IR 05000269/1989034
| ML15224A607 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 12/08/1989 |
| From: | Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A606 | List: |
| References | |
| 50-269-89-34, 50-270-89-34, 50-287-89-34, NUDOCS 8912280288 | |
| Download: ML15224A607 (8) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, ATLANTA, GEORGIA 30323 Report Nos.:
50-269/89-34, 50-270/89-34. 50-287/89-34 Licensee: Duke Power Company 422 South Church Street Charlotte. N.C. 28242 Docket Nos.:
50-269, 50-270, 50-287 License Nos.: DPR-38, DPR-47, DPR-55 Facility Name: Oconee Nuclear Station Inspection C nducted:
October 11 - November 11, 1989 Inspectors:
P. H. Skinne Senior Re dent Inspector D te Signed L. D. Wert, Rd ident Inspedtor teSigned Approved by:
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__1g M. B. Shymloc( 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, and inspection of open item Results: In addition to the routine inspection activities, the resident reviewed the licensees actions concerning;
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A Reactor Coolant System leak through a leaking Building Spray valve resulting in a 2000 gallon spill of primary coolant into the Reactor Building. (paragraph 2.b)
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A dropped control rod and subsequent shutdown on Unit (paragraph 2.c)
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A licensee identified design problem involving the seismic rating of cooling water piping to the Reactor Building Auxiliary Coolers. (paragraph 4.b)
No significant weaknesses were note PDR ADOCK 05000269 Dil
REPORT DETAILS 1. Persons Contacted Licensee Employees
- M. Tuckman. Station Manager D. Couch, Keowee Hydrostation Manager B. Barron, Assistant Station Manager C. Boyd. Site Design Engineer Representative
- J. Davis. Technical Services Superintendent D. Deatherage. Operations Support Manager
- W. Foster. Maintenance Superintendent T. Glenn. Instrument and Electrical Support Engineer D. Hubbard. Performance Engineer 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, operator mechanics. security force members, and staff engineer NRC Resident Inspectors:
- Skinner L. Wert
- Attended exit intervie. Plant Operations (71707)(71710) 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 on day and on night shifts, during week days and on weekends. 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 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. The areas toured included the following:
Turbine Building Auxiliary Building Units 1. 2 and 3 Electrical Equipment Rooms Units 1. 2 and 3 Cable Spreading Rooms Unit 3 Penetration Room Station Yard Zone within the Protected Area Standby Shutdown Facility Units 1. 2 and 3 Spent Fuel Pool Room Intake Structure ISFSI Construction Site Keowee Hydro Station During the plant tours, ongoing activities. housekeeping. security, equipment status. and radiation control practices were observe Unit 1 -
Unit 1 operated at 100 percent power for the entire report period with the exception of a few hours on October 25 when power was reduced to 95 percent as a result of a runback due to a failure in the circuitry of a Reactor Coolant System loop flow instrumen Unit 2 -
Unit 2 operated at 100 percent power from the beginning of this period until October 14 when power was reduced to 60 percent to repair a leak on the 'lB' feedwater pump. The unit was returned to 100 percent power level on October 1 On October 28 power was reduced to 90 percent to repair a steam leak on a heater drain valve. The unit was returned to 100 percent power on October 29. On November 10 Unit 2 dropped control rod 4-9 during a Control Rod Drive Exercise test (paragraph 2.c).
As a result of further analysis by the licensees Design Engineering group. Unit 2 was shutdown on November 11 to repair the proble Unit 3 -
Unit 3 operated at 100 percent power until November 8 when the unit was shutdown to begin a scheduled 42 day outage perio Unit 3 Reactor Coolant System Leak Through Reactor Building Spray System On November 9. 1989, at about 2:20 p.m., Unit 3 spilled approximately 2000 gallons of reactor coolant through the 'A' Reactor Building Spray (RBS) header into the Reactor Building (RB).
Unit 3 was below hot shutdown conditions and proceeding to cold shutdown when the loss of inventory occurre During performance of OP/3/A/1102/10:
Controlling Procedure for Unit Shutdown. the operators opened valves connecting the Reactor Coolant System (RCS)
to the Low Pressure Injection (LPI) system. This placed RCS pressure (about 300 psi) on the RBS system through the LPI system up to valve 3BS-1 (3BS-1 is normally shut and opens on an engineered safeguards spray signal).
3BS-1 apparently had a significant seat leak and this allowed the RCS water to flow into the 'A' spray heade The operators promptly recognized through several indications received in the Control Room (RB fire alarms, sump level increasing, pressurizer level decreasing)
the loss of inventory and immediately shut the valves connecting the RCS to the LPI header thus securing the lea Approximately 2000 gallons were spilled during the leak. No personnel were in the RB at that tim OP/3/A/1102/10: Controlling Procedure for Unit Shutdown has two concurrent steps (bullet format) one of which aligns LPI for decay heat removal and the other secures RBS from its Engineered Safeguards (ES) alignment. Consequently. LPI was connected to the RCS through opening valves 3LP-1, 3LP-2, and 3LP-3. while PBS was still in an ES alignmen As a result only valve 3BS-1 (an 8 inch normally shut globe valve) was between the RCS and the RB spray heade The procedure has previously allowed the possibility of this alignment to occur, but leakage past 3BS-1 has not been a noted problem in the pas While indications of a loss of RCS inventory were immediately recognized and acted on when the leak occurred, for several hours operators believed that the source was a lifted relief valve (3LP-25 in the LPI line).
At about 11:00 p.m. on November 9 it was identified that the leak had been through the spray header into the RB. Apparently senior onsite management was not aware of the details of the incident until the next mornin The plant manager then made several attempts to contact the Senior Resident Inspector and left a message at the Resident Inspector's residence at about noo The resident arrived onsite at 6:30 p.m. and investigated both this event and the Unit 2 dropped rod incident (see paragraph 2.c).
While the spill did increase Unit Three RB radiation and upper level contamination levels. no personnel were contaminate The normal refueling shutdown washdown and decontamination process were not significantly affected by this even III
After discussions with regional and NRR management the residents requested that valve 3BS-1 be quarantined and a systematic approach developed to investigate the proble After review of the plan by the inspectors the licensee will commence the investigatio The inspectors closely reviewed this issue for reportability. It is not clearly required by 10 CFR 50.72 or 20.403 to be reporte The licensee intends to change OP/3/A/1102/10 so that the Unit 3 Building Spray is removed from ES alignment prior to LPI being aligne This problem would not occur on Units 1 or 2 because of a different LPI arrangement. The investigation of the apparent leakage of 3BS-1 will be closely followed by the inspector c. Oconee Unit 2 Dropped Rod At about 11:30 a.m.,
on November 1.
Oconee Unit 2 dropped Rod 4-9 during a Control Room Drive (CRD)
Exercise procedur The operator immediately placed the Integrated Control System (ICS)
in automatic and a runback to about 55 percent occurred as expecte (ICS was in manual as part of the CRD procedure.)
All other plant systems performed as expected during the transien The licensee performed all TS required actions including verification of available shutdown margin within one hour and reduction of Reactor Protection System (RPS) setpoints. Initial plans were to remain at about 55 percent and enter the RB the following morning to investigate the cause of the dropped ro The problem was suspected to be an open connector or an open in the stato After extensive analysis of the incident, the licensee's Design Engineering (DE) group concluded that under the existing Quadrant Power Tilt (QPT)
and power level restrictions (TS requires high flux setpoint to be reset to 65 percent), if imbalance exceeded certain values. localized fuel damage may occu The plant was operating well within limits at the time but DE identified a concern that the automatic protective systems may not have had sufficiently low enough setpoints (imbalance portion) to prevent local fuel damage under conditions of high imbalanc At about 10:00 p.m., the licensee informed the resident who was onsite and also notified the NRC Operations Center of this potential condition and commenced shutdown to a hot shutdown conditio The report was made under 50.72(b)(1)(B)(ii)A and the cause was stated to be "the dropped rod and the subsequent investigation".
On November 12 the problem had been identified as an open in a connector on the CRD and was repaired. While shutdown, the licensee also completed modifications to Containment Penetrations 53 and 39 as committed to previously in an emergency TS change request (See Inspection Report 50-269.270,287/89-31).
The penetration modifications were satisfactorily teste (III5 The licensee's DE is continuing to analyze the dropped rod power distribution and affects, meanwhile the operators have been instructed that TS 3.0 will be entered on a dropped rod event. The inspectors will continue to follow the licensees actions on this issu d. Potential Safety Concern Regarding HPI Flow Instrumentation Accuracy (PSC 1-89)
On October 27, the inspector was notified by Region II of a potential safety concern (PSC)
identified by Babcock and Wilcox (B&W)
for specific plant The inspector participated in a telephone conference call between NR Region II, and Crystal River to obtain more detail concerning the proble Following the conference call the inspector discussed this PSC with the B&W site engineer and licensee representative The B&W site engineer obtained a copy of the PSC indicating that this problem was not applicable to Ocone The inspector confirmed that the PSC was not applicable to Oconee and notified Region II managemen No violations or deviations were identifie. Surveillance Testing (61726)
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 work. The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was complete Surveillances reviewed and witnessed in whole or in part:
MP/O/A/2000/32 Keowee Hydrostation; Mulsifyre Wet Test and Electro-Mechanical Relay Test of Main Transformer PT/2/A/0600/13
'2B' Motor Driven Emergency Feedwater Pump Performance Test OP/O/A/1106/19 Operability Verification of the Keowee Underground Emergency Power Path PT/O/A/0400/04 Safe Shutdown Facility (SSF) Diesel Engine Service Water Pump Performance Test PT/O/A/600/23 SSF Fuel Oil Inventory PT/O/A/1103/15 Reactivity Balance Procedure (Unit 3 Cooldown)
PT/O/A/1103/15 Reactivity Balance Procedure (Unit 2 Dropped Rod)
PT/O/A/0261/07 Emergency CCW Flow Test. Dated 11/3/89 IP/O/A/0310/012A Channel 1 Engineered Safeguards (ES) On-line IP/O/A/0310/013A Channel 2 ES On-line No violations or deviations were identifie Since the pressure on the RBCU
'B' downstream piping is only approximately 40 psi. this would allow a direct flowpath from containment to the environment. This was reported as required by 10 CFR 50.72(b)2(iii)(c).
The licensee immediately shut the motor operated supply valve to the auxiliary coolers and entered a 7 day Limited Condition for Operation (LCO) as required by TS 3.3.5 The corrective actions taken by the licensee have been the following:
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The auxiliary cooling units cooling water flow has been secured by installation of blind flanges upstream of the return check valve This allowed the licensee to exit the LCO by returning the 'B' RBCU's to the required TS lineu Since isolating cooling water to the auxiliary coolers caused increased containment temperatures, these temperatures have been monitored closely to assure the average temperature does not exceed 120 degrees F and the RB dome temperature does not exceed 155 degrees Initially a design calculation was conducted which justified steady-state containment temperatures of 130 degrees A design calculation was subsequently completed which allowed an increase in the dome limitation to 170 degrees An operability evaluation was also performed to assure that the increased temperatures in the containment would have no detrimental effects on electrical equipment within the scope of 10 CFR 50.4 The licensee is evaluating short term and long term actions necessary to return these coolers to operatio.
Inspection of Open Items (92700)(90712)(92701)
The following open items are being closed based on review of licensee reports, inspection, record review, and discussions with licensee personnel, as appropriate: (Closed) Inspector Followup Item (50-269.270.287/89-03-04): Damaged Cable Repair/Replacement. This item concerned cables in trays above the location of the 1TA switchgear fire in January 198 Based on the licensees records and visual inspection of the area by the inspector, all potentially damaged cables have been repaired or replace (IFI 269,270,287/89-05-03 will remain open and addresses the overall cable separation issue.) This item is close b. (Closed) LER 269/86-10:
Potential For Loss of Emergency Feedwater Due to Pump Runout For Certain Transient This LER was submitted September 29. 1986. and supplemented on May 28, 1987, and contained a commitment to install cavitating venturis in each Emergency Feedwater (EFW) line on each unit. On December 16. 1988, the licensee notified NRR that based on the inability to qualify the EFW piping system if the venturis were installed, other alternatives were being pursued to address this conditio By letter to NRR on June 30. 1989, the licensee provided information on alternatives that had been considered and rejected, and also stated that the operator burden during postulated accidents with low steam generator pressure had been evaluate Based on these evaluations, they found the small increment in burden for the operator to be acceptable in comparison to the installation of a complex syste A commitment was also made to continue studying the EFW system to see if cost effective modifications could be made without increasing the complexity of the system. In addition, the licensee requested a meeting between the NRC and the utility to discuss this issue. On October 17, 1989. a meeting was held at NRC headquarters to discuss this issu The NRC did not object to the proposals presented by the license Based on the information provided, modifications will not be made to limit pump runout. This item is close c. (Closed) LER 269/87-03:
Inadequate Overpressure Protection for the Auxiliary Steam Heade This LER was identified in the licensee's correspondence dated March 30, 198 A permanent design has been implemented on all units in accordance with NSM 2678. Auxiliary Steam Relief Valve The modifications have been declared operable and based on this action, this item is close d. (Closed) LER 269/89-12:
Keowee Hydro Units Were Emergency Started Due to Unknown Reason In June 1989 the Unit 2 Keowee Emergency Start circuitry channel B initiated an emergency start of the Keowee unit Unit 2 was shutdown at the time and several testing evolutions were in progres Efforts at duplication of the specific circumstances and getting another emergency start were unsuccessfu Actuation of Engineered Safeguards (ES) Channels 1 or 2 is one way to emergency start the Keowee units. Since this could not be eliminated as a cause of the emergency start, and several ES valves did actuate, a 10 CFR 50.73 report was submitte The licensee expended reasonable effort and resources in unsuccessful attempts to identify the caus The strongest theory involved a power spike in an electrical supply common to both the ES circuitry and the Keowee Emergency Start Circuit The inspectors closely followed the Maintenance Support Engineering efforts toward identification of the cause of the emergency start. Based on the inspectors review of this event, this item is closed.