:10 a.m., on March 27, 1994.
Within the areas reviewed, no violations or deviations were identified
and licensee activities were satisfactory.
3.
Maintenance and Surveillance Testing (62703) (61726)
a.
Maintenance Activities
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures adequately described work
that was not within the skill of the craft. Activities,
procedures, and work orders were examined to verify that proper
authorization to begin work was given, provision for fire were
made, cleanliness was maintained, exposure was controlled,
5
equipment was properly returned to service, and limiting
conditions for operation were met.
Maintenance activities reviewed/witnessed in whole or in part:
-
Work Order 94023085, Task 01, Replace Insulators on U3
Busline.
The inspectors observed portions of the work activities
associated with this work order. The effort involved
replacement of the insulators on the Unit 3 main transformer
bus line to the 525 KV switchyard. The activities observed
were accomplished satisfactorily and in accordance with
engineering instructions contained in the work order.
-
Work Order 94023113, Task 01, Replace the Orifice Plates in
the TDEFW Pump Minimum Flow Recirculation Line.
There were two 3/4-inch orifice plates in series downstream
of 3FDW-89 in the minimum flow recirculation line. These
were replaced with 5/8-inch orifice plates of the same
design. This work order was written to implement a Minor
Modification (OE-6464) which was necessary because the
licensee determined that the existing orifice plates allowed
too much flow. The inspectors observed portions of the
orifice replacements and identified no operability issues.
All activities observed were satisfactory.
b.
Surveillance Testing
Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy. The completed tests reviewed
were examined for necessary test prerequisites, instructions,
acceptance criteria, technical content, authorization to begin
work, data collection, independent verification where required,
handling of deficiencies noted, and review of completed work. The
inspectors witnessed the tests in whole or in part, to verify that
approved procedures were available, test equipment was calibrated,
prerequisites were met, tests were conducted according to
procedure, tests results were acceptable and system restoration
was completed.
Surveillances reviewed/witnessed in whole or in part:
-
Performance Test, PT/2/A/0203/06A, Low Pressure Injection
Pump Test-Recirculation.
The inspector reviewed testing of the Unit 2 low pressure
injection (LPI) pumps required by TS. The test, performed
on a quarterly basis, was to demonstrate operability of the
pumps and to identify any problem areas that may exist as
early as possible. It included vibration measurements,
6
monitoring of bearing temperatures, closure of discharge
check valves on the non-running pumps, and pressure/flow
evaluations.
The test was performed with reference to TS, Sections 3.3.2,
3.8.3, 4.0.4, 4.5.1.2.1. and Table 4.1-2. In addition, the
performance standards were to be in accordance with.the
American Society of Mechanical Engineers (ASME),Section XI,
Subsections IWP & IWV, 1980 Edition, Winter 1980 addenda.
The licensee performed a pre-job briefing, entered the
appropriate LCO, and performed the test as described in the
procedure.
Performance Test PT/2/A/0202/11, High Pressure Injection
Pump Test.
The inspectors witnessed the performance of this test
procedure conducted on the 2A High Pressure Injection (HPI)
Pump. The procedure implements the requirements of TS 4.0.4, Inservice Testing (IST).
The procedure verifies that
the pump meets the requirements of ASME Section XI. The
inspectors verified that the procedural acceptance criteria
was met and that the acceptance criteria met the
requirements of ASME Section XI.
No deficiencies were
noted.
Performance Test PT/1/A/0150/22A, Operational Valve Stroke
Test.
The inspectors witnessed the performance of this test
procedure conducted on valves 1HP-27 and 1LP-6. The
procedure implements the requirements of TS 4.0.4. The
inspectors verified that the procedural acceptance criteria
was met. No deficiencies were noted.
Performance Test PT/2/A/0230/15, High Pressure Injection
Motor Cooler Flow Test.
The inspector observed performance of the test which was to
evaluate the cooling water flow rate of the low pressure
service water (LPSW) to the HPI pump motors. The quarterly
performance test demonstrates operability of the pumps as
required by TS 3.3 and 4.5.
Within the areas reviewed, violations or deviations were not identified
and licensee activities were satisfactory.
4.
Engineering (71707)
a.
2A Motor Driven Emergency Feedwater Pump Inoperable Due to DC
Ground
7
During routine rounds on December 29, 1993, a non-licensed
operator discovered water leaking from pressure switch 2PS0386.
The switch, which monitors the discharge pressure of the 2A main
feedwater pump and sends a signal to start the 2A motor driven
emergency feedwater pump on a low discharge pressure of the main
pump, was replaced on December 30, 1993.
Lifting the electrical leads during the switch replacement
resulted in the elimination of a Unit 2 direct current (DC)
electrical ground problem that had been in alarm since
December 14, 1993. The licensee's failure to take aggressive
action to locate and correct the ground on the DC electrical
system resulted in the prolonged condition. Although the licensee
had generated Work Order 93090047, Task 01, the effort expended
was limited to monitoring the voltage on the system as opposed to
locating and correcting the ground. The issue of allowing DC
grounds to exist without performing an extensive effort to find
and eliminate the problem had been identified earlier by the NRC
as a weakness in Inspection Report 50-269,270,287/93-26.
An operability assessment completed on February 8, 1994,
determined that the grounded pressure switch, 2PS-0386, had caused
the 2A motor driven emergency feedwater pump to be inoperable from
December 14 through December 30, 1993. The length of time that
the emergency feedwater pump was considered inoperable exceeded
the seven days allowed by TS 3.4.2.a. Failure to meet the
requirement specified by the TS is identified as Violation
50-270/94-08-02, Inoperability of the 2A Emergency Feedwater Pump.
Since the switch was replaced on December 30, 1993, two additional
failures have occurred which were caused by water intrusion in the
switch. The first occurrence was on January 23, 1994, and the
second was on March 4, 1994. The failures were reviewed by the
inspectors to determine if the corrective actions for the
December 14, 1993, event were appropriate. Because of the,
differences in the two subsequent failures, the inspectors
concluded that the corrective actions for the December 14, 1994,
event were appropriate.
The licensee's report, LER 270/94-01, was submitted to the NRC on
March 10, 1994.
b.
Condenser Circulating Water (CCW) Piping Seismic Interactions
On January 18, 1994, the licensee identified a potential piping
interaction in which the CCW discharge vents could be damaged in a
seismic event by the metal buoyancy restraints placed around the
CCW intake piping to stabilize the lines while the piping is
dewatered. The licensee modified the restraints to prevent the
seismic interaction from occurring. This issue was discussed in
NRC Inspection Report 269,270,287/94-01 and identified as an item
8
to review following completion of the licensee's past operability
evaluation.
The licensee completed the past operability evaluation on
February 17, 1994, and determined that air inleakage due to the
potential seismic interaction would be sufficient to cause a loss
of siphon flow under worst case design bases events (i.e., seismic
event/loss of offsite power).
The actual effect on the systems
would depend on which CCW pumps were operating prior to the event.
The CCW buoyancy restraints were installed in July 1991, October
1992, and June 1992 for Units 1, 2, and 3, respectively.
The failure of the modification package to address the
potential seismic interaction between the restraints and the
CCW vent valves is identified as a violation of TS 6.4.1
(50-269,270,287/94-08-01).
The licensee identified this issue as a result of the problem
identification process that initially identified that four CCW
vent valves per unit were not shown on the CCW flow diagrams. The
licensee reported the potential interaction via LER 269/94-01,
dated March 23, 1994, identifying corrective actions implemented
to correct the potential seismic interaction, as well as
corrective actions planned to prevent recurrence. Accordingly,
this violaiton will not be subject to enforcement action because
the licensee's efforts in identifying and correcting the violation
meet the criteria specified in Section VII.B. of the Enforcement
Policy.
c.
Fatigue Analysis for RCS Auxiliary Piping
During a plant tour to gather information concerning fatigue
analysis documentation at various licensed facilities, members of
the NRC Fatigue Analysis Group discovered an apparent discrepancy
in Oconee's documentation. The Oconee RCS was designed to ASME
B31.7 Class I. In part, this code requires all RCS piping,
including the auxiliary connections, to have supporting analysis
and documentation for formal fatigue analysis. The NRC team
determined that the residual heat removal (RHR) piping connected
to the RCS does not have the required analysis.
The licensee initiated a Problem Investigation Process, PIP 0-94
0347, to address the issue. The licensee does not agree that the
piping in question is required to have fatigue analysis as
required by ASME B31.7. This item is identified as an Unresolved
Item, 50-269,270,287/94-08-03: Fatigue Analysis for RHR, pending
further NRC review to determine if the subject piping requires
fatigue analysis.
In this section, two Violations (one of which is Non-Cited) and one
Unresolved Item was identified.
9
5.
Inspection of Open Items (92701) (92702)
The following open items were reviewed using licensee reports,
inspection record review, and discussions with licensee personnel, as
appropriate:
a.
(Closed) VIO 269,270,287/93-05-01, Inadequate Procedure Governing
Testing of the 100 KV Power Supply From Lee Steam Station.
During the performance of PT/1/A/610/06, 100 KV Power Supply from
Lee Steam Station, both battery chargers SY-1 and SY-S, serving
the 230 KV switchyard 125 VDC system were deenergized for
approximately forty minutes. This resulted in the 230 KV
switchyard battery voltage dropping to 121 VDC as opposed to the
TS limit of 125 VDC. The performance of PT/1/A/610/06 involved a
dead bus transfer which deenergized main feeder bus 1TE. This in
turn resulted in the feeder breaker for the switchyard battery
chargers SY-1 and SY-S being loadshed (battery charger SY-2 is fed
from 2TE but was out of service for this test). The personnel
performing the test failed to recognize that all the battery
chargers would be deenergized. The test procedure was inadequate
in that it did not address the alignment of the switchyard battery
chargers. The inspector verified that the procedure was rewritten
to ensure both in-service battery chargers are powered from a unit
not being tested.
b.
(Closed) VIO 269/93-17-01, LDST Operation Outside of Procedural
Limits.
During performance of OP/1/A/1106/17, Hydrogen System, to add
hydrogen to the Unit 1 letdown storage tank (LDST), the pressure
in the LDST exceeded the requirements contained in procedure
OP/1/A/1104/02, High Pressure Injection System. Exceeding the
requirements of OP/1/A/1104/02 placed the Unit 1 HPI system in a
condition outside of its design basis.
Procedure OP/1,2,3/A/1106/17 was revised to add independent
verification on LDST level prior to hydrogen addition. The
inspectors verified that the procedure had been revised to include
independent verification.
c.
(Closed) VIO 269/93-17-02, Failure to Report High Pressure
Injection Outside its Design Basis.
During performance of OP/1/A/1106/17, Hydrogen System, to add
hydrogen to the Unit 1 letdown storage tank (LDST), the pressure
in the LDST exceeded the requirements contained in procedure
OP/1/A/1104/02, High Pressure Injection System. Exceeding the
requirements of OP/1/A/1104/02 placed the Unit 1 HPI system in a
condition outside of its design basis. The licensee failed to
report this condition as required by 10 CFR 50.72.B.1.ii.b.
10
The licensee deleted a TS interpretation that identified this
condition as not being outside the design basis of the HPI system
and revised procedure OP/1,2,3/A/1104/02 to reflect that operation
outside the LDST pressure/level requirements makes both trains of
the HPI system inoperable. The inspectors verified that above
corrective actions had been accomplished.
6.
Review of Licensee Event Reports (92700)
The below listed Licensee Event Reports (LER) were reviewed to determine
if the information provided met NRC requirements. The determination
included: adequacy of description, compliance with Technical
Specification and regulatory requirements, corrective actions taken,
existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of each event. The
following LERs are closed:
a.
(Closed) LER 269/92-17, Inadequate Seismic Support of Vital
Instrumentation and Control Batteries Due to Unknown Cause,
Possible Installation Deficiency.
The report identified three areas associated with the 125v battery
banks where the installation of the equipment did not agree with
the applicable vendor drawings. The deficiencies involved were:
(1) a vertical support was missing on the 2CB battery rail, (2)
missing splice plates on Units 2 and 3 battery racks, and (3)
battery cells were located above the butt joints on the mounting
racks.
The first two deficiencies were reviewed by the inspectors and
found to be acceptable. The results of that evaluation were
documented in NRC Inspection Report 50-269,270,287/94-01.
The third issue involved battery cells located above the butt
joints of the mounting rails. The vendor manual was revised by the
licensee to allow batteries to be placed above the butt joints on
racks with installed seismic protection. The inspector could not
find the basis for the licensee's revision to the vendor manual
even when considering the addition of the seismic structure.
Accordingly, the inspectors questioned the licensee regarding the
adequacy of their documentation. The licensee subsequently
performed an engineering evaluation and documented the results in
a letter dated March 3, 1994, Subject: Oconee Nuclear Station,
Seismic Behavior of Butt Joint Connection for Exide Battery Racks,
File No. NSD-0183. The evaluation concluded that the placement of
battery cells above the battery rack butt joints was acceptable.
b.
(Closed) LER 269/92-02, Equipment Failure In Emergency Power
System and Inappropriate Action Result In Technical Specification
Violation.
At 9:04 p.m., on January 29, 1992, Unit 1 of the Keowee Hydro
Power System failed when the hydro operator attempted to start the
unit and supply power to the grid. This unit was one of two
generators that can supply electrical power to the grid and serve
as back-up emergency power to the Oconee Nuclear Station. As a
result, the remaining unit (Keowee Unit 2) was started and
operated to supply the needed power to the grid.
The hydro operator inspected the Unit 1 "x" relays because of past
problems associated with them and found none to be out of the
expected position. However, the Unit 1 generator was declared
inoperable from the time that it was last shut down until it was
subsequently restarted at 9:16 p.m., on January 29, 1992.
The licensee investigated the event and determined that the root
causes of the event were: (1) an equipment failure where the
x-relays failed to reset which prevented the generator field
breaker from automatically closing and (2) inappropriate operator
action in that the hydro Unit 2 was not tested by energizing the
standby power bus within one hour as required by TS.
The licensee took corrective actions to counsel both the reactor
operators and the hydro operators on the .importance of
communication between the plants and the need to take immediate
corrective actions at any time when one of the Keowee Hydro units
fails to start. In addition, the mechanical "x" relays were
replaced with an electrical x/y scheme for all Keowee DB breakers
that require automatic closing capability.
The inspector reviewed the documented corrective actions and
determined them acceptable.
c.
(Closed) LER 287/91-07, Equipment Failure Closes Pneumatic Valve
in Condensate Demineralizer System Causing Loss of Feedwater and
Oconee Unit 3 tripped on July 3, 1991, on a loss of feedwater.
The unit was operating at 100 percent power level when a clogged
instrument air line associated with a master valve controller
caused five parallel condensate valves to fail closed. This
resulted in blocking the condensate flow and consequently a main
feedwater pump trip, followed by a reactor trip.
Various other equipment items failed to operate as required during
the trip. As each deficient area was identified, the licensee
took corrective actions to eliminate the condition and to prevent
recurrence. However, a problem was discovered with the system
function and setpoints for actuation of emergency feedwater pumps
in response to loss of low feedwater pressure.- This resulted in
the issuance of LER 269/91-09.
The inspectors reviewed the licensee's resolution for each of the
deficiencies and determined them to be acceptable.
12
d.
(Closed) LER 287/92-01, Inappropriate Action Results in High Steam
Generator Level Causing Loss of Main Feedwater and Reactor Trip.
On January 14, 1992, while operating at 94 percent power, Unit 3
tripped on loss of both main feedwater pumps.
Instrument and
Electrical (I&E) technicians were performing trouble checks on a
suspected faulty controller in the Integrated Control System
feedwater control circuits. The I&E technicians used an
instrument with the test leads configured for current measurement
rather than voltage, causing a false signal to be introduced into
the controller. This increased feedwater flow, resulting in a
high water level in the 3B steam generator which automatically
tripped both main feedwater pumps. The trip of both main
feedwater pumps resulted in an anticipatory reactor trip. The
Licensee determined that the root cause was lack of attention to
detail by the I&E technicians. The I&E technicians were
counselled concerning their inappropriate action in this event.
Additionally, the licensee established a policy to have blank
plugs installed in the current measuring jacks of Fluke 8600
multimeters when issued. The above corrective actions (including
the licensee's root cause evaluation) were reviewed/verified by
the inspector and determined to be adequate.
e.
(Closed) LER 269/92-15, Reactor Trip Results From a Low Main
Feedwater Pump Discharge Pressure Reactor Protective System
Anticipatory Trip Signal Due to a Defective Procedure.
On October 3, 1992, Unit 1 tripped from 7.5 percent power due to a
main feedwater pump (MFDWP) low discharge pressure anticipatory
trip signal.
The trip occurred during an attempt to restore the
1B MFDWP to service following maintenance activities. When the
1B pump suction valve was opened, a momentary discharge pressure
drop occurred on the operating lA main feedwater pump resulting in
the reactor trip signal.
The licensee determined that the
pressure fluctuation was the result of the 1B MFDWP casing not
being pressurized prior to opening the pump suction valve.
This event was discussed in NRC Inspection Report
50-269,270,287/92-24. The inspector verified that the licensee
revised procedure OP/1/A/1106/02, Condensate and Feedwater, to
pressurize the isolated feedwater pump train prior to opening the
suction valve.
f.
(Closed) LER 287/91-08, Excessive Reactor Coolant Leak, Reactor
Trip and Inadvertent Protection System Actuation Result From
Management Deficiency and Equipment Failure
On November 11, 1991, Oconee Unit 3 experienced a RCS leak rate of
approximately 130 gpm through a failed 3/4-inch instrument line on
the RCS hot leg level sensing line. During the unit.shutdown, a
reactor trip occurred at approximately 33 percent power. The trip
was caused by a control loop oscillation which started when
13
operators stopped one of the two feed pumps by procedure. After
responding to the trip, operators continued the cooldown and
depressurization of the RCS. An inadvertent reactor protection
system actuation subsequently occurred when operators deviated
from procedure. Specifically, the shift crew decided to leave the
turbine bypass control station in automatic instead of placing it
in manual per procedure. The crew felt that automatic mode of
control was easier to control than manual for the
cooldown/depressurization in progress. When the Rod Control
System was reset in preparation for withdrawing Shutdown Banks, a
125 psig bias on the steam header pressure was removed
automatically. If the controller had been in Manual, as required
by the procedure, the removal of the bias would not have resulted
in a change in the output of the controller. Since the controller
was in Automatic, the removal of the bias caused the turbine
bypass control to sense that steam header pressure had instantly
increased 125 psig, creating a large pressure error. This caused
the bypass valves to open fully, creating a rapid temperature and
pressure drop. Operators responded by shutting the bypass valves
manually. After the bypass valves shut, temperature and pressure
began increasing, eventually reaching 1710 psig, the shutdown
overpressure trip setpoint. This actuated the RPS, and initiated
a reactor trip.
The cause of the leak was determined to be failure of an
improperly swaged compression fitting. All compression fittings
on the RCS were inspected for similar inadequate compression.
Several additional fittings were found that had not had complete
swaging or compression of the inner ferrule.
NRC Inspection Report 50-269/270/287-91-34 cited a violation for
failure to follow procedures during the cooldown, and a violation
for inadequate procedures used to field fabricate the compression
fittings.
Procedures and training were revised and deficient
fittings were replaced. Operators were counselled regarding their
lack of adherence to procedures during the cooldown. The licensee
determined that a contributing cause of the failure to follow
procedures was a poorly written procedure governing the cooldown.
This procedure was revised. Corrective actions for the violations
and LER were reviewed/verified by the inspector, and determined to
be adequate.
g.
(Closed) LER 269/90-04, Unanticipated System Interaction During
Undervoltage Condition in the 230 KV Switchyard Results in Failure
to Comply With Technical Specifications.
During development of a design basis study of the 230 Kv
switchyard, Design Engineering determined that during certain
degraded voltage conditions in the 230 Kv switchyard, both the 230
S0K
switchyard and the Keowee overhead path could be unavailable to
the Oconee station. Minimum voltage to adequately supply
emergency safeguards loads is 219 Kv, but the protective relaying
14
used to clear and realign the switchyard is 160 Kv. In order for
the overhead path from Keowee to supply the station, the 230 Kv
switchyard must be isolated from the bus section used by the
overhead path. The detection and clearing of the undervoltage
condition (or fault) is accomplished by the External Grid
Protection System. Confirmation that the fault or undervoltage
condition has been cleared and the bus realigned is provided by
the Switchyard Isolate Complete logic circuit. The Switchyard
Isolate Complete circuit then provides the permissive signal to
allow the Keowee overhead path to close in and supply the Startup
Transformers for all three Oconee units. A postulated degraded
voltage below 219 Kv, but above the actuation setpoint of 160 Kv,
would provide inadequate voltage for the safeguards loads and
prevent the Keowee unit from supplying power. If a single failure
of the other Keowee unit or its underground path is assumed, an
Oconee unit undergoing a LOCA would be without emergency power.
Operator action to isolate the switchyard would have to be
performed to restore power.
Immediate corrective actions included development of a procedure
to have operators monitor bus voltages frequently, attempt to
restore voltage if it drops below 225.2 KV, and enter the Action
Statements of TS 3.0 (i.e., correct the condition, or place the
units in hot shutdown conditions within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />).
Subsequent corrective actions included:
(1) A station modification was implemented to automatically
isolate the switchyard when a coincident low bus voltage and
engineered safeguards signal is present.
(2) A TS change was submitted clarifying the requirements and
action for degraded grid conditions.
(3) Operator training was developed which included actions to be
taken during conditions described above.
(4) Revisions to previous plant responses to the NRC Generic
Letter (GL) dated August 8, 1979, titled, Adequacy Of
Distribution System Voltages, would be submitted, as
appropriate. This was necessary since the original response
was not accurate because it had not considered the degraded
voltages described in this LER.
This LER commitment was
later deemed unnecessary by the station staff. Therefore,
an amended response to the GL was not submitted. The
licensee concluded that submission of the TS changes, review
of the proposed switchyard modification by NRC, and
extensive review of the entire area of degraded grid
situations by the NRC Electrical Distribution Safety
15
Functional Inspection (EDSFI) team conducted in 1993, made a
revised response not appropriate.
No violations or deviations were identified.
7.
Exit Interview
The inspection scope and findings were summarized on March 30, 1994,
with those persons indicated .in
paragraph 1 above. The inspectors
described the areas inspected and discussed in detail the inspection
findings addressed in the Summary and listed below. The licensee did
not identify as proprietary any of the material provided to or reviewed
by the inspectors during this inspection.
Item Number
Description/Reference Paragraph
50-269,270,287/94-08-01
Non-Cited Violation:
Inadequate
Modification Package Results in Potential
Seismic Interaction (paragraph 4.b).
50-270/98-08-02
Violation:
Inoperability of 2A Emergency
Feedwater Pump (paragraph 4.a).
50-260,270,287/94-08-03
Unresolved Item:
Fatigue Analysis for RHR
(paragraph 4.c).