IR 05000269/1982026
| ML20058H350 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/14/1982 |
| From: | Bryant J, Kleinsorge W, Order W, William Orders, Puckett M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058H340 | List: |
| References | |
| 50-269-82-26, 50-270-82-26, 50-287-82-26, 50-289-82-26, NUDOCS 8208030557 | |
| Download: ML20058H350 (5) | |
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UNITED STATES
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E REGION 11 g[
101 MARIETTA ST N.W., SUITE 3100 g
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ATLANTA, GEORGIA 30303 4,***
Report flos. 50-269/82-26, 50-270/82-26 and 50-287/82-26 Licensee: Duke Power Company 422 South Church Street Charlotte, f4C 28242 Facility flame: Oconee Nuclear Station Docket flos. 50-269, 50-270 and 50-287 License fios. DPR-38, DPR-47, DPR-55 Inspection at Oconee site near Seneca, South Carolina
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Approved by:
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Bryant, seq 46nChief,Divisionof D'a'te ' Signed oject and Resident Programs SUMf4ARY Inspection on July 6-9, 1982 Areas Inspected This special, announced inspection involved 64 inspector-hours on site in the areas of followup of extraction steam line rupture.
Results Of the areas inspected, no items of noncompliance or deviations were identified.
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DETAILS 1.
Persons Contacted Licensee Employees
- J. Ed Smith, Station Manager J. N. Pope, Supervisor Operations T. Owen, Supervisor Technical Services J. Vaughn, Supervisor Mechanical Maintenance
- T. Cribbe, Licensing & Project Engineer
- T. Matthews, Licensing Engineer Other licensee employees contacted included technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on July 7, 1982, with those persons indicated in paragraph 1 above. The licensee acknowledged cognizance of the inspectors' findings.
3.
Licensee Action on Previous Inspection Findings Not inspected.
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Unresolved Items Unresolved Items were not identified during this inspection.
5.
Extraction Steam Line Rupture On June 28, at 2:02 p.m., while at 95 percent power, Oconee unit 2 l
experienced a catastrophic failure in a 24" steam extraction line. Upon
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hearing the explosion and observing an apparent loss of main steam turbine header pressure, the reactor operators suspected that a main steam line break had occurred. Nine seconds after the rupture, the reactor was manually tripped, initiating an automatic turbine trip.
The failure was downstream of the main steam stop valves, thus the turbine trip isolated supply to the extraction line. Details of the post trip recovery are described elsewhere in this report.
The 194 PSIA /380 F steam escaping through the 4 square foot rupture (approximately 2 feet by 2 feet) physically destroyed motor control center (MCC) number 2XA-A. There were no safety-related loads supplied from the MCC nor any essential loads which-precluded routine plant shutdown.
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l Steam impingement also destroyed several non safety-related instruments which were mounted on a panel board located 6 feet from the failure. Two of four turbine steam header pressure transmitters were among the instruments destroyed and were the reason for the loss of indication of steam header pressure. Safety related steam generator header pressure instruments were not affected.
Other than the aforementioned equipment, no significant structural or equipment damage was noted, nor was there evidence of pipe whip. Two.
personnel suffered steam burns, were hospitized overnight and released.
The rupture occurred in the outside radius of a 375 mil thick 90 elbow where a 24" steam extraction line branches off a 42" high pressure turbine exhaust line.
Ultrasonic thickness testing performed on the elbow in March 1982 revealed significant erosion thinning had occurred, but that the elbow was still serviceable. At that time the thinnest area recorded was 170 mils; micrometer readings performed after the rupture revealed a thickness of 17 mils at the edge of the failure.
The elbow has been replaced, other suspect extraction piping has been inspected, the equipment supplied from MCC 2XA-A has been temporarily supplied from alternate sources, and at the end of this report period Unit 3 is heating up and is scheduled to be critical on July 11.
The NRC Region II office became aware of the event at 2:21 p.m. when the resident inspector notified the project coordinator of a possible main steam line break. At 2:30 p.m. the Region II Emergency Response Center was activated in order to facilitate evaluation of the ongoing event and assist the licensee.
In subsequent conversations with the resident inspector and licensee it was discerned that the reactor was stable and in controlled cooldown.
Region II dispatched two inspectors to the site at 3:15 p.m. to evaluate the failure, analyze the transient in terms of reactor-operator response, and determine the radiological effects of the event.
The results of the inspection are documented in this report. The regional office also drafted a proposed Information Notice to disseminate the information surrounding the event to the industry.
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Reactor Transient Response As previously stated, the reactor was manually tripped 9 seconds after the steam rupture, effectively isolating the fault. Post trip plant response was as follows.
T-hot decreMed to 550 F at the trip, increased to 559 F due to secondary system isolations performed by the operators attempting to locate the
'I rupture, then slowly decreased, resulting in a cooldown of approximately l
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58'F during the first hour following the trip. Reactor coolant system pressure ranged from 1816 psig to 2200 psig, ultimately being maintained at 2175 psig during the first 15-20 minutes following the trip.
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Main steam pressure, as measured at the steam generators, peaked at 1097 psig, ultimately stabilizing at approximately 1000 psig. Neither the pressurizer code safety valves nor the power operated relief valve (PORV)
were called upon during the transient; primary and secondary levels remained on scale, within acceptable range; and no Engineerad Safety Features (ESF)
setpoints were reached.
Initial reports were that the rupture was in the
"A" main steam line.
In an attempt to isolate the rupture the operators isolated the "A" generator.
In subsequent actions the operators sequentially isolated and un-isolated both steam generators and the steam bypass valves in their attempts to locate and isolate the rupture.
During the foregoing efforts to isolate the rupture, it was reported to the
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l operators that one or more of the main steam relief valves were stuck open.
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As a result of this information, the operators isolated the steam bypass valves opting to employ the main steam relief valve (s) as prime heat sink, a measure taken to pre-empt the possibility of an overcooling transient. Once the location of the rupture was ascertained, the bypass valves were unisolated, a normal cooldown rate was established, and the main steam relief valves closed.
Preliminary evaluation of the transient and parameter recordings indicates that the main steam relief valves did not stick or hang open but responded as would be expected for the set of circumstances described.
Seven minutes into the event, the unit experienced the loss of the process computer for a period of 3.5 minutes. Discussions with licensee computer technicians revealed that the loss was apparently the result of a computer stall, a computer malfunction during which the computer either slows down drastically or quits. The computer was reinitialized with no major difficul ty. The computer malfunction is currently being evaluated in the licensee's corporate office to determine cause and corrective actions.
The reactor coolant subcooling margin monitors are supplied from the process computer and were for that 3.5 minutes inoperable. The operators ascertained subcooling during the period from RCS temperature and pressure indications available in the control room. Loss of the computer posed no major impedence to the shut down of the plant.
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Radiological Evaluation The inspector reviewed the air samples taken by the licensee during the event and also reviewed the calculations performed to determine the magnitude of release of radioactive materials to the environment from the steam line rupture.
The licensee calculated the total release to the environment from the event to be 0.3 millicuries. This quantity of material released to the l
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unrestricted area is insignigicant in terms of off-site dose. The inspector stated that f urther review of the licensee's action and calculation would be conducted upon finalization of the licensee's report on the event and during the next routine inspection.
(IFI50-270/26-1).
8.
Materials Evaluation An NRC Region II materials inspector was dispatched to the site to evalute the rupture in terms of failure mode, history preceding the rupture, corrective measures, and the established NDE program. The inspector examined the proximity of the failure, the new elbow which had been installed and the failed elbow.
Discussions with the licensee revealed that in August 1976, a 12" extraction line had failed due to steam erosion at a weld. The erosion was attributed to a misaligned backing ring which caused eddy currents in the steam flow.
At that time, the licensee initiated an informal, undocumented ultrasonic (UT) thickness examination program to detect similar areas of erosion degradation.
In 1979 an Oconee Unit 3 24" steam extraction elbow, identical to the one which ruptured on Unit 2, developed a small leak. Analysis revealed that the leak was attributable to steam erosion.
Subsequent to the 1979 event, the licensee formalized their UT thickness inspection program in procedure MP-0-B-3005-06, " Procedure for Periodic Inspection of Extraction Piping Wall Th'ckness." The procedure required only that the measurements be performed 90 apart around the pipe but did not specify a grid map nor location of the measurements, such that subsequent inspection had no substantial correlation to the preitous inspections.
Subsequent to the current extraction line failure, the licensee inspected fifteen extraction line fittings on Oconee Units one and two. A detailed 4"x4" grid map was marked on the areas being examined, providing for test correlation / comparison and more detailed analysis.
A July 1, 1982 UT examination of extraction piping on Oconee unit one, which was operating at full power, revealed an area of approximately 4"x4" which had been eroded from 375 mils to 100 mils, which is below the minimum wall thickness for that schedule pipe as delineated in ANSI B31.1.0-76.
Unit power was reduced, a patch welded on, and power returned to 100%. The licensee plans to replace the elbow during the next outage of adequate duration. The licensee also plans to inspect main steam system piping upstream of the main steam stop valves on Oconee Unit 3 in July 1982.
In retrospect, the most recent failure on Oconee Unit 2 appears attributable to steam erosion which was accelerated by sustained reduced power operation resulting in lower quality steam in the line.
The licensee is currently re-evaluating their program of examination of the extraction lines.
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