ML20056E814
| ML20056E814 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/12/1993 |
| From: | Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20056E807 | List: |
| References | |
| 50-298-93-22, NUDOCS 9308250204 | |
| Download: ML20056E814 (17) | |
See also: IR 05000298/1993022
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APPENDIX B
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Inspection Report: 50-298/93-22 '
Operating License: DPR-46
Licensee: Nebraska Public Power District
P.O. Box 499 l
Columbus, Nebraska 68602-0499
Facility Name: Cooper Nuclear Station i
Inspection At: Brownville, Nebraska j
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Inspection Conducted: June 6 through July 17, 1993 j
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Inspectors: R. Kopriva, Senior Resident Inspector i
a W. Walker, Resident Inspector l
l P. gner, Team Leader, Division of Reactor Safety
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Approved: / ki 9 IF 93 I
{.E.(jgliardo, Chief,ProjectSectionC Date l
. Inspection Summary
Areas Inspected: Routine, announced inspection of onsite response to events, f
operational safety verification, surveillance observation, maintenance '
observation, followup, and onsite review of licens.ee event reports (LERs).
Results:
- The licensee's implementation of its corrective action process was mixed.
Appropriate corrective actions were implemented for a reactor protection
system (RPS) motor generator (MG) trip and erosion in a service water
booster pump case. However, previous corrective actions for a service
water flow discrepancy and to prevent repetition of a service water pipe ;
through-wall leak were not effective. A violation of Appendix B, 10 CFR ,
Part 50, Criterion XVI was identified for the failure to identify and i
correct the condition which resulted in the through-wall leak. The
corrective actions overview group performance did not consistently !
demonstrate a questioning attitude when reviewing service water
deficiencies (Section 2).
- Licensee personnel did not demonstrate the expected level of awareness-
when working around sensitive plant equipment. In addition, potentially
degraded plant conditions were not promptly assessed and protective
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measures established to assure that plant equipment was not adversely l
impacted (Sections 2.5 and 3.2). ]
- Control room activities were generally well conducted; however, )
management expectations were not clearly established for logging of i
switchyard activities (Sections 3.1 and 3.2).- '
- The maintenance and surveillance programs were appropriately implemented. ,
The expected supervisory oversight was provided during the conduct of i
each activity (Sections 4 and 5). ,
- The station service water design modifications were appropriately
documented and required training was provided to the operators-
(Section 6.2).
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Summary of Inspection Findings: l
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- Violation 298/9322-01 was opened (Section 2.2). :
- Inspection Followup Item 298/9322-02 was opened (Section 3.4). I
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- Inspection Followup Item 298/93201-05 was closed (Section 6.1). ]
LER 91-002 was closed (Section 7.1).
LER 91-005 was closed (Section 7.2).
LER 91-006 was closed (Section 7.3).
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LER 91-008 was closed (Section 7.4).
Attachment:
Persons Contacted and Exit Meeting
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DETAILS !
1 PLANT STATUS
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At the beginning of this inspection report period, Cooper Nuclear Station was !
in Day 93 of refueling / maintenance outage that was originally scheduled to be i
56 days in length. As of the end of this report period (July 17, 1993), the ;
plant was in Day 133 of the outage. At-that time the licensee estimated !
startup to occur early in the week'of July 26, 1993. The extension was .
attributed to work required to repair residual heat removal Valves RHR-M0-25A l
and RHR-M0-27A, and the replacement of the reactor vessel head 0-rings that I
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were found not to be properly sealed during the vessel hydrostatic test.
Discovery of pipe thinning and pump casing plug problems in the service water
system had also contributed to the extension of the outage. ;
2 ONSITE RESPONSE TO EVENTS (93702)
2.1 Reactor Protection System Motor-Generator Set Trip
On June 21, 1993, at approximately 8:53 a.m. CDT while the reactor was shut
down for refueling, the plant experienced one out of two isolation signals in
Groups I, II, III, VI, and VII. This resulted in the isolation of shutdown
cooling, reactor water cleanup (RWCU), and secondary containment systems. ;
The isolations resulted from the RPS MG 1B set output breaker tripping. Once }
the cause of the isolations was identified, the operators energized -the RPS l
utilizing the alternate power supply and reset the RPS trip. The operators
then restored shutdown cooling, RWCU, and secondary containment-systems. The ;
systems had been isolated for approximately 7 minutes, and there was' no ,
! indicated change in reactor coolant tempersture. Nonconformance l
Report (NCR)93-140 was initiated and the licensee formed a Problem Resolution i
Team (PRT) to investigate the RPS MG set output breaker trip. A station l
operator, taking voltage readings, had tapped several times on a voltmeter i
attached to the cabinet door of the RPS MG set output breaker, just prior to
the breaker tripping.
The licensee informed the inspectors of the isolations shortly after the- )
output breaker tripped. The inspectors observed the licensee. perform their
initial inspection of the RPS MG set output breaker cabinet and voltmeter.
The licensee inspected the breaker and found no loose wire connections within
the cabinet. They did, however, find a blown fuse in the under-frequency
relay circuit. The licensee's inspection of the under-frequency relay
revealed that two wires for the relay contacts had been pulled slightly out of
their slots, and the contacts were scorched, indicating probable arcing.
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The licensee's electrical mechanics repeated the tests of the relay and
discovered that slight movements of either wire caused the under-frequency
relay to either open its contacts or increase in impedance. Contact opening
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would cause the breaker to trip. Increased impedance due to poor electrical
contact would cause increased current through the circuit.
The licensee concluded that the most probable cause of the event was a ,
combination of an old fuse with decreased ampacity and the sensitivity of the ;
under-frequency relay to actuate if displaced. Intermittent poor electrical ,
contact due to vibration when the operator tapped on the cabinet door likely
resulted in increased impedance and arcing across the relay contacts. ,
Increased current through the fuse could have caused it to fail. l
After the licensee had performed their investigation, the inspectors discussed
the event with the electrical maintenance personnel and reviewed the testing
that had been performed on the under frequency relay. The inspectors observed
a successful breaker actuation test. :
Licensee representatives informed the inspectors that, presently, there were
two electrical protection assemblies in series, which provided protection
against over-voltage, under-voltage and under-frequency. The under-frequency
relay which provided protection for the RPS MG set had been installed prior to :
the addition of the electrical protection assemblies. The inspectors were i
informed that the PRT recommended to station management that the under-
frequency relay trip inside the RPS MG set cabinets be bypassed to prevent
future false trips.
The inspectors reviewed the licensee's corrective actions taken following a
previous RPS Bus B trip on March 31, 1993. The trip was documented in
LER 93-10, Revision 0, " Spurious Trip of Two Reactor Protection System
Electrical Protection Assemblies Due to an Unknown Cause While Shutdown." In
this instance, the fuel had been offloaded from the reactor vessel and the
shutdown cooling system was not in service. The licensee had investigated the :
previous event but did not identify a cause for the RPS trip. Although a
cause for the electrical protection assemblies tripping was not identified,
the inspectors found the licensee's review of the event to be satisfactory. A
review of the licensee's corrective actions to LER 93-10 and the LER
associated with the latest event will be conducted during a followup ,
inspection.
2.2 Service Water Sample Return Line
On July 3, 1993, while performing work urder Maintenance Work Request 93-2620
l to replace two service water valves, the licensee discovered through-wall
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degradation of the 3-inch sample return line. The licensee had initiated j
NCR 93-155 on the date of discovery. The licensee replaced both 3-inch sample
return lines from reactor equipment cooling Heat Exchangers A and B outlet
piping. Approximately 60 feet of 3-inch stainless steel piping was used to
make the repair.
l During review of this event, the inspectors observe,d that a 10-foot section of
i the 3-inch sample return line appeared to have been replaced recently. The
l inspectors questioned the licensee concerning whether other degradation had
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been detected recently on this piping. The licensee informed the inspectors
that on January 13, 1993, a section of 3-inch diameter pipe upstream of the
Service Water Valve 533 had been found to have a through-wall leak. This pipe
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was located in the reactor building, southeast quadrant, next to the control
! rod drive pumps. On May 2, 1993, as authorized by Maintenance Work i
Request.93-0147, a 10-foot section of this pipe was replaced. The inspectors l
noted that the licensee had initiated action to repair the pipe, but had not l
taken measures to identify the cause for the degraded condition and had not i
established corrective actions to preclude its repetition. During a review of 2
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the licensee's actions, it was learned that Maintenance Work Request 93-0147
had been reviewed by the corrective actions program overview group. The ;
overview group, however, had failed to identify a need for corrective action
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(e.g., inspections of other piping) to prevent recurrence of subsequent
failures of the degraded pipe. !
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Appendix B to 10 CFR Part 50, Criterion XVI, " Corrective Actions," states that I
measures shall be established to assure that conditions adverse to quality,
such as deficiencies, deviations, defective material and equipment, and j
nonconformances are promptly identified and corrected. In the case of ;
signficant conditions adverse to quality, the measures shall assure that the !
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cause of the condition is determined and corrective action taken to preclude l
l repetition. Since a loss of the service water system could have an adverse j
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impact on the ability of this system to enable a safe shutdown of the plant, ,
the licensee's failure to determine the cause for the degraded pipe condition i
following the identification of the through-wall leak on January 13, 1993, is !
considered a significant condition adverse to quality. The licensee's failure :
to take corrective action to prevent the second through-wall leak on the same
! sample return line on July 3,1993, was identified by the inspectors as a ,
! violation of Appendix B to 10 CFR Part 50, Criterion XVI (298/9322-01). l
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( 2.3 Service Water Booster Pump 'D' Casino Leak l
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On June 30, 1993, the licensee discovered a leak in the Residual Heat. !
Removal B service water booster Pump 'D' casing. The licensee determined that i
the leak had occurred because of the high velocity flow in the area that i'
contained an unused casing penetration. ' The high velocity flow caused a
swirling action of the service water inside the cavity sealed by the. pipe plug I
which led to erosion inside the cavity, resulting in a leak past the pipe l
plug's threads. The licensee initiated NCR 93-153 to document and evaluate ;
this problem. :
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The licensee replaced the two standard pipe plugs that were exposed to the !
high velocity flows in each of the booster pumps' casings. The remaining
casing penetrations were either being utilized or did not experience the high
flow rates. The licensee also replaced the standard pipe plugs with custom
fitted, elongated plugs. The custom fitted plugs were designed to provide a
solid, close-fit through the depth' of the pump casing, thereby eliminating the
cavity that had existed. The inspectors witnessed portions of the service
water booster Pump D repair effort. The repairs were performed using ;
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instructions contained in Maintenance Work Request 93-2734.
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The inspectors found the licensee's actions to resolve the casing leak problem
to be acceptable. ,
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2.4 Service Water System Flow Rate Calibration Problem
- During the design basis reconstitution effort, the licensee had discovered a
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problem with the flow measuring system used for the high pressure coolant
injection system. The factor used to convert the measured pressure drop
across the flow element to a flow rate was determined to be incorrect. The
licensee documented this problem in NCR 93-071 and LER 93-15. This issue was
discussed in Section 8.3 of NRC Inspection Report 50-298/93-16. In addition
to correcting the identified problem, the licensee initiated an evaluation of
other flow measuring systems. As part of that corrective action, the licensee >
discovered concerns with the service water flow rate measurements.
The licensee was unable to locate calibration curves for the service water
flow elements (SW-FE-387 A&B) for the reactor equipment cooling heat
exchangers. This problem was documented in NCR 93-116. As stated in the root
cause analysis and the associated corrective action statement for this
problem, the licensee had found a discrepancy in 1974 between the above flow
indication system and the system used to verify service water pump flow rate
performance (SW-FE-385 A&B). Until the recent investigation; however, the
discrepancy between the flow measurements had not been resolved.
The licensee evaluated the accuracy of the information used to calibrate the
SW-FE-385 A&B instruments, and obtained updated information from the annubar
manufacturer, including the appropriate calibration constant. The licensee
recalibrated the annubar flow measuring devices and installed a clamp-on
ultrasonic flow measuring system on each of the service water supply loops.
The licensee was then able to establish the proper conversion factor to
recalibrate the SW-FE-387 A&B instruments. A review of the as-found flow
rates was conducted. The licensee determined that the required design basis
flow rates had been maintained. ,
The inspectors determined that the licensee had not aggressively pursued
resolution of this discrepancy which was first identified in 1974; however,
the overall safety significance of this discrepancy was minimal and the latest
corrective action was found to be appropriate.
2.5 Reactor Scram Actuation
On July 8, 19J3, at approximctely 11:42 p.m., with the reactor shut down for
refueling, a full reactor scram signal was received. At the time the scram ,
signal was received, the licensee was performing a reactor vessel hydrostatic :
test in accordance with Surveillance Procedure (SP) 6.3.10.28, "ASME Class 1-N
System Leak Test," and had been controlling reactor pressure at approximately
1031 psig. l
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Concurrent with the performance of SP 6.3.10.28, the licensee was also i
performing Nuclear Performance Procedure 10.9, " Control Rod Scram Time ;
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I Evaluation." The operators noted that the scram signal had been generated by
the high reactor pressure Switches NBI-PS-55C and NBI-PS-550, which actuated
RPS Channels A2 and B2. The operators checked available pressure -
instrumentation and the plant management information system computer to verify '
that a high reactor pressure had not existed, nor had a spurious pressure
spike activated the pressure switches. Pressure Recorder PFC-R-FRPR98
indicated that reactor pressure was at 1023 psig at the time the scram signal
was generated. After confirming that reactor pressure had not reached the
high pressure scram setpoint of 1049 psig, the operators reducea pressure to
950-980 psig to investigate the cause of the scram. i
The licensee did not identify any obvious, direct causes of the scram. A
potential cause was attributed to a ladder that had been secured to the
pressure sensing lines for Instruments NBI-PS-55C and -550. The ladder may
have caused vibration in the sensing lines causing actuation of the switches.
The licensee was still reviewing this event at the end of inspection period.
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When the scram signal was received, Control Rod 26-31 was at Position 26
because of the ongoing scram time evaluation surveillance in progress. This
caused the control rod to scram into the reactor core as designed. The .
licensee completed the initial 10 CFR 50.72 notification within the 4-hour
requirement. The inspectors reviewed the operators actions and the computer
history of the event and concluded that the licensee's assessment of the event
was appropriate.
The inspectors walked down the instrument piping to Pressure Switches NBI-PS-
550 and -550 and located the area where the ladder had been secured to the
instrument piping. The inspectors discussed with licensee management the
controls and expectations that had been disseminated to plant personnel when
working around sensitive instrument piping. The licensee indicated that there
was no established guidance to workers for tasks being performed at or near
sensitive instrument piping.
The inspectors reviewed the licensee's controls for the erection of
scaffolding and ladders around safety-related and potentially energized ;
equipment. Two handbooks on recommended work practices and industrial safety i
were identified which discussed the use of scaffolding and ladders; however,
these handbooks were not approved procedures.
The licensee was continuing its efforts to identify the root cause and '
corrective actions for the event. An LER and NCR 93-161 will be issued to
document the licensee's findings and conclusions. The inspectors will review i
the licensee documentation for closure.
2.6 Conclusions
The licensee's implementation of the corrective action program was mixed.
Previous corrective actions for a service water flow discrepancy, and a
service water pipe through-wall leak were not fully effective. This
contributed to a significant delay in resolving the flow discrepancy, and
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additional service water pipe through-wall leakage. It was noted, however, l
that the resolution of a second RPS MG set trip and service water booster pump !
case leak appropriately utilized the corrective action program. The !
effectiveness of this corrective action overview group was also mixed. This l
group was not effective in assuring the cause for the degraded pipe condition l
was promptly identified and corrected. The failure to determine the cause for j
and correct the degraded service water pipe condition is a violation of :
Appendix B to 10 CFR Part 50, Criterion XVI. l
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A lack of personnel awareness while working around sensitive instrumentation !
appeared to have resulted in a reactor scram with t'e plant in an abnormal l
configuration for a hydrostatic test. Management's expectations and the j
established requirements for securing ladders was not well disseminated to
plant personnel. !
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3 OPERATIONAL SAFETY VERIFICATION (71707) !
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3.1 Control Room Observations
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The inspectors observed shift turnover activities routinely throughout.this
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inspection period and verified that proper control room staffing and control
l room professionalism were maintained. j
l Control room shift supervisor log book and control room balance-of-plant log ;
book entries were reviewed to verify that appropriate entries were made. The !
inspectors discussed the ongoing electrical switchyard activities with the
i shift supervisor and other control room personnel. It was determined that the
appropriate personnel were aware of the electrical switchyard activities. The
control room staff was also found to be cognizant of recent industry events
including a switchyard problem of Fort Calhoun Station. However, it was noted
that management's expectations were not well established for documenting
electrical switchyard activities in the shift supervisor's log book. The _
inspectors found that the shift supervisor's log book entries for ongoing work
in the electrical switchyards was inconsistent and, at times, incomplete. The
inspectors discussed the concerns with documenting switchyard activities in
the shift supervisors' log with licensee management. The licensee indicated-
they would review the log keeping practices.
3.2 Plant Tours
3.2.1 Review of Licensee Actions Due to increasing River level
On July 12 the licensee entered Emergency Procedure 5.1.3, " Flood. This
procedure was used to monitor river level above the 895-foot elevation (mean
- sea level) on an hourly basis. During this inspection period, the river ,
increased to a high level of 897 feet 10 inches. In the event the river level i
reached 899 feet, a Notification of Unusual Event would be declared as l
required by the licensee's emergency plan.
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The licensee placed primary barriers around the diesel room, reactor building,
radwaste building, and turbine building when the river level reached the 897-
foot eleva+. ion. During plant tours, the inspectors noted ground water seepage ;
in the condenser bay and the reactor building southwest quadrant. This
quadrant houses the high pressure coolant injection (HPCI) pump. The water
inleakage was discussed with licensee management. It was determined that the
licensee was cognizant of the ground water inleakage; however, they had not
been proactive in assuring that plant equipment was not adversely impacted. l
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After the inspectors questioned licensee representatives about the impact the
water inleakage had on the continued operability of the HPCI pump, they did
take action to assure the operability of the system. The licensee
subsequently posted a security guard at the southeast area of the plant due to
water intrusion effecting some security equipment.
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3.2.2 Review of Danger Taas
i On July 13 the inspectors noted a danger tag for the pilot scram valve on
Control Rod Drive 38-47 lying on the floor. The tag was brought to the
attention of the health physics technicians to test for potential
contamination. No contamination was noted. The inspectors discussed with the ;
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plant manager the proper control of danger tags and whether this particular
danger tag was still active. The licensee subsequently informed the
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inspectors that the tag had been accidentally dropped earlier in the day and l
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was no longer in effect. The inspectors identified a concern to licensee !
l management that the misplaced tag used to protect personnel safety and control
l equipment status was not identified and resolved by plant personnel in the
immediate area. l
3.3 HPCI Steam Overpressure Protection
On June 10 the inspectors discussed, with the systems engineer, the HPCI
turbine exhaust steam overpressure protectic. system at Cooper Nuclear :
Station. Recently, at the Quad Cities Nuclear Station, during a routine
monthly surveillance of the HPCI turbine, an exhaust steam overpressure
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protection line released high pressure steam directly into the HPCI room,
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injuring several workers. The inspectors reviewed the HPCI system design at
Cooper Nuclear Station using Burns and Roe Drawing 2044 and the system manual
for the HPCI system. The system manual provided information concerning
turbine exhaust overpressure protection, which consists of two rupture discs, ,
mounted in series in the 16-inch exhaust line, and that the rupture discs were i
designed to break at approximately 175 psig as sensed in the exhaust line.
The design of the exhaust steam overpressure protection system at Cooper
Nuclear Station differed from that at Quad Cities Nuclear Station in that
l Cooper Nuclear Station's system exhausts into the torus area outside of the
l HPCI room. This is a large area and there was no equipment in close proximity
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to where the overpressure line would exhaust. The inspectors reviewed with
licensee representatives the possibility of limiting toru's area access during
HPCI turbine surveillances to reduce the possibility of personnel injury, if
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an exhaust steam overpressure were to occur. This consideration was under
review by the licensee at the end of the inspectiori period.
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j 3.4 Drywell Walkdown )
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On July 8 the inspectors performed a walkdown of.the drywell with licensee ;
i management. The inspector's observations of the drywell included the area !
j from upper elevations, where the main steam lines exit the vessel, to below 3
i the vessel where the control rod drives are attached. The walkdown was !
j conducted during the 1000 psig system hydrostatic testing of the reactor ;
vessel. The inspectors noted packing leaks on several valves and some leakage
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under the vessel in the area around the control rod drive flanges. !
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j The walkdown included an observation of the vent piping, vent header, and ;
] downcomer piping, which is between the drywell and the torus. The vent pipes :
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and vent header were observed to be free of debris. The inspectors did find a i
j pencil floating in one of the downcomer pipes, which the licensee removed. !
) During the vent header walkdown, the inspectors questioned licensee '
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{ representatives concerning debris inside the torus to drywell vacuum breakers.
- The licensee indicated that the final drywell' inspection and cleaning was :
. scheduled and would be completed prior to plant startup.
} The inspectors noted that no kaowool or other fibrous type of insulation was
j in the vicinity of the safety valves / safety relief valves. i
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The inspectors questioned licensee representatives concerning the usage of I
black duct tape within the drywell to hold some foam-based insulation around l
the makeup condensate piping. The licensee identified that the use of the i
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black duct tape had been approved for use in the drywell; however, it was
j identified that an evaluation of the potential of this tape loosening and
- falling into the drywell would be conducted. The inspectors will follow up on
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the licensee's action concerning this issue as an inspection followup item
(298/9322-02).
! 3.5 Conclusions
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The licensee's assessment of the differences between the Cooper Nuclear
Station and Quad Cities Nuclear Station steam turbine overpressure protective
. design provided the assurance that the same event would not occur at its
! facility. The licensee's control of switchyard activities was good; however,
i management's expectations were not well established for documenting and
tracking the switchyard activity status in the shift supervisors' log. Plant
personnel did not demonstrate. a heightened awareness' of plant housekeeping
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conditions which could adversely effect equipment status or personnel safety.
1 Compensatory measures for water intrusion into the condenser and the southwest
quadrant, which houses the HPCI pumps, were not established until questioned
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4 SURVEILLANCE OBSERVATIONS (61726)
4.1 Emergency Diesel Generator Monthly Surveillance
On June 18 the inspectors observed portions of Surveillance
Procedure 6.3.12.1, Revision 34, " Diesel Generator Monthly Operability Test."
The inspectors observed a reactor operator manipulate the required controls to
pr operly start Diesel Generator 2. The control room operator adhered to the
procedure and maintained good communications with the system engineer and
auxiliary operator throughout the surveillance.
The surveillance was completed satisfactorily with no anomalies noted. l
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4.2 Reactor Vessel Hydrostatic Test
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On July 7 the licensee commenced the hydrostatic test of the reactor vessel
I and associated systems in accordance with SP 6.3.10.28, "ASME Class 1-N System
Leak Test." The inspectors attended the licensee's planning meeting and
observed preparatory work required for the test. On July 8 the inspectors
toured the primary containment and noted several valves that had packing leaks
and some observed leakage at the control rod drive flanges. The inspectors
discussed these identified leaks with licensee representatives. The licensee
l representatives informed the inspectors that the leaks identified had already
been noted by station personnel and that preparations to correct the problems
were in progress. It was noted that a reactor scram occurred during the
performance of this test as discussed in Section 2.5. At the completion of
the hydrostatic test, the licensee informed the inspectors that they had
indications that the inner seal for the reactor vessel head appeared to be
leaking. The licensee removed the vessel head, replaced the seals and, on
July 15, commenced the hydrostatic test a second time. The test was completed
satisfactorily on July 16.
The inspectors reviewed the records of the completed surveillance. No
discrepancies were identified.
4.3 Conclusions
Both surveillances observed by the inspectors were appropriately conducted.
The diesel generator surveillance was a routine surveillance performed
regularly by the operators, and the hydrostatic test was a surveillange that ,
is performed very infrequently. Both surveillances were given the appropriate '
attention and supervisory oversight.
5 MAINTENANCE OBSERVATIONS (62703)
5.1 Diesel Generator Piston Ring Replacement
On June 9 the inspectors observed maintenance mechanics remove two pistons
from Cylinders "4 Left" and "7 Right" of Diesel Generator 2, under Maintenance
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Work Request 93-2219. The pistons were being removed to determine the ,
condition of the piston rings and to determine if the rings needed to be !
replaced. l
The licensee determined that further inspection was needed after low l
compression ratings had been recorded during the 24-hour postmaintenance i
performance testing. After replacing rings on the two pistons, the diesel i
vendor representative suggested that, as a conservative measure, a power
leakdown test be conducted on the remaining cylinders to determine whether j
other piston rings had also experienced wear and needed to be replaced. ;
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The test was accomplished using a power cylinder leakdown test which involved l
pumping air into each cylinder and recording the pressure in the cylinder
after 30 seconds. The test was used to determine if excess. leakage was l
passing by the piston rings, which would determine whether replacement of.the !
rings was needed. Based on the test results, the licensee decided to replace.
the rings in all of the pistons. ;
In addition to replacing the piston rings, the exhaust and inlet valves and t
seats were replaced on Cylinders "6 Right" and "8 Right". To increase engine
reliability, the licensee had been replacing the 45-degree valves and seats :
with 30-degree valves and seats whenever cylinder maintenance was required. i
This action was recommended by the diesel vendor. All the 45-degree valves
and valve seats had been replaced with 30-degree valves and seats during '
previous maintenance afforts except for those on Cylinders "6 Right" and
"8 Right".
The inspectors reviewed the work packages.used to perform the piston ring and l
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valve replacement, and they appeared to be accurate and complete. The work
activities to remove the pistons, replace the piston rings, remove the valves,
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and lap the valves and valve seats were frequently observed by the inspectors. !
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Appropriate vendor representation and licensee supervision were present during
these activities.
5.2 Repair Work on Residual Heat Removal Injection Valves
From June 20 through July 6, the inspectors observed portions of the :
j maintenance activities associated with the disassembly, repair, reassembly, j
l and testing of Motor-0perated Valves RHR-M0-25A and RHR-M0-27A. These valves ;
are the inboard and outboard injection valves for Loop A of the low pressure !
coolant injection portion of the residual heat removal system. Both of these j
valves had exceeded their allowable leakage during local leak rate testing and -'
had to be repaired. The inboard isolation check valve, located inside the ,
drywell, had passed its local leak rate test and was operable. Valve disc ,
inspection and lapping, and reassembly of Valve RHR-M0-25A were witnessed by !
the inspectors. Cage inspections, seat ring weld inspections, and the l
reassembly of Valve RHR-M0-27A were observed. Upon completion of valve '
reassembly, the licensee again performed the leakage testing with satisfactory
results.
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The associated Maintenance Work Requests (93-2181 for RHR-M0-25A and 93-0292 i
for RHR-M0-27A) had been reviewed and approved as noted by the appropriate ;
signatures. The activities associated with the valve work were found to be !
within the skills of the personnel involved. The inspectors also noted that -!
supervisors and management personnel were routinely present during the various ;
stages of the maintenance activities. !
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5.3 Conclusions ll
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Maintenance management oversight and vendor representation of the diesel !'
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generator work and the motor-operated valve repair activities were effective.
The work appeared to be well organized, and any questionable steps in
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maintenance procedures were discussed with the systems engineers, the vendor !
representative, and maintenance management. An attitude of teamwork and well l
thought out and planned work was evident. j
6 FOLLOWUP (92701) l
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6.1 (Closed) Inspection Followup Item 298/93201-05: Electrical Switchyard !
Walkdowns i
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On June 24 the inspecim observed reinstallation of the emergency transformer .l
and associated switchyard work activities such as worker entry for rigging -l
adjustments and crane operation. The inspector questioned the shift
supervisor concerning Cooper Nuclear Station Directive 52, Revision 2,
" Control of Switchyards and Transformer Yards Activities." The shift ;
supervisor had a copy of Attachment "A" from Directive 52, which provided a >
! work planning form with a description of the work to be performed, vehicles to ;
be used in the yard, number of people in yard, and duration of work. j
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Directive 52 also instructed the work supervisor or lead person to notify the l
l shift supervisor when entering and exiting the switchyard. This notification !
was documented in the Shift Supervisor's Control Room Log as noted by the :
inspectors. It was noted in Section 3.1 of this report that this log was not !
well maintained. The inspectors discussed and reviewed the steps in the i
directive with the work coordinator. The work coordinator briefed the
supervisor overseeing work within the switchyard and the supervisor had the
responsibility of assuring switchyard activities were performed in accordance
with Directive 52 requirements. This included any aerial / crane activities in
the switchyard, control of access of authorized individuals to the switchyard, i
i lockup of the switchyard at the end of the day, and notification of the ;
l control room shift supervisor.
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The inspectors noted during routine tours that the main transformer, startup !
transformer, and emergency transformer switchyards were locked unless work was ;
being performed within the switchyard. The emergency, normal, and startup i
transformer areas were frequently inspected during tours because they were ,
within the protected area. The inspectors also verified that the !
69/161/365 kV switchyards were locked when work was not being performed in the !
switchyard. ;
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On June 29 the inspectors observed two welders inside the emergency
transformer switchyard performing final welding to the holddown supports for
the emergency transformer. The inspectors verified that the welders' presence
in the switchyard had been recorded in the control room shift supervisor's log
book. The inspectors questioned the shift supervisor concerning control af
keys for the transformer areas and the switchyards. The keys for the
transformer areas within the protected area were carried by various
individuals who had a need to work inside the transformer area. The keys to
the 69/161/365 Kv switchyard were strictly controlled and obtained from
station security.
l 6.2 Followup to Service Water System Modifications
The licensee had implemented several changes to the service water system
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during the outage. The most significant changes involved modif. cations of the
i power supplies to motor-operated valves and the removal of gle.J seal water i
for the service water booster pumps.
The inspectors verified that training lesson plans and selected operating ,
procedure changes reflected the system modifications. The inspectors also l
verified that selected control room drawings had been appropriately marked up i
to depict the modifications. Each significant change to a drawing was marked I
up on a separate copy of that drawing. In some cases it was necessary to "
review three or four copies of the same drawing to view all the changes. The
inspectors noted that, with a number of changes to a given drawing, this
practice could cause confusion when the operators attempted to use the i
drawings.
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6.3 Conclusions j
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The licensee's control of personnel and work activities in the station
electrical switchyards was appropriate. Station service water modifications
were appropriately documented and required training was provided to the
operators. The practice of using several copies of the same drawing to
document design changes was found to be potentially difficult to assimilate,
particularly during periods of high activity.
7 ONSITE REVIEW OF LER (92700)
7.1 (Closed) LER 91-002: RWCU Isolation Due to High System Temperature
The 1.censee sutmitted LER 91-002 to document a Group III isolation during
shutdown on Marci 24, 1991. The isolation occurred when backleakage through a l
newly installed cneck valve caused high temperature in the coolant downstream
of the nonregenerative heat exchanger.. Another isolation occurred during full
power operation on May 7, 1991. The licensee determined that the check valve
should have been expected to allow some backleakage under conditions of low
differential pressure. The licensee evaluated several possible corrective
actions but concluded, by memorandum dated November 30, 1992, that hardware
modifications were not cost effective. The licensee implemented procedure
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changes that required additional operator action (and resultant radiation 'l
exposure) to preclude the high temperature condition. The inspectors found -l
that the licensee had adequately considered the radiological impact of not :
modifying the system configuration. ;
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7.2 (Closed) LER 91-005: Unplanned Start of Diesel Generator 2 Due to an :
Eauipment Deficiency !
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This LER documented the unplanned startup of Diesel Generator 2 due to a - l
! deficiency in a breaker auxiliary switch during plant startup while j
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transferring loads from the startup transformer to the normal transformer. !
l The licensee determined that the root cause of the event was an equipment [
! deficiency. Upon closure of 4160V Breaker IBN, an auxiliary switch with
controls in the Bus IB undervoltage circuit did not actuate properly. The l
j licensee's corrective actions included: j
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- Reinstalling the breaker and shimming the 4160V breaker slightly to :
elevate its position in the cubicle, t
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- During the 1993 outage, all essential 4160V breakers were inspected, the ;
I auxiliary switches were cleaned, and the operating arms were checked. ;
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l The licensee plans to incorporate the cleaning and inspecting of these .
auxiliary switches as a part of the preventive maintenance performed on the !
4160V breakers during each outage. The inspectors fornd these corrective ;
activities to be appropriate. j
7.3 (Closed) LER 91-006: 4160V Loss of Voltage Relay -Setpoint Noncompliance !
With incorrectly Stated Technical Specification j
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This item resulted from the licensee's discovery that setting limits
prescribed in the Technical Specifications for the 4160V loss of voltage ;
- relays were determined to incorrectly reflect original design basis l
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l To addrest this issue, the licensee requested a temporary waiver of compliance
j from the NRC since the existing relay settings were withir the plant design :
basis. The licensee also took the following actions: !
- Review and approval of a change to Surveillance Procedure 6.2.2.1.9,
which required specific verification that the relays functioned within ;
the newly prescribed Technical Specification limits.
- Changed the Updated Safety Analysis Report, providing an updated !
description of the operation of the loss of voltage relays and a
description of surveillance testing that was used to verify voltage relay
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The inspectors reviewed documentation of the licensee's corrective actions.
Based on the review performed by the inspectors, it was concluded that
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appropriate actions had been taken. ;
7.4 (Closed) LER 91-008: Failure to Deactivate an Inoperable Containment
Isolation Valve as a Result of Inconsistent Technical Specifications
! The licensee submitted LER 91-008 to describe a problem with ensuring
l containment integrity when an isolation valve was determined to be inoperable
on August 26, 1991. The LER stated that inconsistent and unclear Technical
Specification requirements had contributed to the problem. The licensee
committed to evaluate the need for a change to the Technical Specifications as
a corrective action. The inspectors noted that Change 106 was submitted for
Station Operations Review Committee approval on May 20, 1992. After two
l revisions, the proposed change was approved on March 18, 1993. The inspectors
were informed that the proposed change was presently being reviewed by the
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Safety Review Board. Licensee representatives expected to submit the proposed
change for NRC approval in August 1993.
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ATTACHMENT
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1 PERSONS CONTACTED
L. E. Bray, Regulatory Compliance Specialist
R. Brungardt, Operations Manager
M. A. Dean, Nuclear Licensing and Safety Supervisor
J. W. Dutton, Training Manager
J. R. Flaherty, Engineering Manager
R. L. Gardner, Plant Manager
M. D. Hamm, Security Supervisor
R. A. Jansky, Outage and Modifications Manager
E. M. Mace, Senior Manager Site Support
J. M. Meacham, Site Manager
D. R. Overbeck, Acting Site Services Manager
S. M. Peterson, Senior Manager of Operations
J. V. Sayer, Radiological Manager
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J. T. Scheuerman, Acting Technical Staff Manager
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G. E. Smith, Quality Assurance Manager
! R. L. Wenzl, Nuclear Engineering Department Site Manager ;
M. F. Young, Maintenance Supervisor '
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The licensee personnel listed above attended the exit meeting. In addition to
l the personnel listed above, the inspectors contacted other personnel during
this inspection period.
2 EXIT MEETING
An exit meeting was conducted on July 16, 1993. During this meeting, the
inspectors reviewed the scope and findings of this report. The licensee did
not identify as proprietary any information provided to, or reviewed by, the
inspectors.
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