IR 05000298/1990033
| ML20217A376 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 11/06/1990 |
| From: | Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20217A373 | List: |
| References | |
| 50-298-90-33, NUDOCS 9011210022 | |
| Download: ML20217A376 (15) | |
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APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-298/90-33 Operating License:
DPR-46 Docket:
50-298 Licensee: Nebraska Public Power District (NPPD)
P.O. Box 499 Columbus, Nebraska 68602-0499 Facility Name: Cooper Nuclear Station (CNS)
Inspection At:
CNS, Nemaha County, Nebraska Inspection Conducted:
September 4 through October 16, 1990 Inspectors:
R. V. Azua, Project Engineer, Project Section C Division of Reactor Projects G. A.- Pick, Resident Inspector, Project Section C Division of Reactor Projects W. R. Bennett, Senior Resident Inspector, Project Section C Division of Reactor Projects
///6/90 Approved:
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'onslable-r-CriTef, Project Section C Date '
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,0 # 01 vision of Reactor Projects Inspection Summary Inspection Conducted September 4 through October 16, 1990 (Report 50-298/90-33)
Areas Inspectedi Routine, unannounced inspection of operational safety verification, monthly-surveillance' and maintenance observations, review of previously identified inspection findings,. onsite followup of written reports, followup of 10 CFR Part 21. reports, and engineered safety feature walkdown.
Results: Within the areas inspected, a noncited violation was identified in paragraph 3 for failure to issue a temporary procedure change as required by administrative guidelines.
Operators properly controlled the reactor during the power increase af ter replacing the brushes on the reactor recirculation motor generator (RRMG) sets (paragraph 3).
9011210022 901107
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PDR ADOCK 05000290
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The licensee appears to be proactive concerning security training and is using
. imaginative = methods to improve security performance (paragraph 3).
Licensee personnel issued a guideline for control of contamination at the instrumentracks~(paragraph 4).
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The licensee continues to be-responsive to inspection findings and events, taking proper corrective actions to prevent recurrence (paragraphs 6, 7, and 8).
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DETAILS 1.
Persons Contacted Principal Licensee Employees
- J. M. Meacham, Division Manager of Nuclear Operations
- S. M. Peterson, Senior Manager of Technical Support Services
- R. L. Gardner, Senior Manager of Operations
- J. V. Sayer, Radiological Manager
- M. E. Unruh, Acting Maintenance Manager
- J. R. Flaherty, Engineering Manager
- R. Brungart, Operations Manager
- R. A. Jansky, Outage and Modifications Manager
"M. A. Gillan, Acting Training Manager
- D. C. Schrader, Acting Operations Supervisor
- S. L. Bray, Operations Quality Assurance (QA) Supervisor
- L. E. Bray, Regulatory Compliance Specialist NRC
- G. L. Constable, Chief, Reactor Projects Section C
- T. R. Reis, Resident Inspector, Fort Calhoun Station The inspectors also interviewed other licensee-employees during the inspection period.
" Denotes those present during exit interview conducted October 11, 1990.
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Plant Status The plant operated at essentially 100 percent power throughout the inspection period. The licensee decreased. power to 280 MWe on
. September 16, 1990, and entered single-loop operations in order to change out brushes on the RRMG sets. The plant was in single-loop operation for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and was returnsi to 100 percent power later that day.
On Septemuer 16 the licensee formally dedicated the CNS plant-specific simulator.
Af er the dedication ceremony, the licensee hosted an open t
house so that trie public could iearn more about CNS.
3.
Operational Safety Verification (71707)
The inspectors observed operational activities throughout the inspection period. Control room activities and conduct were observed to be well controlled.
Proper control room staffing was_ maintained. Based on discussions with the operators, it was determined that they were cognizant of plant status and understood the importance of, and reason for, each lit annunciator.
The inspectors observed selected shift turnover meetings and noted that information concerning plant status and planned evolutions was
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i properly communicated to the oncoming operators. The inspectors verified, l
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daily, by visual inspection of emergency core cooling system valve indications, that the systems were maintained in a standby condition.
On September 16, 1990, the inspector monitored control room activities during the power increase after replacing the RRMG brushes.
The licensed operator withdrew control rods in the order specified on the control rod sequence sheet, and a reactor engineer performed the required independent
verifications. The combination of control rod withdrawals and increased reactor recirculation flow prevented the licensee from entering the instab_ility region designated on the power-to-flow map.
The power increase
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occurred without incident.
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On September 26, 1990, the inspector observed a station operator conduct
reactor water cleanup (RWCU) filter demineralizer backwash and precoat operations in accordance with Radwaste Procedure 2.5.3.4, "RWCU Filter
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Demineralizer," Revision 18, dated April 5,1990. A review of the d
procedure determined it to be easy to follow and understand.
Discussions with the station operator indicated that he was knowledgeable about system-operation.
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During review of the procedure, the inspector observed that Procedure Steps B.I k and B.1.m had words crossed out with other words inserted which cid not alter the intent of the procedure, Review of the temporary procedure change (TPC) log indicated that no TPC existed for
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Procedure 2.5.3.4, Revision 18, as required in CNS Procedure 0.4.2,
" Temporary Procedure Changes," Revision 4, dated February 8,1990. CNS
' Procedure 0.4.2 described the conditions needed to initiate a TPC, which included improvements that did not alter the intent of-the procedure.
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The failure to issue a TPC was in violation of NRC requirements; however, I
no citation will be issued in accordance with Section V.A of the NRC's Enforcement Policy because the licensee's corrective actions were prompt and no previously similar occurrences had been observed.
The-licensee began processing a ermanent procedure change to RP 2.5.3.4, Revision 18,-
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'.e inspectors had informed licensee management of other i
minor problems observed during the inspection period. The division manager of nuclear operations-issued a memo dated October 2, 1990, notifying station personnel of concerns similar to the one identified by j
the inspector, which asked plant personnel to guard against becoming complacent.
On October 10, 1990, the licensee noted increasing temperature on the Residual Heat Removal (RHR) "A" heat exchanger (HX).
During investigation
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of the temperature increase, the licensee determined that leakage was occurring past two pressure regulating valves and a closed manual valve which supply steam to the RHR "A" HX for the steam condensing mode of operation. The licensee vented the HX to a floor drain to attempt to i
reduce inlet temperature, but could not effectively reduce it.
Steam was emitted during the venting process.
Since temperature could not be reduced to allow effective cooling, the licensee declared the containment cooling L-
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subsystein inoperable, which placed them in a 7-day shutdown Limiting Condition for Operation (LCO) in accordance with Technical Specifications (TS).
The licensee cycled and inspected both pressure regulating valves to ensure that they were closing properly.
In addition, the licensee cycled the manusi isolation valve (RHR-36BA) to ensure proper seating of the valve. This was done on two dif ferent occasions.
Each time it was performed, HX temperature remained steady for several hours, then increased slowly. While temperature increases were still being obstied, the licensee vented the HX on an hourly basis to reduce the HX temperat
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Proper health physics (HP) precautions were observed during venting evolutions.
To make repairs to RHR-36BA would require shutting the steam inlet valves to the High Pressure Coolant Injection (HPCI) turbine, causing the HPCI
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system to be inoperable. After much review and discussion, the licensee isolated the HPCI system on October 14, 1990, which placed the plant in a 7-day shutdown LCO.
RHR-368A was inspected on October 15, 1990, and found to have a slight steam cut in the disc, causing it to leak.
Valve repairs were completed and the HPCI was returned to service on October 16, 1990.
The licensee performed all required surveillances prior to voluntarily entering the HPCI LCO. All required actions were performed while in both LCOs.
The LCOs were properly documented and tracked by control room personnel.
The inspectors verified that selected activities of the licensee's
_ radiological protection program were implerented in conformance with
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facility policies, procedures, and regulatory requirements.
Radiation and contaminated areas were properly posted and controlled.
Raciation work permits contained appropriate information to ensure that work could be performed in a safe and controlled manner. HP personnel were observed to be touring work areas ensuring proper implementation of "as low as reasonably achievable" requirements.
Radiation monitors were properly utilized to check for contamination. On September 26, 1990, the inspector observed an HP technician perform the weekly functional check of a personnel contamination monitor (PCM). The PCM responded properly to the source. The PCMs are used to detect the presence of contamination prior to personnel exiting the radiological controlled area and after working in contaminated arcas. The licensee hydrolazed various drain lines in the reactor building to reduce radiat.on levels.
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The inspectors observed security personnel perform their duties of vehicle, personnel, and package search.
Vehicles were properly authorized and control ed or escorted within the protected area (PA).
The inspectors ennducted site tours to ensure that compensatory measures were properly implemented as required.
Personnel access was observed to be controlled in accordance with established procedures. The PA barrier had adequate illumination and the isolation zones were free of transient materials.
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During the CNS open house, the security department stationed an extra security crew as a precautionary measure.
Six guards were assigned duty outside the PA barrier with the rest of the crew inside providing periodic relief.
The public was not allowed access to the PA during the open house.
On September 2h '?90, the inspector observed tee ing of the microwave intrusion detection system. The testing uti19ed a ball to simulate a man jumping or crawling in the transition zone.
The test results were in accordance with the applicable procedure.
On October 4, 1990, the inspector observed security personnel with a video camera inside the PA.
Upon questioning, the inspector was informed that they are considering utilizing videos to assist in training for situatinnel analysis. They are, at present, using videos to tape guards while the; are at the shooting range. The guards' techniques during marksmanship training are then analyzed and corrections made.
The inspectors performed periodic tours of the reactor plant to verify proper system lineups and cleanliness.
The inspectors verified, i
periodically, that electrical lineups were maintained for components needed to mitigate an accident. The inspectors determined that plant housekeephg had been maintained at an excellent level throughout the inspection period.
The inspectors perforred a detailed walkdown of the RHR system.
Results of this walkdown are documented in paragraph 9 of the report.
In June 1990 the inspector identified and documented in NRC Inspection i
Report (IR) 50-298/90-26 the addition of nonstandard door stops to two
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fire doors lccated in the radwaste corridor.
As a result of this deficiency, the licensee initiated a 100 percent reinspection of fire doors to determine whether similar deficiencies exist.
The inspector reviewed " Fire k n ection Engineering Evaluation For Fire Door Modifications and.;ttachments," Revision 0, dated September 13, 1990, I
which documented the inspection of the fire doors and the analysis of the inspection results.
The analysis determined that all fire doors were functional. Several maintenance work requests (MWR) were issued to correct minor deficiencies identified during the inspection.
The licensee initiated comprehensive corrective actions, which were completed in a timely manner.
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In summary, the licensee, as a re: ult of an inspection finding, performed l1 a timely, comprehensive evaluation of fire doors in the plant for I
unanalyzed appurtenances.
Operators properly controlled the reactor during single-loop operation for brush replacement on the RRMG sets. The licensee took conservative actions by adding extra security force personnel during a public open house. The licensee appears to be proactive concerning security training and is using imaginative methods to improve security performance. The licensee performed proper evaluations and conducted required surveillances prior to declaring HPCI inoperable to perform valve repairs. No additional violations or deviations were identified.
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4 Monthly Surveillance Observations (61726)
On September 5, 1990, the inspector observed the performance of Surveillance Procedure (SP) 6.2.2.6.5, "RCIC Turbine Conditional Supervisory Alarm Timer Calibration and Functional / Functional Test,"
Revision 13, dated August 30, 1990. This functional test, required by the TS, verified that the timer operated correctly and provided a permissive signal to the reactor core isolation cooling (RCIC) low flow annunciator.
All prerequisites and limitations were met prior to beginning the SP.
The communications between the instrumentation and controls (I&C) technician coordinating the test and the licensed operator manipulating control panel switches was excellent throughout the test.
On September 12, 1990, the inspector observed the monthly operability test of the RCIC rump conducted in accordance with SP 6.3.6.1, "RCIC Test Mode Surveillance Operation," Revision 25, dated July 26, 1990. This procedure tested the pump flow rate and discharge pressure, verified unit cooler operation, and tested the turbine trip logic as required by TS.
The RCIC pump was tested on an increased inservice test frequency because of high differential pressure.
The licensed operator conducting the test verified all precautions and limitations and properly placed the RCIC pump in service as required by the procedure.
During performance of the test, the control panel indication for the gland seal steam vacuum pump was lost.
The operator immediately informed the senior operator onshift and requested that the problem be investigated.
Electricians found and subsequently replaced a bad undervoltage coil on the vacuum pump motor.
The test was completed satisfactorily except for the gland seal steam vacuum pump, which was not required for the RCIC pump to perform its safety function.
On September 13, 1990, the inspec+cr observed I&C technicians perform a functional test of the automatic depressurization system ( ADS) level switches as required by TS. The technicians conducted thi; test in accordance with SP 6.2.2.2.1, " ADS Water Level Calibration and Functional / Functional Test " Revision 24, dated August 30, 1990.
The level switches provide a permissive for automatic blowdown timer initiation onslow reactor vessel water level.
The qualified I&C technician ensured that the procedure prerequisites and limitations had been met prior to beginning the surveillance.
He used test equipment that was within calibration and followed proper radiological practices.
On September 17 and 18, 1990, the inspectors observed testing of Emergency Diesel Generator (EOG) No.1 in accordance with SP 6.3.12.1, " Diesel Generator Operability Test," Revision 29, dated April 23, 1990.
The operability test verified that the EDG would provide sufficient backup power in the event of a loss of offsite power.
The licensee voluntarily l
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started the EDG utilizing only one starting air bank in service; however, if an actual automatic diesel start signal was received, both air banks would be in service to assist in diesel start.
The test on September 17 was performed as a monthly TS-recuired operability test.
During that test the diesel failed to start within specifications, with only the left air bank in service.
The licensee
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immediately placed the right air bank in service and reperformed the SPs satisfactorily.
Subsequently, the licensee declared EDG No. 1 inoperable to troubleshoot the problem with the left air bank. The problem was determined to be with the lef t-bank shuttle valve which allows air flow from the starting air bank to the air distributor on the diesel.
The shuttle valve was replaced, and the SP performed on September 18 was utilized as a postmaintenance test (PMT) for the troubleshooting and repair activities.
Test results were satisfactory utilizing the left air bank only.
The licensee determined that the shuttle valve was original equipment and failed due to normal wear. Discussions with the system engineer indicated that a preventative maintenance (PM) item was developed to replace the shuttle valves at 5 year intervals.
The licensee ordered additional shuttle valves and is scheduled to replace the other valves during the 1991 Refueling Outage.
On September 24, 1990, the inspector observed I&C technicians perform a TS-required functional test of core spray (CS) and RHR pressure switches in accordance with SP 6.2.2.1.4, "CS and RHR Pump Discharge Permissive Calibration and Functional / Functional Test," Revision 15, dated April 16, 1990. This SP verified that the pump discharge pressure switches provided logic signals to the ADS as designed.
A more experienced technician provided guidance and monitored the activities of a trainee during this test performance. The trainee followed proper radiological practices.
Continuous communications were maintained with personnel in the auxiliary relay room who wero verifying relay actuations.
During performance of the SP, the technicians accidentally jarred the
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pressure gauge on the test pump.
Since the technicians could not quickly locate a-replacement pressure gauge, they stopped the surveillance and checked the calibration of the jarred pressure gauge.
The technicians used a dead weight tester to perform the 6-point calibration check in accordance with a data sheet attached to I&C Procedure (ICP) 14,1.2.1,
"IAC Test Gauge Calibration," Revision 2, dated August 31, 1989. The nressure gauge was found to be within calibration.
Since the technicians considered the gauge internally contaminated, they requested that HP smear the tools and equipment used prior to resuming the test.
On September 25, 1990, the inspector observed I&C technicians perform SP 6.2.2.5.4, "RHR Loops A and B Reactor Vessel Shroud Level Calibration
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i and Functional / Functional Test," Revision 15, dated March 8,1990. This surveillance verified that the reactor vessel shroud level pressure instrument provided a permissive signal to the containment spray valves when the level exceeded the trip point.
A more experienced technician monitored the activities of a trainee while the trainee performed the test.
The test instruments used were within calibration. The trainee properly isolated and returned the instrument to service. The licensee recently changed the policy for control of contamination at instrument racks connected to reactor water. The technicians had received industry events training on the guidelines that implemented the policy. The licensee has attached copies of the guidelines to all test equipment transportation carts to ensure that the guideline requirements are implemented when requireo.
On September 25, 1990, the inspector observed the quarterly inservice test for the RHR pumps conducted in accordance with SP 6.3.5.1, "RHR Test Mode Surveillance Operation,"
Revision 32, dated September 6, 1990. This test verified operability of the RHR pumps, as required by TS, and verified that the pump flow rates, pressures, and vibrations were within specified limits.
The inspectos observed the activities of a qualified station operator and a station i,x rator trainee. The trainee observed the station operator's activities during this test performance.
The vibration measuring test equipment was within calibration.
The station operator followed proper radiological practices, in that he wiped off the transducer after using it in a potentially contaminated area prior to using the transducer at the other locations.
On September 26, 1990, the inspector observed an I&C +.echnician perform a calibration check of a RWCU system differential pressure instrument in accordance with SP 6.2.1.2.1, "PCIS RWCU High Flow Calibration and i;'nctional/ Functional Test," Revision 14, dated April 23, 1990.
This ca.ibration check verified that the primary containment isolation systtm (PCIS) would actuate upon a sensed high flow condition in the RWCU systen as required by TS.
The qualified technician used calibrated test equipment to perform this SP. The technician followed the guideline for performing tests on instrument racks that could be contaminated by reactor water.
In summary, I&C technicians and station operators did an excellent job of transferring information about the tests performed to their trainees during the on-the-job training. A system engineer made a conservative evaluation when he placed the EDG shuttle valves on a 5 year PM for replacement. The licensee recently issued improved guidelines for control of contamination at instrument racks. No violations or deviations were identifie _-
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Monthly Maintenance Observation (62703)
On September 12, 1990, the inspector observed I&C technicians perform PM 02010. The monthly PM implemented ICP 14.3.9, " Seismic Monitoring System Testing," Revision 4, dated Noven.ber 11, 1989, which checked the natural frequency and damping response of the accelerometers.
As part of the test acceptance criteria, I&C shop personnel mailed a magnetic tape containing the test data to the vendor for evaluction.
The technician obtained the test tapes from the warehouse using the correct CNS part number, and he properly removed and returned the seismic monitor to service.
On September 17, 1990, the inspector observed I&C technicians troubleshoot the thermal flow switch for the service water (SW) liquid effluent radiation monitor in accordance with vendor manual instructions.
Discussions with the technicians indicated they were familiar with the i
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flow switch specifications and troubleshooting instructions.
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determined that the flow switch heater had an open.
The PMT consisted of performing the sections of SP 6.3.7.4, "$W Radiation Monitor Instrument Channel Test," Revision 17.. dated April 10, 1990, that verify flow.
No violations or deviations were identified.
6.
Review of Previously Identified items (92701,and 92702)
(Closed) Unresolved Item 298/8710-09:
Design Adequacy of 4160 Vac Electrical System for EDG Testing.
This item was previously reviewed in RRTlR 50-298/89-03 and remained open pending the receipt and review of documentation from the switchgear vendor. The documentation confirmed the adequacy of the switchgear rating for the fault duty identified and I
indicated that a CNS maximum fault condition would not result in damage to the switchgear.
=The inspector reviewed the-design calculation, NEDC 89-2164, " Review of
'GE 4160 Volt Switchgear Fault Capability," that documented the ability of the 4160 Vac switchgear to operate properly without damage to itself or
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surrounding equipment during a maximum fault condition.
The design i
calculation consisted of a tabulation of maximum current values possible with and without the EDG loaded parallel to the grid.
Calculations conducted by the licensee and information contained in the vendor report verified that satisfactory performance of the 4160 Vac breakers and bus bars would occur up to a bus voltage of 4300 volts.
Based on this information, it was determined that if a maximum fault were to occur on one of the 4160 Vac -switchgear buses, the switchgear would operate properly to interrupt the fault.
No damage would occur in the operating switchgear and the redundant division would not be affected.
This unresolved item is closed, i,
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i (Closed) Unresolved Item 298/8710-12: Adequacy of PMT on Safety-Related
Systems. This item was previously reviewed in IR 50-298/89-03 and remained open pending a review of Maintenance Procedure 7.0.5,
"Postmaintenance Testing," Revision 1, dated November 16, 1989, and an evaluation of the effectiveness of the PMT requirements.
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This item was reviewed and evaluated during an NRC-scheduled inspection in September 1990 (NRC IR 50-298/90-31).
The inspectors concluded that PMT controls were sufficiently detailed to ensure that the licensee performed thorough reviews and specified appropriate testing.
The inspector's review of completed MWRs determined that the specified tests were performed, well documented, and reviewed.
This unresolved item is closed.
(Closed) Deviation 298/8925-01:
Inadequate Storage of Training Department QA Records.
In deviation of ANSI N45.2.9-1974, " Requirements for Collection, Storage, and Maintenance of Quality Assurance Records for i
Nuclear Power Plants," the licensee's training department QA records were stored in a room which did not meet the requirements set forth in the standard.
The licensee issued Nuclear Training Department Guideline 117, " Control and Retention of Records," Revision 0, dated December 29, 1989. The procedure required that all training department QA records be microfilmed with two separate se+5 of the microfilm stored in remote locations as specified in ANSI N4b.2.9-1974.
The original records remained in their training center records storage area while the microfilm was being processed at the general office.
The records were maintained in tiiis status until a completed copy of the microfilm was received. The original records were stored.in 1-hour fire rated cabinets protected by a sprinkler system. A training department administrative procedure was revised to require that all cabinets be barred and locked when the records area was unattended.
The inspector reviewed the licensee's actions and the training records storage area and determined that both met the requirements set forth in ANSI N45.2.9-1974. This deviation is closed.
(Closed) Violation 298/8922-01:
Inadequate Design control, This violation identified the licensee's failure to modify procedures and train licensed operators following performance of an on-the-spot change (OSC No.8) to Design Change Package 88-036.
Following a review, the licensee identified three procedures which needed to be. revised as a result of OSC No. 8:
System Operating Procedure (SOP) 2.2.28, "Feedwater System Startup and Shutdown"; Alarm Procedure (AP) 2.3.2.27, " Panel 9-5 - Annunciator 9-5-1"; and AP 2.3.2.28,
" Panel 9-5 - Annunciator 9-5-2."
These revisions were made and approved by plant management on June 20 and July 6, 1989.
Engineering Procedure 3.4.10. " Revisions, Amendments, and On-The-Spot Changes," was revised to include a requirement that ensures that changes to OSCs were incorporated into drawings, calculations, proposed procedure changes, and
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proposed training instructions. The inspector verified that all changes were adequate. Subsequent OSCs were found to be well documented t.0 reviewed in detail with associated changes made to affected G uments and proper training provided on the changes. This violation i' closed, j
(Closed) Violation 298/8907-01:
Failure to Provide a T Oely Response to F
a Notice cf Violation.
The licensee failed to respond to i
Violation 298/8831-01 until February 10,1989(84 days after the issuance of the Notice of Violation).
This violation was due to a personnel error, which delayed the response beyond the required 30-day period.
The responsible individual had set aside the draft of the subject response and permitted other duties to distract him from issuing the response in a timely manner.
The individual was counseled on the importance of meeting the assigned response times related to NRC correspondence.
In addition, a review was conducted to ensure that other correspondence action required by the NRC was not overdue.
It was determined that this isolated case was neither a generic issue nor a programmatic breakdown in the licensee's corrective action tracking systems.
This violation is closed.
(Closed) Open Item 298/8724-02: Discrepancy Between the CNS TS and the Updated Safety Analysis Report (USAR). A discrepancy between the USAR and TS regarding the EDG fuel tanks minimum fill limit was identified. The USAR specified a minimum limit of 45,500 gallons, and the TS specified a minimum limit of 45,000 gallons.
A design calculation, NEDC 87-104A, Revision 7, indicated that minimum fuel limits of 43,686 and 42,900 gallons were required for EDGs No. I and 2, respectively, to power required equipment during a loss of coolant accident (LOCA) with a concurrent loss of offsite power; therefore, the minimum fuel limit of 45,000 gallons, as stated in the TS, was acceptable.
The USAR fuel limit was changed to 45,000 gallons, documented in License Change Request (LCR) 90-0022, and incorporated into Revision 8 of the
USAR, dated July 22, 1990. Both of these documents were reviewed and found to be satisfactory. This open item is closed.
l (Closed) Violations 298/8831-01 and 8933-01; Failure to Track Personnel Training. These violations concerned the failure of the training department to adequately track personnel training, resulting in allowing personnel site access even though they had not completed required training.
L In response to these violations, the licensee committed to implement a
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computerized system for monitoring all personnel training. As a data base L
for this system, all previous training would be verified and entered into l
the training tracking system (TTS).
h Verification of training for site access was completed in Janutry 1990.
The TTS was declared in operation at that time, and a monthly report of personnel whose training had expired or who were within 100 days of
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expiration was issued to cil supervisors.
Since that time all training
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J verification has been completed and monthly reports are issued.
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inspector discussed with licensee personnel the process for verification of previous training and observed how verification was performed and entered into TTS.
No problems were identified.
The inspector verified the records of four personnel and found the reports to be accurate.
No problems have been observed concerning site access since implementation of t
TTS. These violations are closed.
No violations or deviations were identified.
7.
Onsite Followup of Written Reports (92700)
(Closed) LER 90-005 documented that on April 30, 1990, with the plant shut down for the 1990 refueling outage, the reactor protection system (RPS)
Motor. Generator (MG) Set B output breaker tripped.
l The root causes of the event were determined to be an equipment malfunction and a PM program deficiency. The relay contacts in the normally energized CR-120 relay, which monitored the RPS MG set output voltage and tripped the RPS MG set output breaker upon sensing abnormal voltage conditions, were not properly making up. During the investigation conducted by electrical maintenance and engineering personnel, jarring of the RPS MG set control cubicle caused relay actuations and tripped the RPS MG set output breaker, The licensee postulated that the relay contact deficiency caused the initial event.
' As a result of the discovery of the relay contact deficiency, the relays installed in the RPS MG B output voltage monitoring circuit were replaced.
Subsequently, the relays in the RPS MG A control cabinet were inspected and the contacts cleaned.
No deficiencies were noted in contact operation.
The licenste created a PM for inspection and cleaning of the relays in the RPS MG sets. Additionally, the coils for these normally energized relays will be replaced periodically.
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In summary, the inspector's review determined that the licensee had taken timely actions to prevent recurrence of the identified event. No iviolations or deviations were identified.
8.
Followup on 10 CFR Part 21 Reports (92700)
The following 10 CFR Part 21 reports were closed on the basis of the inspector's review of licensee documentation and discussions with personnel:
88-018 Limotorque Corporation - Reduced Starting Torque at Elevated Temperatures in SMB Valve Actuators With RH Insulated DC Motors.
NPPD engineering evaluated the motor-operated valve actuators with RH insulated DC motors and determined that the reactor recirculation discharge valves, RR-M0-53A and RR-M0-53B, would be required to operate at temperatures greater than specified in the Part 21 report.
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Limotorque determined that the subject valve motors were acceptable for operation at 175'F, with a minimum of 200 volts at the motor, using the existing spring pack and torque switch setting. The valve motors were located inside containment and were required to function during a LOCA.
The LOCA temperature profile immediately spikes at 296'F for 10 seconds and gradually decreases to 175'F in approximately 1000 seconds.
Based on a subsequent analysis, the licensee determined that the subject motors were required to operate fur only the first 47 seconds following a design basis accident. The mass of the motors and their sealed configuration prevent the motor winding temperature from exceeding 175'F during this time.
Additionally, the licensee justified an exception from the 1-hour operability requirement in accordance with Regulatory Guide 1.89.
89-015: Cooper Bessemer - KSV Standby Diesel / Generator Pennsylvania Power and Light Unit "B," Crankcase Explosion. A Cooper Bessemer letter cated September 28, 1989, stated "The incident is regarded as unique and, consequently, no further action is contemplated by Cooper-Bessemer." After a thorough review by the licensee, it was determined that this event had no generic impact upon CNS at this time.
The licensee will monitor further developments concerning this issue via participation in Cooper-Bessemer Owner's Group activities.
No violations or deviations were identified.
9.
ESF Walkdown (71710)
The inspector conducted an independent verification of the RHR system status. The inspector compared the valve lineup sheets from SOP 2.2.69A,
" Residual Heat R-ival System Valve Checklist," Revision 5, dated April 18, 1990, the latest controlled drawing. The inspector identified minor discrepanc1es between the valve checklist and the drawing.
Subsequently, the inspector walked down accessible portions of the RHR system, using the same checklist.
During the walkdown, the inspector identified minor discrepancies that included valve labels not agreeing with the valve checklist descriptions, valves with missing labels, and valves with painted labels. The inspector discussr.d these discrepancies with the operations staff. The staff noted the g elems and will turn them over to the contractor responsible for verifying the as-built configuration of the plant. The contractor had not verified the as-built configuration of the RHR system at this time.
The i
Inspector observed that all instruments were valved in and functioning,
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Local flow indication agreed with control room indications.
Power was available to valves as appropriate.
No violations or deviations were identified.
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(30703).
.l 10.
Exit Interviews
.An exit meeting was conducted on October 11, 1990, with licensee
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representatives identified in paragraph 1.
During this interview, the c
inspectors reviewed the scope and findings of the inspection. Other
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meetings between the inspectors and licensee management were held
.periodicallyfduring the inspection period to discuss identified concerns.
The licensee did not identify as proprietary any information provided to, i
t; or reviewed by, the inspectors.
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