ML20034E957
| ML20034E957 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 02/19/1993 |
| From: | Binoy Desai, Harmon P, Martin R, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A740 | List: |
| References | |
| 50-269-93-03, 50-269-93-3, 50-270-93-03, 50-270-93-3, 50-287-93-03, 50-287-93-3, NUDOCS 9303020125 | |
| Download: ML20034E957 (12) | |
See also: IR 05000269/1993003
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UNITED STATES
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NUCLEAR HEGULATORY COMMisslON
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REGloN 11
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.101 MARIETT A STRE ET, N.W.
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ATLANTA, GEORGI A 30373
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Report Nos.:
50-269/93-03, 50-270/93-03 and 50-287/93-03
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.:
50-269, 50-270, 50-287, 72-4
License Nos.:
DPR-38, DPR-47, DPR-55, SNM-2503
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Facility Name: Oconee Nuclear Station
Inspection Conducte : Jan ary 3 - 30, 1993
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Inspector:
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Date' Signed
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n %pector
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g 4 P. E. Harmon, Se 'or Re
pat B. B. De ai, Re -ident/sp
Date Sfgned
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Approved byS
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J+R.E. Martin,ActingSectionChief
Dat'e $igned
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SUMMARY
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Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
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Keowee issues, and inspection of open items.
Results:
Two violations were identified involving failure to follow
procedures.
In the first violation, two separate instances of
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mispositioned fuel assemblies occurred during the' core reload
sequence (Paragraph 2.d).
This violation (with-its two examples)
is similar to a previous violation. The second violation,
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involved two separate examples in which procedures were not
followed by licensed operators (Paragraphs 2.e and 2.f).
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93o3o2o12s 930222
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ADOCK 05000269
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REPORT DETAILS
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1.
Persons Contacted
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Licensee Employees
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- H. Barron, Station Manager
S. Benesole, Safety Review
D. Coyle, Systems Engineering
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- J. Davis, Safety Assurance Manager
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- D. Deatherage, Operations Support Manager
B. Dolan, Manager, Mechanical / Nuclear Engineering (Design)
W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site
D. Hubbard, Component Engineering
0. Kohler, Regulatory Compliance
C. Little, Superintendent, Instrument and Electrical (I&E)
- M. Patrick, Performance Engineer
B. Peele, Engineering Manager
- S. Perry, Regulatory Compliance
G. Rothenberger, Work Control Superintendent
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R. Sweigert, Operations Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
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NRC Resident Inspectors
- P. Harmon
W. Poertner
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- B. Desai
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- 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.
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Control room logs, shift turnover records, 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 performance personnel.
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Activities within the control rooms were monitored on an almost
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daily basis.
Inspections'were condu ted on day and on night
shifts, during weekdays and on weekends. Some inspections were
made during shift change in order to evaluate shift turnover
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performance. Actions observed were conducted as required by the
licensee's Administrative Procedures. The complement of licensed
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personnel on each shift inspected met or exceeded the requirements
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of TS. Operators were responsive to plant annunciator alarms and
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were cognizant of plant conditions with the exceptions noted in
paragraphs 2.e and 2.f.
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Plant tours were taken throughout the reporting period on. a
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routine basis. The areas toured included the following:
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Turbine Building
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Auxiliary Building
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CCW Intake Structure
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Independent Spent Fuel Storage Equipment Rooms
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Units 1, 2 and 3 Electrical Equipment Rooms
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Units 1, 2 and 3 Cable Spreading Rooms
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Units 1, 2 and 3 Penetration Rooms
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Units 1, 2 and 3 Spent Fuel Pool Rooms
Unit 1 Containment
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Station Yard Zone Within the Protected Area
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Standby Shutdown Facility
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Keowee Hydro Station
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During the plant tours, ongoing activities, housekeeping,
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security, equipment status, and radiation control practices were
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observed.
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Within the areas reviewed, licensee activities were generally
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satisfactory with the exceptions noted in paragraphs 2.d,2.e, and
2.f.
Problems in the area of attention to detail by licensed
operators were noted during the events described.
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Plant Status
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Unit I shut down on December 3,1992, for a scheduled End-of-Cycle
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14 Refueling outage. The unit remained shutdown for the entire
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reporting period.
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Unit 2 operated at power the entire reporting period.
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Unit 3 operated at power for most of the reporting period. On
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January 26, the unit experienced a reactor trip from full power.
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The unit was returned to power on January 27.
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c.
Midloop Operations (TI 2515/103)
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The inspectors reviewed the licensee's actions with regard to
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reducing reactor coolant system (RCS) inventory for midloop
operations.
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Unit I entered midloop operating conditions on January 10 for
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nozzle dam removal and on January 20 for repairs on a leaking
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Resistance Temperature Detector (RTD) instrument penetration on
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the 181 Cold Leg. No significant incidents occurred during this
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time.
The licensee's requirements for midloop operations are contained
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in Operating Procedure OP/1/A/1103/ll, Draining and Nitrogen
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Purging of the Reactor Coolant System. The procedure requires
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that the following items be implemented prior to reducing RCS
level below 50 inches as indicated on reactor vessel level
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indicator LT-5:
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Containment closure survey was performed to identify
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containment penetrations that would need to be closed in the
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event of a loss of decay heat removal capability and to
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ensure th,t containment closure can be achieved.
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Two independent RCS temperature indicators and alarms
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LT-5 operable and calibrated.
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Ultra.wnic level instrumentation operable.
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Two low pressure injection pumps operable.
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Both main feeder busses are energized and two sources of
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electrical power are available.
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Two means of adding inventory to the RCS are required.
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A review of maintenance and testing activities to ensure no
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adverse effects on systems and components required for decay
heat removal.
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The inspectors reviewed and witnessed the performance of portions
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of Procedure OP/1/A/1103/11 and verified that the requirements
contained in the controlling procedure were accomplished prior to
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reducing vessel level below 50 inches on LT-5.
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d.
Refueling Operations
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During the Unit 1 refueling operations conducted to reload the
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vessel, two fuel assemblies were _ loaded into the wrong core
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locations. The first misplaced assembly was identified on. January
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1, 1993. During core reload the operators on the refueling bridge
identified that a fuel assembly was already. installed in core
location E-05 during fuel loading activities. 'The' licensee
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determined that Fuel Assembly 6DT had been loaded in. core location
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E-05 instead of its required core location F-05 on December 31,
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1992. The licensee removed fuel assembly 6DT from core location
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E-05 and placed the assembly in core location F-05.
Operating
Procedure OP/1/A/1502/07, Refueling Procedure, required that fuel
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assembly 6DT be placed in core location F-05 during the core
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reload.
The failure to meet the requirements of Procedure
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OP/1/A/1502/07 is identified as example 1 of Violation 269/93-03-
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01: Failure to follow Refueling Procedures.
On January 2,1993, the licensee identified that fuel assembly 4MU
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was located in core location M-13 instead of fuel assembly 5R4.
The licensee determined that fuel assembly SR4 was still located
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in the spent fuel pool. The misplaced assembly was identified
after the core was reloaded, during the core verification process.
The licensee determined that fuel assembly 4MU had been removed
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from the spent fuel pool on December 31, 1992, instead of fuel
assembly SR4, and placed in core location M-13.
Fuel assembly 4MU
was removed from the vessel and returned to the spent fuel pool
and fuel assembly SR4 was inserted in core location M-13 as
required by procedure OP/1/A/1502/07. The failure to meet the
requirements of Procedure OP/1/A/1502/07 is identified as example
2 of Violation 269/93-03-01:
Failure to Follow Refueling
Procedures.
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The licensee has received two violations in the past three years
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for failure to maintain configuration control of fuel assemblies
during refueling operations.
It has been determined that
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escalated enforcement action for this item was not appropriate due
to the low safety consequences of the events.
e.
Unit 3 Reactor Trip
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On January 26, at approximately 10:08 a.m., Unit 3 experienced a
reactor trip from full power when the generated megawatt electric
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(MWe) input to the Integrated Control System (ICS) failed to its
low bias.
The Emergency Feedwater system was actuated by
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Anticipated Transient Without a Scram (ATWS) Accident Mitigation
Systems Actuation Circuitry (AMSAC) on low main feedwater pump
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discharge pressure. The operators manually secured main feeccater
pumps after ensuring adequate emergency feedwater flow.
Abnormal
Procedure AP/3/A/1700/19, Loss of Main Feedwater, was entered
following the reactor trip.
Just prior to the reactor trip, two 1&E technicians were
performing troubleshooting on the transducer associated with the
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power factor meter on Unit 3.
The 1&E technicians determined that
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the transducer was wired incorrectly. Under the allowances of the
work request, the technicians were permitted to perform both
troubleshoot and repair activities. After rewiring the transducer
correctly, the technicians used a hand held multimeter to verify
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that the transducer's voltage output was correct. With the
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multimeter inadvertently selected to amps, the technician
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attempted to measure voltage across the transducer. The
multimeter circuitry induced a high current in two phases, the X
and Y phase on the secondary side of the metering pots.
The high
current caused the fuses in *.he X and Y phases to blow. This
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caused a power loss to the Mwe meter and to the signal that feeds
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the ICS. The Mwe input failed to the low bias of 250 Hwe.
With the demand set for full power and the ICS receiving a signal
indicating 250 Mwe generated power, the main turbine control
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valves went to their full open position. Also the main turbine
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went to manual on mismatch between setpoint and turbine header
pressure. The steam generator pressure decreased, due to opening
of the turbine control valves, causing both the main feedwater
pump discharge pressures to decrease.
This caused main turbine to
trip as well as causing AMSAC to initiate both motor driven
emergency feedwater pumps. The loss of the main turbine caused
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the reactor to trip.
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After verifying adequate emergency feedwater flow to the steam
generators, the operators secured the main feedwater pumps. This
caused the Turbine Driven Emergency Feedwater Pump (TDEFWP) to
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emergency start.
It was later secured by the operator.
Procedure
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AP/3/A/1700/19 was also entered on securing the main feedwater
pumps.
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At approximately 12:00 noon, with the unit still in hot shutdown,
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main feedwater was restored in accordance with Enclosure 6.5 of
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AP/3/A/1700/19.
The emergency feedwater pumps were placed in
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Automatic per step 1.11.
Step 1.12 required several valves to be
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placed in Automatic. Among them were the 3A and 3B SG EFDW
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Control valves 3FDW-315 and 3FDW-316. These valves, which were
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manipulated in Manual during the transient to control emergency
feedwater flow to the SGs, were not placed in Automatic by the
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operators in response to Step 1.12.
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Prior to shift turnover at approximately 6:00 p.m., during a
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normal control panel walkdown, a non-licensed operator discovered
that Valves 3FDW-315 and 3FDW-316 were in the manual position. The
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valves were returned to their automatic position.
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With the two valves in manual, both the emergency flow paths had
been inoperable from approximately 12:29 pm to 6:05 pm.
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requires initiation of immediate corrective to restore at least
one emergency feedwater path to operable status and be in hot
shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and below '250 degrees F in another 12 '
hours.
Due the reactor trip 'at 10:08 am, the unit was already in
a hot shutdown condition.
The failure to meet the requirements of AP/3/A/1700/19, Loss of
Main Feedwater, is identified as example 1 of Violation
269,287/93-03-02: Failure to Follow Procedure.
The inspectors noted that during the use of AP/3/A/1700/19
following the reactor trip as well as during re-establishing main
feedwater, the operators did not " check off" in the space provided
upon completion of steps in the abnormal procedure.
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discussed this practice with plant and training. personnel, who
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indicated that the use of place keeping blanks or " check offe"
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during the use of an abnormal procedure is perceived to be
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optional. The inspectors reviewed Operations Management Procedure
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(OMP) 1-9, 6.2, A.2.c. which states "The E0Ps and APs contain a
single line to the left and adjacent to the step number.
It is
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provided as a place keeping aid and should be checked or initialed
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as completed." The inspector informed the licensee of this aspect
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of the procedure and was assured that the event investigation
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would consider making the use of check offs mandatory as part of
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the corrective action.
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The unit was taken critical at 11:48 p.m. on January 26 and was
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returned to full power at 4:54 p.m. on January 27.
f.
Inadvertent Reactor Protection System (RPS) Actuation on Unit 1
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While Shutdown
On January 29, at approximately 3:36 p.m., an RPS actuation on low
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RCS pressure caused Unit 1 Group 1 rods to trip into the core from
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50 percent withdrawn position. Unit I was already subcritical
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at the time of the trip.
Group 1 rods are kept at 50 percent
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withdrawn position per the procedure to provide a means of
inserting negative reactivity.
Unit I was being cooled and depressurized from hot shutdown
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conditions in accordance with OP/1/A/1102/10, Controlling
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procedure for Unit Shutdown, to repair an 0.8 gpm leak on check
valve ICF-14. Turbine bypass valves had been taken to manual in
accordance with step 2.2.1 to control RCS cooldown rates and an
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operator was assigned to monitor / control the cooldown evolution.
Pressurizer heaters were de-energized and pressurizer spray valve
1RC-1 was manually controlled to depressurize the RCS.
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balance of plant operator (B0P) was assigned the task of de-
pressurizing the RCS by the Control Room SRO. - During this time,
I&E was troubleshooting a rod indication problem on Group 1 Rod 5.
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The BOP operator was asked by the 1&E technician to exercise the
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rod. While exercising the rod, the B0P operator's attention was
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diverted from the depressurizing evolution. With 1RC-1 open, the
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pressure continued to decrease and reached the low pressure trip
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setpoint of 1810 psig.
This caused the RPS to actuate and Group 1
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rods to drop into the core.
In discussing this event with the
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operator following the event, the operator remembered last seeing
the pressure at approximately 1910 psig. With the
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depressurization rate of approximately 30 psig per minute, it is
estimated that the pressure decrease went unnoticed for about 3
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minutes.
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Procedure OP/1/A/1102/10 directs the operator to insert Group 1
rod at an RCS pressure of 1900 to 1850 psig. At an RCS pressure
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of 1810 psig, the RPS would have actuated but no rods would have
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dropped into the core. However, with the B0P operator involved in
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activities associated with the rod indication problem, RCS
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pressure continued to drop until it reached the low pressure trip
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setpoint. The failure to meet the requirements of OP/1/A/1102/10,
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Controlling Procedure for Unit Shutdown, is identified as example
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2 of Violation 259,287/93-03-02: Failure to Follow procedure.
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g.
Letdown Storage Tank (LDST) Outlet Check Valve Failure.
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During the previous inspection period, the inspectors identified
that the licensee had not completed an operability evaluation on
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the failure of the Unit 1 LDST outlet check valve 1HP-97 to close
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during the performance of PT/1/A/251/24, LPI to HP1, BWST Suction,
and HPI to the RCS Check Valve Test.
Check Valve IHP-97 is the
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only valve provided to preclude backflow into the LDST. The
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inspectors identified the review of the operability determination
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as an item that would be reviewed during this monthly resident
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inspection. The licensee completed the past operability
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evaluation on January 20, 1993, and determined that the valve had
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been operable.
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The inspectors reviewed the operability determination and
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questioned the adequacy of the evaluation performed. The
operability determination was based, in part, on the conclusion
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that valve IHP-97 closed during the trouble shooting activities
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conducted after the initial valve failure when LDST outlet
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isolation valve IHP-23 was si:at to isolate the LDST and then -
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reopened. The operability determination stated that opening Valve
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lHP-23 was a better simulation of conditions that the valve would
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see under accident conditions, and exposed the valve to. higher
reverse seating forces. The operability determination concluded
that the higher differential pressure applied to 1HP-97 when lHP-
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23 was opened caused lHP-97 to shut as required, and that the
valve had been operable (capable of shutting against reverse flow)
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all along.
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The inspector had observed the test from the control room. After
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reviewing the evaluation, the inspector determined that the
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Engineering Evaluation was in error. Valve IHP-97 had not closed
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when valve IHP-23 was opened during the second test attempt as
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indicated by the licensee's evaluation.
In fact, level in the -
LDST again increased and operators had to reclosed lHP-23 to stop
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the reverse flow.
Licensee personnel then mechanically agitated -
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valve IHP-97 by beating on it. The test was performed once again.
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using the original alignment which the engineering evaluation
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stated did not apply sufficient differential pressure to cause
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IHP-97_ to seat properly. On the retest lHP-97 seated against the
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backflow. The inspector concluded that not only was the
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engineering evaluation in error regarding the sequence of the
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tests but also in the conclusion that valve IHP-97 failed to seat
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against backflow only because insufficient differential -seating
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force was applied in the first test.
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The inspectors reviewed the Unit I alarm typer printout and the
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LDST level chart recorder. These records confirmed the
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inspector's observations. LDST level increased abruptly twice
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during the time period in question. The first level increase
occurred when ILP-12 was opened in the initir.1 test to pressurize
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the HPI pump suction. The second increase occurred approximately
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30 minutes later and corresponds to the opening of valve IHP-23
during the second test. The engineering personnel who had
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complied the engineering evaluation reviewed the LDST level chart
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and the alarm typer printout and informed the inspector that the
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LDST chart did not show a level increase when valve IHP-23 was
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reopened during the second test. After additional review of the
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chart and the alarm printout and discussing the apparent
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contradictory observations with the engineers, the inspector was
informed by the licensee that the engineers had been reviewing a
chart and alarm printout from Unit 2 instead of Unit 1.
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licensee agreed to perform the engineering evaluation again, using
the appropriate unit information.
Since valve IHP-97 is.the.only
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valve which will actuate to isolate the LDST from the HPI pumps
and the other sources to the pumps (BWST and/or LPI pump discharge
from the RCS or containment ECCS sump) it is essential that the
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valve operates properly during an accident or ESF actuation.
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Pending resolution, this is identified as Unresolved Item 269/93-
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03-03:
Past Operability of Valve IHP-97.
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Within the areas reviewed, two violations were identified.
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3.
Surveillance Testing (61726)
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Surveillance tests were reviewed by the inspectors to verify procedural
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and performance adequacy.. The completed tests reviewed were examined
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for necessary test prerequisites, instructions, acceptance criteria,
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technical content, authorization to begin work, data collection,
independent verification where required, handling of deficiencies noted,
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and review of completed work. The tests witnessed, in whole or in part,
were inspected to determine that approved procedures were available,
test equipment was calibrated, prerequisites were met, tests were
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conducted according to procedure, test results were acceptable and
systems restoration was completed.
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Surveillances reviewed and witnessed in whole or in part:-
PT/1/A/2Sl/24,
LPI to HPI, BWST Suction, and HPI
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to the RCS Check Valve Test
TT/1/A/0711/13,
Unit 1 Zero Power Physics Test
PT/1/A/150/15D
Intersystem LOCA Performance Test
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PT/0/A/610/06
100 KV Power Supply from Lee Steam
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Station Lee
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Within the areas reviewed, licensee activities were satisfactory.
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No violations or deviations were identified.
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4.
Maintenance Activities (62703)
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Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures in use adequately described work
that was not within the skill of the trade. Activities, procedures, and
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work requests were examined to verify, proper authorization to begin
work, provisions for fire, cleanliness, and exposure control, proper
return of equipment to service, and that limiting conditions for
operation were met.
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Several maintenance activities were reviewed and witnessed in whole or
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in part.
These included:
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a.
Core Flood Check Valve Leak
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On January 29, during a tour of the reactor building while Unit 1
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was in hot shutdown, the licensee discovered that RCS Low Pressure
Injection (LPI)/ Core Flood (CF) Inlet Check Valve ICF-14 was
leaking. The RCS leak was estimated to be 0.8 gpm. Valve ICF-14
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is the first valve upstream of the LPI/CF vessel penetration.
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Maintenance had been performed on Valve ICF-14 during the outage
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and the bonnet seal ring had been replaced.
RCS pressure and-
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temperature were reduced to 1000 psig and 400 degrees E to effect
repairs to stop the leak. The leak was stopped by tightening the
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studs. The leak was most likely cause by the bonnet seat ring not
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being seated properly following replacement. The licensee is
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considering enhancing the torquing process to prevent future
similar occurrences.
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b.
Steam Generator (SG) Tube Surveillance
The licensee conducted SG tubing surveillance on Unit 1 pursuant
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to TS 4.17 during the EOC 14 refueling outage.
Each SG has 15531
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tubes. Of.these,152 tubes in A SG and 577 tubes in B SG had
already been plugged. - The results from the initial surveillance
sample of approximately 60 percent of total tubes indicated 124
pluggable tubes on A SG and 456 pluggable tubes on B SG. The
licensee increased the sampling size, eventually to- 100 percent.
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A total of 139-tubes on A SG and 473 tubes on B SG were plugged.
The licensee will issue detailed written reports to the NRC
pursuant to TS 4.17.6.
Within the areas reviewed, licensee activities were satisfactory.
No violations or deviations were' identified.
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5.
Keowee Issues
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During the inspection period the licensee identified that a potential
existed for the Keowee hydro units to overspeed on a load rejection if
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the unit was generating to the grid and an Engineered Safeguards signal
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occurred. The licensee identified this item as a result of an ongoing
Keowee single failure analysis.
Immediate corrective action was to stop
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generating to the grid with the Keowee hydro units.
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The inspectors had questioned the licensee previously concerning the
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ability of the keowee hydro units to withstand a load rejection and were
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told that the overspeed trip was bypassed during an emergency start
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signal. The licensee determined that the normal overspeed trip was
bypassed during an emergency start. However, a backup overspeed trip at
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140 percent of rated speed (180 rpm) in the startup control circuitry is
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not bypassed and this trip signal will trip the shutdown solenoid which
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in turn will send a trip signal to the generator field breakers. The
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generator field breakers contain an anti-pumping circuit that could
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prevent the breakers from reclosing if a trip and close signal was
present at the-same time.
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The licensee determined that this condition was only credible under
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certain high load (88 MW) and lake level (maximum DP) conditions. The
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licensee determined that generating to the grid at power levels less
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than 66 MW would prevent the hydro units from exceeding the 140 percent
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trip setpoint under any lake level conditions.
Prior to allowing the
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Keowee hydro units to generate to the grid the licensee completed the
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Keowee single failure analysis. The inspectors will review the
licensee's long term corrective actions by review of the Licensee Event
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Report (LER) required to be submitted to the NRC pursuant to 10 CFR
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50.73.
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6.
Inspection of Open Items (92700) (92701) (92702)
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The following open item was reviewed using licensee reports, inspection,
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record review, and discussions with licensee personnel, as appropriate:
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(Closed) URI 50-269,270,287/92-30-01: Inadequate HPSW Flow to TDEFW
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Turbine Oil Cooler. The licensee performed special test TT/3/A/0600/10,
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Turbine Driven Emergency feedwater Turbine Oil Temperature Test, to
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determine the temperature increase in the TDEFWP turbine oil system with
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no cooling flow to the turbine oil cooler. The inspector witnessed
portions of the test and reviewed the data collected from the test. The
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test indicated that the turbine oil cooler e'.it temperatures as well as
the bearing temperatures remained within acco.ntable limits.
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9.
Exit Interview
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The inspection scope and findings were summarized on February 2, 1993,
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with those persons indicated in paragraph I above. The inspectors
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described the areas inspected and discussed in detail the inspection
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findings. The licensee did not identify as proprietary any of the
material provided to or reviewed by the inspectors during this
inspection.
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Item Number
Description / Reference Paraaraph
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Vio 50-269/93-03-01
Failure to Follow Procedures (two
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examples). (Paragraph 2.d.)
Vio 50-269,287/93-03-02
Failure to Follow Procedures (two
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examples). (Paragraph 2.e & 2.f.)
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URI 50-269/93-30-03
Past Operability of Valve IHP-97.
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(Paragraph 2.h)
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