IR 05000269/1990004
| ML15224A639 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 02/28/1990 |
| From: | Binoy Desai, Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A638 | List: |
| References | |
| 50-269-90-04, 50-270-90-04, 50-287-90-04, NUDOCS 9003130094 | |
| Download: ML15224A639 (11) | |
Text
6 s REG'
UNITED STATES o
NUCLEAR REGULATORY COMMISSION
REGION II
o 101 MARIETTA STREET, ATLANTA, GEORGIA 30323 Report Nos.:
50-269/90-04, 50-270/90-04, 50-287/90-04 Licensee: Duke Power Company 422 South Church Street Charlotte, N.C. 28242 Docket Nos.:
50-269, 50-270, 50-287 License No DPR-38. DPR-47, DPR-55 Facility Name:
Oconee Nuclear Station Units 1, 2, and 3 Inspection Conducted: January 14 -
February 17, 1990 Inspectors______ _//___________
T. 11. Ikinner, Senipt Resident Inspector Bate 6igned L. D.Wert, Residentnspector ate ined
'B..
esal, eside Inspector ate igned Approved by:
'
M. B. Shyml ck, Section Chief Date Signed Division of Reactor Projects SUMMARY Scope:
This routine, announced inspection involved inspection on-site in the areas of operations, surveillance testing, maintenance activities, evaluation of licensee self-assessment capability, observation of fitness for duty training and inspection of open item Results:
In addition to the routine inspection activities, the residents reviewed the licensee's actions concerning;
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A Unit 3 reactor trip which occurred during routine testing of the Control Rod Drive system (paragraph 2.b.).
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The identification and subsequent repairs of a body-to-bonnet leak on valve 3LP-9 (paragraph 3.b.).
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The resolution of a potential problem with Sylvania circuit breaker loose contactor screws (paragraph 2.c.).
No significant weaknesses were note C()313009;4 90022:
PDR ADOCi-K::
05o0026.9:.)
FDC
REPORT DETAILS 1. Persons Contacted Licensee Employees
- B. Barron, Station Manager D. Couch, Keowee Hydrostation Manager
- J. Davis, Technical Services Superintendent D. Deatherage, Operations Support Manager B. Dolan, Design Engineering Manager, Oconee Site Office
- W. Foster, Maintenance Superintendent
- R. Gill, Manager Regulatory Compliance T. Glenn, Instrument and Electrical Support Engineer D. Hubbard. Performance Engineer
- C. Jennings, Station Emergency Planner
- E. LeGette. Compliance Engineer H. Lowery, Chairman, Oconee Safety Review Group B. Millsap, Maintenance Engineer D. Powell, Station Services Superintendent
- G. Rothenberger. Integrated Scheduling Superintendent
- R. Sweigart. Operations Superintendent Other licensee employees contacted included technicians, operators mechanics, security force members, and staff engineer NRC Resident Inspectors:
Skinner
- L. Wert B. Desai
- Attended exit intervie.
Plant Operations (71707)(71710)
a. The inspectors reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative controls. Control room logs, shift turnover records, and equipment removal and restoration records were reviewed routinel Discussions were conducted with plant operations, maintenance, chemistry, health physics, instrument &
electrical (I&E), and performance personne Activities within the control rooms were monitored on an almost daily basi Inspections were conducted onday and on night shifts, during weekdays and on weekend Some inspections were made during shift change in order to evaluate shift turnover performanc Actions observed were conducted as required by the Licensee's Administrative Procedure 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. The areas toured included the following:
Turbine Building Auxiliary Building CCW Intake Structure Independent Spent Fuel Storage Facility Units 1, 2 and 3 Electrical Equipment Rooms Units 1, 2 and 3 Cable Spreading Rooms Units 1, 2 and 3 Penetration Rooms Station Yard Zone within the Protected Area Standby Shutdown Facility Units 1, 2 and 3 Spent Fuel Pool Rooms Keowee Hydro Station During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observe Units 1 and 2 operated at 100% power for the duration of this reporting perio Unit 3 commenced this report period operating at 100% power and continued operation at that level until January 19 when a reactor trip occurred (see paragraph 2.b).
The unit returned to 100% on January 21 and operated at that level for the remainder of the period with the exception of a one day period at 95% to repair a leaking valve on the second stage reheate Unit 3 Reactor Trip At 8:49 a.m. on January 19, 1990, Unit 3 experienced an automatic reactor trip. The automatic trip was caused by a low Reactor Coolant System (RCS)
pressu're conditio I&E personnel were performing Instrumentation Procedure (IP) 0/B/340/02. Control Rod Drive (CRD) DC Hold Supply, Regulate Supply SCR Gate Drive, and Programmer Checks when the trip occurre Post trip response was normal with the following exceptions:
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The 'B' Once Through Steam Generator (OTSG) level control did not properly control the level in the 3B OTSG resulting in a higher than normal level following the tri The 'B' Main Feedwater Control Valve would not stay in the manual mode as selected by the operato The 'A' Main Feedwater Pump (MFWP)
tripped on high discharge pressur A review conducted by the licensee identified the following sequence of events:
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IP/0/B/340/02 was being conducted by I& Due to a problem in the rod drive control system all rods in Group 6 were unlatched and dropped into the cor For the conduct of the IP, the Integrated Control System (ICS)
had been placed in the manual mode as required by normal procedure This precluded the ICS from automatically running the feedwater control systems back following the tri When the Group 6 rods dropped, the continued feedwater flow to the OTSGs resulted in a rapid RCS pressure decrease which caused an automatic RCS low pressure trip at 1800 psi The operators immediately attempted to take manual control of the main feedwater valves in order to reduce feedwater flo The 'B' OTSG feedwater valve did not immediately shift to manual control when the operator attempted to perform the transfe Several attempts had to be made before the valve was success fully shifted to the manual control mod The 'B' OTSG level control circuit of the ICS apparently attempted to control level at a higher value than the 25 inch programmed level setpoint following a tri Other problems that occurred were: (1) a relief valve on the
'C2'
feedwater heater failed open which resulted in the heater requiring isolation, and (2) Condensate Booster Pump (CBP) 'A'
experienced a mechanical seal failur The licensee conducted an investigation of the trip and events that occurred as part of this trip. The findings were discussed in detail with the inspector The inspectors witnessed actions taken by the operators and portions of the corrective actions taken by the licensee. The inspectors participated in the post trip meeting held on January 26, 1990. Corrective actions were taken for each specific problem identified prior to returning the unit to power operatio The licensee notified the NRC as required by 10 CFR 50.72(b)(2)(ii).
The licensee's investigation resulted in the following actions:
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The problem with the CRD system was attributed to either an operator error (the "clamp release" pushbutton was not fully actuated) or a failure in the clamp circuit which could not be duplicate This action allowed both the auxiliary and the normal power supply voltage to be simultaneously applied to the mechanisms in group si When the I&E technicians, in
accordance with the procedure, cycled the normal power supply to the various phases of the control rod group six contactors, four phases were simultaneously energized in an alignment which resulted in a cancelling effect on the CRD magnetic field This caused the rods to unlatch and drop. Procedures are being changed to monitor for phase relationships when performance of this IP is being conducte Further review of this is being pursued by the license The problem identified with the OTSG level control on the B generator was determined to be an improper setpoint on an integral module in the ICS feedwater controlle The setting was returned to the correct position and an investigation is being performed to determine how the setpoint was misadjuste The problem identified with the MFW control valves was determined to be an incorrect module installed in the ICS system. Although the modules in question have the same supply system identification number, the modules are designated F (correct) and G (incorrect) on their label The time delay associated with the G module is longer and required the switch for the MFW valve to be held in position a longer period to initiate a transfer to manua Since this was not known by the operators, difficulty was experienced in making this transfe The licensee is investigating this problem to determine how this incorrect module was obtained and installe The 'A' MFWP trip occurred due to a problem with setpoint drift associated with the pressure switches involve On increasing discharge pressure, the 'B' MFWP is expected to trip before the
'A' MFW (The setpoints are 1275 and 1240 psig for A and B respectively.)
I&E concluded that the change in setpoint was probably due to vibration. A locking material will be used on the setting adjustment screws during subsequent calibration The relief valve on the C2 heater was attributed to a failure of the valve. It was gagged and a temporary relief was installed on a vent line as temporary corrective actio The relief valve will be repaired during a subsequent shutdow Condensate booster pump 'A' has been isolated and the mechanical seal is being repaire Based on the actions taken and a review of Units 1 and 2 to ensure similar problems were not identified on those units, Unit 3 was returned to power operation at 1:47 a.m., January 20 and was returned to 100% power at 6:47 a. m.. on January 2 c. Inspection for Loose Contact Carrier Screws in Sylvania Contactors On January 17, 1990, the inspectors were informed by the resident inspectors at Catawba Nuclear Station of a potential problem regarding Sylvania circuit breaker contactor Duke Power Company (DPC)
personnel had discovered that the contact carrier screws in several circuit breakers had become loos The contactors are used inside safety-related (S/R)
and nonsafety-related breakers on Motor Control Centers (MCCs)
throughout the DPC nuclear station The loosening or backing out of these screws can result in the breaker becoming inoperabl Apparently the screws become loose after numerous operation The inspectors contacted Oconee Instrument and Electrical personnel when informed of the potential proble The Catawba initiated Problem Investigation Report (PIR 0-C90-0008) had not yet reached Ocone It was determined that these contactors are utilized much less at Oconee than the other DPC nuclear station The following S/R or important to safety applications of the Sylvania contactors were identified;
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Four S/R remote starter valve breakers per unit; Valves LPSW-565,566 (Low Pressure Service Water to 'B' Reactor Building Cooling Unit and Auxiliary Coolers)
and HP-409,410 (High Pressure Injection pump discharge cross connects).
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Eight important to safety valve breakers per unit, two in the reactor building purge system, six in the feedwater syste Numerous S/R valve breakers on several MCCs located in the Safe Shutdown Facility (SSF).
Oconee I&E personnel promptly carried out inspection on all of the above breakers to verify no loose screws existe The inspection consisted of opening the breaker enclosure and performing a visual verification that the screws were flush with the adjoining surfac The inspectors observed most of these inspections conducted on the SSF valve breaker All inspections were completed on January 1 with no loose screws noted. The majority of those S/R breakers are infrequently cycled. Additionally, these breakers had been installed at Oconee after this potential problem had been noted by the manufacturer and screws coated to prevent this problem were utilize The inspectors will continue to follow the licensee's actions in regards to both long term corrective actions and final resolution of the PIR. Regional Management is following this issue for potential generic implication No violations or deviations were identifie II
3. Surveillance Testing (61726)
a. Surveillance tests were reviewed by the inspectors to verify procedural and performance adequac The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification where required, handling of deficiencies noted, and review of completed wor The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met. tests were conducted according to procedure, test results were acceptable and systems restoration was complete Surveillances reviewed and witnessed in whole or in part:
PT/1/A/0150/22A Operational/Refueling Valve Functional Test dated January 11. 1989 PT/O/A/0160/02 RB Cooling System Performance Test dated January 9. 1989 PT/O/A/0160/03 RB Cooling System ES Test dated January 8, 1989 IP/O/A/0310/014C Engineered Safeguard System Analog Channel "C" On Line Calibration b. 3LP-9 Leakage In Excess Of TS Surveillance Limits (71707,61726)
At approximately 5:00 on January 30, 1990. during maintenance efforts to correct a previously identified body-to-bonnet leak on valve 3LP-9 (Low Pressure Injection (LPI)
Pump discharge cross connection valve) it was identified that leakage had increased to approximately 2.2 gallons per hour (gph).
TS 4.5.4:
Low Pressure Injection System Leakage, requires that at each refueling outage tests to determine LPI system leakage shall be conducte The requirements specify that the portion of LPI which contains valve 3LP-9 shall be tested either by use in normal operation or hydrostatically tested at 350 psi The TS acceptance limit states that maximum allowable leakage from the LPI system including valve stems, flanges and seals shall not exceed 2 gph. The 2.2 gph leakage from 3LP-9 was measured with approximately 40 psig present on the system (primarily Borated Water Storage Tank static head).
The issue was promptly reported to the resident inspector Discussions were held regarding the available options for repair of the leak and the course of action regarding the LPI syste After attempts to stop or minimize the leak by overtorquing the body-to-bonnet studs had failed, the 'A' LPI train was isolated at 7:24 This action stopped the lea Valve 3LP-9 was success fully repaired and the 'A' train of LPI was returned to service within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Limiting Condition for Operation period specified for an LPI train out of service in TS 3. While the basis and intent for the requirements of Surveillance TS 4.5.4 are not clear, the above actions were conservative and resulted in the rapid isolation and repair of the leak. The licensee has initiated a Problem Investigation Report (PIR)
to address questions about TS 4.5.4 which surfaced during this situatio The inspectors will continue to follow the licensees action No violations or deviations were identifie. Maintenance Activities (62703)
Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that was not within the skill of the trad Activities, procedures, and work requests were examined to verify proper authorization to begin work, provisions for fire, cleanliness, and exposure control, proper return of equipment to service, and that limiting conditions for operation were me Maintenance reviewed and witnessed in whole or in part:
WR 22911C Readjust Closing Indication Time On Valve 2LPSW-21 (IP/O/A/3001/10 Maintenance of Limitorque Operator June 26, 1989)
WR 0537901 Inspection of Contact Carrier Screws In Specific Valve Breakers WR 26227C Troubleshoot 2FDW106 No violations or deviations were identifie. Evaluation of Licensee Self-Assessment Capability (40500)
The inspectors completed the review of the licensees capability to perform self assessments which was started in November 1989 (See Inspection Report 50-269,270,287/89-36).
The Oconee Nuclear Safety Review Board (NSRB)
conducted a meeting at the station January 23 and 24, 1990, at which various topics were discussed in detail with representatives of the Oconee operating staff and various support group Topics included Emergency Power Switching Logic problems, methods of providing Design Data to the station, security issues, Technical Specification 3.1.2 associated with Low Temperature Overpressure Protection, and various other topic The NSRB asked indepth questions of the personnel involved and made recommendations to the NSRB Chairman to address outstanding issue No violations or deviations were identifie.
Resident Inspector Observation of Licensee Fitness For Duty Training (TI 2515/104)
On February 12, 1990, the senior resident inspector observed the training being provided to new supervisory staff personnel. The training consisted of a series of video tapes in conjunction with a lecture presentatio The presentation was taken from a training lesson plan entitled FFD-001-FFD. Training For Supervisor The session lasted approximately three hours and fifteen minute Although there were only four individuals in the training, the class actively participated in a question and answer session at the conclusion of the presentatio The concerns expressed by the inspectors at a previous training session concerning training in the areas of behavior observation and escort training were included in this trainin This training and the previous training discussed in Inspection Report 50-269,270,287/89-36 fulfills the requirements contained in TI 2515/10 No violations or deviations were identifie. Licensee Quality Assurance Program Implementation (35502)
An internal office evaluation of the licensee's quality assurance program implementation was conducted by reviewing recent inspection reports, SALP reports, open item licensee corrective actions for NRC inspection findings and licensee event report Particular emphasis was placed on all new items or findings since the last SALP report period. There were no recommendations to perform additional inspection An evaluation by Emergency Preparedness of a drill in addition to the annual exercise was already planne. Inspection of Open Items (92700)(90712)(92701)
The following open items were reviewed using licensee reports, inspection, record review, and discussions with licensee personnel, as appropriate:
a. (Closed)
IFI 269,270,287/89-12-01:
Resolution of Malfunctions Associated With RVLIS. This item was identified due to a variety of faults that could be received on the reactor vessel level instrumentation system (RVLIS)
that would cause the indicators to display the word "Malfunction". Operators could not determine if the system was operable if this condition occurre As a result the licensee issued a surveillance procedure which was conducted two times a day by operations personnel to determine operabilit Nuclear Station Modification (NSM)
2401 has been developed and implemented on Unit 3 which provides malfunction in the form of an annunciator alar Upon receipt of this annunciator alarm I&E technicians make a determination as to the operability of this syste If a failed sensor occurs and can be bypassed without effecting the RVLIS operability, this will be done by I&E and the malfunction indication will be eliminated returning the system to normal indication for operator us This NSM is scheduled to be accomplished on Units 1 and 2 during the next refueling outag Based on this action, this item is close (Closed)
IFI 269,270.287/88-12-03:
Management Review of Communications Interface Between Performance and Operations During Testin This item addressed a concern that operating requirements of a performance test were not communicated to Operations personnel conducting the tes Training sessions emphasizing the responsibilities of Operations personnel during the specific performance test (Turbine Driven Emergency Feedwater Pump Performance Test) were conducted with all non-licensed operators (NLOs) on all shift Additionally a specific Limit and Precaution' statement in the Performance Test was modified to more clearly state the responsibilities of the NLO during testin Operations management sent a letter to various station Section Heads addressing the communications interface between Operations and other working groups during testing or maintenanc The inspectors have observed improvement in these interfaces since this issue was identifie Communications between Operations and other working groups during testing have not been a problem in recent month Communications between Instrument and Electrical technicians and operator's involving a performance test during which a Unit 3 trip occurred (paragraph 2.b) were noted as particularly stron This item is close (Closed)
LER 50-269/89-07:
Release To Chemical Treatment Pond Results In A Condition Prohibited By Technical Specifications. This LER was addressed in Inspection Report 50-269,270,287/89-2 This item was left open pending management review of staffing requirements of the radwaste facilit Discussions with the Technical Superintendent identified that portions of the facility will not be operated and based on that decision the present staffing levels are adequat Based on this discussion, this item is close (Open)
LER 287/88-03:
Potential Degraded Performance of Reactor Building Cooling Units (RBCUs) Due to Service Induced Fouling. This LER addressed a situation in which performance testing data indicated that service induced fouling of the Unit 3 RBCUs may have reduced their post-LOCA heat removal capabilities below acceptable limit The inspectors have been closely following the licensees actions to resolve this issu Inspection Reports 50-269,270,287/89-11 and 28 contain additional detail Currently, the licensee is still performing testing at quarterly intervals on each of the three unit The service induced fouling of the coolers has been attributed to an air side fouling problem but the exact phenomenon has not been confirme The licensee has purchased improved instrumentation to obtain humidity and air temperature values during testin The instrumentation will be permanently installed inside the RBCU ductwor There continues to be uncertainty in the correlation of data obtained during "cold" (approximately 100 degrees F) or on-line testing to the predicted cooler performance under LOCA condition Data obtained during testing performed just prior to shutdown of Unit 3 for its end of cycle (EOC) 11 refueling outage indicates that the analysis may still be overly conservative when predicting LOCA heat transfer capabilities from on-line dat Because of a problem with the Reactor Building Auxiliary Coolers, (see Inspection Report 50-269,270,287/89-34), Unit 3 containment temperatures were higher than normal during the EOC testing (approximately 125 degrees F).
The coolers heat removal capabilities for LOCA conditions were calculated at values of about 100 percent of their design parameters based on this dat Testing after extensive cooler cleaning (prior to plant startup), conducted under cooler ambient conditions. yielded values of only seventy percen While all of the planned corrective actions listed in the LER have been completed, the licensees actions to fully resolve the fouling mechanism and any overly conservative considerations in the calculated LOCA capabilities of the coolers are continuin This item remains ope e. (Closed)
10 CFR 21:
Potential Deviation To Specifications In RY Vertical Indicators. Series 15, All Versions of RY 1 and RY 2 (P2188-05).
This Part 21 was identified to the NRC in correspondence dated October 10, 1988. The licensee has replaced all safety-related Bailey RY indicators, with the exception of one indicator in each unit, with a new design manufactured by Dixo The remaining indicator is located in each control room and indicates High Pressure Injection crossconnect flow. There are no plans by the licensee at this time to replace this indicato The licensee considers that since the problem identified by the Part 21 is associated with a change in temperature of 60 degrees. that since the indicator is located in the control room, the problem identified will not be observed in this instrument. Based on this information this item is close. Exit Interview (30703)
The inspection scope and findings were summarized on February 16, 1990, with those persons indicated in paragraph 1 abov The inspectors described the areas inspected and discussed in detail the inspection finding The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio