IR 05000269/1993026
| ML16148A848 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 11/10/1993 |
| From: | Harmon P, Leslser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A846 | List: |
| References | |
| 50-269-93-26, 50-270-93-26, 50-287-93-26, NUDOCS 9312140084 | |
| Download: ML16148A848 (10) | |
Text
ega REGo4 UNITED STATES o0 NUCLEAR REGULATORY COMMISSION
REGION II
<0 101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 Report Nos.:
50-269/93-26, 50-270/93-26 and 50-287/93-26 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 Facility Name: Oconee Nuclear Station Inspection Conducted: September
- October 23, 1993 Inspector: //
/t LP. E. Hirmon, Seni Re *dent spector Date Signed W. K. Poertner, Resident Inspector L. A. ller, Resident Inspector Approved by:
H1//1 /f M. S. Lesser, Section Chief, Date Signed Reactor Projects Section 3A Division of Reactor Projects SUMMARY Scope:
This routine, resident inspection was conducted in the areas of plant operations, surveillance testing, maintenance activities, Keowee issues, independent safety engineering group functions, licensee evaluations of changes to the environs around licensed reactor facilities, inspection of open items, and review of licensee event report Results:
One Unresolved Item (URI) was identified. The URI involved the completion of a past operability evaluation for the Unit 1, 2,and 3 load shed channels with respect to a single failure potential identified during the reporting period by the licensee (paragraph 2.c)
A weakness was identified in the licensee program to identify and correct grounds on the safety related DC busses (paragraph 4.c).
Another weakness was identified in the surveillance test procedure for verifying the correct voltage and frequency of the Keowee generator voltage and frequency/rpm. The test procedure did not provide appropriate acceptance criteria. (paragraph 3)
9312140084 931110 PDR ADOCK 05000269
REPORT DETAILS Persons Contacted Licensee Employees
- H. Barron, Station Manager S. Benesole, Safety Review Manager D. Coyle, Systems Engineering Manager
- J. Davis, Safety Assurance Manager T. Coutu, Operations Support Manager B. Dolan, Manager, Mechanical/Nuclear Engineering W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site D. Hubbard, Component Engineering Manager C. Little, Superintendent, Instrument and Electrical (I&E)
- M. Patrick, Regulatory Compliance Manager B. Peele, Engineering Manager
- S. Perry, Regulatory Compliance
- G. Rothenberger, Operations Superintendent R. Sweigart, Work Control Superintendent Other licensee employees contacted included technicians, operators, mechanics, security force members, and staff engineer NRC Resident Inspectors
- P. Harmon
- W. Poertner
- L. Keller
- Attended exit intervie.
Plant Operations (71707) General The inspectors reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative control 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 engineering personne Activities within the control rooms were monitored on an almost daily basi Inspections were conducted on day and night shifts, during weekdays and on weekends. Inspectors attended some shift changes to evaluate shift turnover performance. Actions observed were conducted as required by the licensee's Administrative Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of T Operators were responsive to plant annunciator alarms and were cognizant of plant condition Plant tours were taken throughout the reporting period on a routine basis. During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observe Plant Status Unit 1 operated at power the entire reporting perio Unit 2 operated at power the entire reporting period. On October 23 a power reduction to 25 percent power was commenced to repair a pipe leak in the heater drain system. The leak was repaired and the Unit was returned to full power on October 2 Unit 3 operated at power the entire reporting perio Load Shed System Not Single Failure Proof NRC Inspection Report No. 269,270,287/93-24 documented that during a modification, the load shed channel 1 relay for switchgear 3TD was wired incorrectly resulting in the channel being inoperable from March 1987 to August 1993. As part of the review for the Licensee Event Report (LER) required due to this inoperable load shed channel, the licensee discovered on October 12, 1993, that the TD switchgear load shed channels for all three units were not single failure proof. This discovery placed all three units in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO per TS 3.7. Channel 1 of load shed is powered from 125 Vdc panel board DIA, but one set of relay contacts required to actuate channel 1 load shed was from a relay (RSL2X) powered from DIB. Additionally, channel 2 of load shed is powered from DIB, but one set of contacts required to actuate channel 2 load shed was from a relay (RSL1X) powered from DIA. This problem only existed for bus T Therefore, any single failure that would deenergize DIA or DIB, would defeat both load shed channels for the TD switchgear. This condition had existed since plant constructio As of the end of this inspection period, the licensee was still evaluating whether this issue is reportable under 10 CFR 50.72 b.2.iii. The intent of the licensee's evaluation is to determine the effects of a design basis accident coincident with a failure of load shedding on the TD switchgear on one uni The licensee was able to resolve the problem by modifying the wiring on relays RSL1X and RSL2X such that all the contacts for these relays were in the appropriate string of load shedding circuitry. The inspectors reviewed the modification package
(Minor Mod OE-6247), observed portions of the work in the field, and observed portions of the post modification testing. All activities observed were satisfactor The inspectors will complete their evaluation of this issue after reviewing the licensee's evaluation discussed above. This matter is identified as Unresolved Item 269/93-26-01, Load Shed System Not Single Failure Proo DIC Inverter Failure At 12:54 a.m. on September 28, numerous statalarms were received in the Unit 3 control room. The statalarms received included Reactor Protection System Channel C Trip, DC Breakers CB-1 and CB 2 Trip, and Inverter 3DIC Troubl Investigation determined that power fuses in inverter 3DIC had blown resulting in a loss of power to panelboard 3KVIC. Loss of panelboard 3KVIC placed the Unit in a 24 Hour LCO. At 2:50 a.m. panelboard 3KVIC was powered from an AC line placing the Unit in a 7 day LCO per Technical Specification 3.7.2.h. I&E personnel investigated the blown fuse and could not identify the cause of the blown fuse. The fuse was replaced at 5:23 a.m. and the inverter was returned to servic At 6:40 a.m. the power fuse for inverter 3DIC blew again. The licensee repowered panelboard 3KVIC from an AC line and commenced troubleshooting activities to identify the cause of the failur Licensee troubleshooting activities continued until October 2 without identifying a specific cause for the failure. The licensee replaced several components inside the inverter in an attempt to correct the problem and returned the inverter to service at 10:25 a.m. At 3:04 p.m. on October 2, inverter 3DIC again tripped due to the power fuse blowing and panelboard 3KVIC was provided powered from an AC line. The licensee decided to swap the internals of inverter 3KX with inverter 3DIC. The decision to swap components was based on a lack of spare parts and the lack of an available spare inverter. The 3DIC inverter internals were replaced and the inverter was returned to service on October 4. The inverter operated properly throughout the remainder of the reporting perio The licensee has identified the inverters on all three units for replacement. Each unit contains 7 inverters. The present schedule for implementation commences at the next Unit 1 refueling outage presently scheduled for June 1994. The inverters on Units 2 and 3 will be replaced in the subsequent refueling outages following the Unit 1 outag Unit 1 Power Reduction to Repair Heater Drain Piping At 1:26 a.m. on October 23, Unit 1 commenced a power reduction to 25 percent power to repair a steam leak in the heater drain system that developed in a 90 degree elbow downstream of valve 1HD-6 This line is a low pressure line with a design pressure of 150 psig. The power reduction was completed at 4:56 a.m. and the licensee commenced to isolate the 1A2, 1B2, 1CI, and 1C2 feedwater heaters to isolate the steam leak. The cause of the piping failure was erosion. A patch was welded on the piping elbow to repair the elbow. The feedwater heaters were returned to service and a power increase was commenced at 4:00 p.m. The Unit was returned to 100 percent power at 3:32 a.m. on October 2 No violations or deviations were identifie.
Surveillance Testing (61726)
PT/O/A/620/09, Keowee Hydro Operatio This surveillance provides a monthly test of the Keowee Hydro Units from the Oconee control room per Technical Specification 4.6.1. During the test of Keowee Unit 2, the inspector noted slow frequency swings between 59.6 and 60.2 hertz. The control room operators felt that the frequency swings were norma The inspector noted that there were no acceptance criteria within the procedure for voltage or frequency/generator rpm, nor were the values of these parameters documented for subsequent review. The inspector noted that the only Keowee surveillance test that mentions correct generator voltage and frequency is the annual emergency start test (PT/0/A/0620/16), which records the time it takes for the unit to reach a rated speed and voltage of "approximately" 128.6 rpm and 13.8 kV respectively. The licensee indicated during the exit interview that appropriate acceptance criteria for voltage and frequency would be included for future monthly surveillance test Technical Specifications for Oconee do not require verifying correct voltage and frequency. The licensee's surveillance program should have included verification of parameters as important as the voltage and frequency of the emergency power source. The inspector concluded that the lack of specific quantitative acceptance criteria for Keowee generator voltage and frequency/rpm, represented a weakness in the licensee's surveillance progra No violations or deviations were identifie.
Maintenance Activities (62703) TN/1,2,3/A/6246/00, Modification of Load Shed Relays DLS1 and DLS2 in 1,2,3T This modification rewired the power supplies to load shed relays DLS1'and DLS2 to correct a potential single failure vulnerability that could have prevented switchgear TD from load shedding under accident conditions. The inspectors reviewed the modification package, monitored work activities in progress, and observed the post modification testing performed to verify proper operation of
the load shed relays. The inspectors did not identify any problems during the performance of this work activit Leak Sealant Practices During the inspection period the inspectors reviewed the licensee's program for controlling leak repair activities using temporary leak sealant. The licensee uses three primary vendors to perform leak repairs; Utilities Support Specialist Incorporated (USSI); Preventive Maintenance Incorporated (PMI); and Leak Repair Incorporated. All leak repair activities are accomplished by the exempt change process. Leak sealant is used on both safety related and non-safety related components. The inspectors determined that the licensee does not allow leak sealant to be used on pipe leaks. Licensee procedures are used to document and control leak repair activities ; however, vendor procedures are used to perform the actual leak repair. The licensee procedure for leak repair activities specifies the type and amount of sealant to be injected. The licensee policy on length of use is that a work request is initiated to repair the component at the next available opportunity. The inspectors noted that the licensee does not have a mechanism available to readily identify components that are presently leak repaire Grounds on 125 Vdc Control Power Busses From October 12, 1993, until the end of the inspection period, there were annunciators indicating low resistance to ground on the DC control power bus positive legs of all three units. The nominal value for voltage on the positive leg is approximately 67 Vd When a ground occurs the voltage on the affected leg drop Oconee has set their ground detectors to alarm when the voltage drops below 4 Vdc, which corresponds to a resistance to ground of 1500 ohms. When a ground annunciator actuates, the licensee measures the positive and negative leg voltages on the affected bus. If the absolute value of the voltage is greater than 4 Vdc, the licensee does not consider a "ground" to exist and no further action to correct the low resistance is taken. Throughout this period the positive leg voltage remained slightly above 4 Vdc, therefore no corrective action was taken to resolve the low resistance to ground conditio The inspectors were concerned that a threshold of 1500 ohms was low and could adversely affect safety similar to events discussed in NRC Information Notice (IN) 88-86, and Supplement 1 to IN 88 86. The IN documented instances where plant equipment at various plants was rendered inoperable or started unexpectedly because of grounds. Supplement 1 to the IN documented that a 125 Vdc system with a sustained ground condition of 4000 ohms or less, was susceptible to subsequent grounds causing vital circuits to fail energize The inspectors noted that there was no technical basis for the 1500 ohm threshold. The licensee stated that this setpoint was selected because their equipment for locating grounds in the field was inadequate for grounds above 1500 ohm The NRC has previously documented concerns with the continued presence of ground alarms on Oconee's 125 Vdc system (see Inspection Reports Nos. 269, 270, 287/88-17 and 93-22).
The licensee has provided their position that the grounds on one leg do not render the bus inoperable since it is normally an ungrounded DC system. To date the licensee has taken little action to correct the underlying concern, namely the prolonged presence of low resistance to ground conditions on a system that requires a high degree of reliability and availability for safe plant operation. This continues to be identified as a maintenance weaknes No violations or deviations were identifie.
Keowee Issues During the previous inspection period (NRC Inspection Report N,270,287/93-24), the Keowee Unit 2 generator supply breaker did not close during the performance of the annual surveillance test. The initial cause of the failure was identified as high contact resistance in the closing coil circuitry and the breaker was replaced. Subsequent testing performed on the failed breaker by the licensee, conducted during this inspection period, identified that the breaker failure was not caused by high contact resistance as originally postulated. The licensee determined by testing the breaker that current values required to prevent the breaker from closing would have resulted in major heat damage and pitting of the contacts and would not have resulted in the (as-found) heat damage to the breaker closing coi The licensee determined that the most probable cause of the failure was a trip free operation of the field supply breaker caused by a missing cotter pin in the pin that connects the close solenoid armature to the breaker toggle mechanism. The missing cotter pin could have allowed the connecting pin to slip and catch on the mechanism frame. If this occurred, the armature would hang near the top of its travel preventing the trip latch from resetting when the breaker was subsequently tripped on a unit shutdown. If the trip latch doesn't reset, the breaker will trip free on the next operation. During a trip free operation, the armature operates the toggle mechanism but doesn't operate the main contacts or auxiliary switches and the breaker will not operate. The inspectors reviewed the licensee's actions to identify the breaker failure mechanism and concluded that the licensee actions were appropriate and identified the most probable root cause of the breaker failur O Independent Safety Engineering Group (ISEG) Functions During the inspection period the inspectors reviewed the licensee implementation of the ISEG functions. Oconee does not have an ISEG
requirement in the Technical Specifications. However, the licensee performs the functions identified to be accomplished by an ISEG. These functions are accomplished in a disbursed manner throughout the organizatio Corporate Nuclear Services performs an Integrated Safety Assessment (ISA) every six months for submittal to the Nuclear Safety Review Boar This assessment uses the following data to evaluate nuclear safety:
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Significant events/accident precursors/shutdown events
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Safety system unavailability (high pressure injection, Emergency feedwater, and Keowee Hydro)
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NRC Violations
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Nuclear plant reliability data system (NPRDS)
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Performance Indicators
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Licensee Event Reports Oconee was rated good with opportunity for improvement in the last ISA reviewed by the inspector Corporate controls the operating experience program (OEP).
The inspectors have reviewed the licensee's responses to numerous OEP items throughout the SALP cycle and concluded that the licensee program was adequat Licensee Event Reports are generated by the Oconee safety review grou This group is part of the safety assurance department and reports to the site vice president through the safety assurance manager. This group also performs investigations of significant operating events and controls the licensee's problem investigation process to identify and resolve discrepancies identified by plant personne The inspectors consider that the ISEG functions are being performed but consider that the process is not necessarily independent of site managemen.
Licensee Evaluations of Changes to the Environs Around Licensed Reactor Facilities (T12515/112)
The purpose of this inspection was to determine if the licensee's programs were adequate for evaluating public health and safety issues resulting from changes in population distribution or in industrial, military, or transportation hazards that could occur on or near the site, and to determine if the licensee routinely documents these changes in updates to the final safety analysis report (FSAR).
The licensee updates their FSAR on an annual basis. Each chapter is assigned a technical sponsor who reviews the chapter and recommends any changes. For Chapter Two of the FSAR (the chapter regarding site characteristics), the review does not include a query into any pending construction of industrial facilities that might affect the sit Additionally there is no mechanism to determine major changes to military or civilian airways or changes in the frequency of the movement or amount of hazardous cargo near the sit The population information in the FSAR was limited to the 1970 population distribution and the 2010 projected population distributio The inspector noted that this information was based on the 1960 census and that the 1990 population listed in the licensee's emergency plan (based on the 1990 census) exceeded that of the 2010 projected population in the FSA The original FSAR stated that there were no oil or gas pipelines within 5 miles of the site. In the 1991 update, this was amended to document the existence of high pressure (400 psi) gas distribution pipelines approximately 3.5 miles from the site. This update was not initiated as a result of any program for evaluating changes to the environs around the site, but rather as a result of NRC information notice 91-63,
"Natural Gas Hazards at Fort St. Vrain Nuclear Generating Station". The inspector noted that the licensee did not perform a 10 CFR 50.59 analysis to determine if the gas distribution pipelines represented an unreviewed safety questio In conclusion, based on interviews with licensee personnel and a review of the FSAR, the inspector determined that the licensee did not have a proactive program to periodically identify and evaluate changes in site proximity hazards and demography to determine their effect on the safety of the plan.
Inspection of Open Items (92701) (92702)
The following open item was reviewed using licensee reports, inspection record review, and discussions with licensee personnel, as appropriate:
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(Closed) URI 50-287/93-22-01, Load Shed Channel 1 Operabilit This unresolved item was opened pending completion of a past operability review by the licensee for the load shed channel 1 signal to switchgear 3TD. This item was addressed in NRC Inspection Report No. 269,270,287/93-24 and a violation was issued (50-287/93-24-01). The Licensee plans to issue a Licensee Event Report (LER) on this event. Resolution of this item will be tracked by the violation response and review of the LER. Based on these actions, the Unresolved Item is close O Review of Licensee Event Reports (92700)
The below listed Licensee Event Report (LER) was reviewed to determine if the information provided met NRC requirements. The determination
included: adequacy of description, compliance with Technical Specification and regulatory requirements, corrective actions taken, existence of potential generic problems, reporting requirements satisfied, and the relative safety significance of each even (Closed) LER 50-270/93-06, Containment Isolation Valve Mispositioned Due to an Unknown Cause, Possible Inappropriate Action. This LER addressed a 3/4 inch instrument root valve, 2CF 41, on the 2B core flood tank fill line that was found open by a non-licensed operator during water addition to the core flood tank. Valve 2CF-41 is a containment isolation valve and is required to be closed during normal operation. The licensee determined that the last documented time the valve was opened was on May 26, 1993, during the performance of a local leak rate tes Subsequent to the local leak rate test, the valve was shut and independently verified shut. On June 17, the valve was again independently verified closed during the performance of PT/2/A/115/08, Reactor Building Containment Isolation and Verification. On September 2, the valve was found open by the non-licensed operator. The licensee immediately closed the valve and verified that the corresponding valve on the 2A core flood tank fill line was closed and that the corresponding valves on Units 1 and 3 were also in their proper positions. This item was previously addressed in NRC Inspection Report No. 269,270,287/93 24. The inspectors reviewed the LER and the licensee's planned corrective actions. Based on this review, this item is close No violations or deviations were identifie.
Exit Interview The inspection scope and findings were summarized on October 27, 1993, with those persons indicated in paragraph 1 above. The inspectors described the areas inspected and discussed in detail the inspection findings. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection nor did they provide any dissenting view Item Number Description/Reference Paragraph URI 50-269/93-26-01 Load Shed System Not Single Failure Proof (paragraph 2.c).
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