IR 05000338/1989020
| ML20246E728 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 06/28/1989 |
| From: | Blake J, Coley J, Economos N NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20246E726 | List: |
| References | |
| 50-338-89-20, 50-339-89-20, GL-89-04, GL-89-4, IEIN-82-37, IEIN-85-065, IEIN-85-65, NUDOCS 8907120370 | |
| Download: ML20246E728 (9) | |
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.' UNITED STATES
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' NUCLEAR REGULATORY COMMISSION
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(%4 1 eport Nos.i ;50-33P/89-20 and 50-339/89-20 R
{fyy. 'L1censeet LVirginia; Electric and Power Company w'
Glen. Allen, VA 23060 Docket.Nos;: 150-338 and 50-339'
License Nos.:
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' TFacility Name:. North Anna 1 a'nd 2
. Inspection Conducte :
/,. _ { ;5-9 and 12-13, 1989
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Ma er 1-'and. Processes Section
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SUMMARY.
Scope:
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.This ~ routine, announced," inspection was conducted in the areas of review and L
evaluation of tindicationsi discovered during the ten year ultrasonic examination of Lthe.. Unit-1-reactor pressure vessel; observation of -inservice activities, l.y
' review of.-previously identifiedzinspector followup items, and followup on NRC
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Information. Notice.No. 85-65, " Crack Growth.in Steam' Generator Girth Welds."
Results:
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InLthe areas; inspected, violations or deviations were not identified.
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1The: inspectors 1 ascertained that ' the subject indications.were evaluated in i~
accordance with; code. requirements. and with sufficient conservatism to assure
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Followup performed by the inspectors on NRC Information Notice.
p-safeloperation.
l tNo.' 85-65 also confirmed the licensee's-conservatism to assure safe operation-
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by. their effective use of' augmented examination methods to confirm material soundness on the Unit-1 and;2 steam generators,(S/G).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees
- M. L. Bowling, Assistant Station Manager
- D. R. Dodson, Corporate NDE Level III
- R. F. Driscoll, Manager QA G. E. Kane, Station Manager i
- P. Kemp, Supervisor Licensing W. L. Stewart, Senior Vice President Nuclear
- H. L. Travis, Supervisor NDE Services M. Walker, ISI Supervisor, North Anna Power Station Other licensee employees contacted during this inspection included engineers, technicians, and administrative personnel.
Dynacon Systems Inc.
F. J. Dodd, Level III NDE Examiner Westinghouse (W)
D. Kurek, Senior Engineer Level III, Nuclear
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L. Markle, Coordinator, Reactor Pressure Vessel Examination e
NRC Resident Inspectors J. Caldwell, Senior Resident Inspector L. King, Resident Inspector
- J. Munro, Inspector
- Attended exit interview 2.
Action on Previous Inspection Findings Units 1 and 2, (92701)
a.
(Closed) URI 50-338, 339/87-41-01, Maximum Limiting Stroke Time on IWV Valves
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i This item was identified when the inspector noted that limiting I
stroke times for ASME Code Section XI valves were not commer.surate with the actual full stroke times.
Limiting parameters of full i
l stroke times were related to particular system resr.onse times rpecified by the station's Technical Specification 05).
In response to this observation, the licensee developed a program to administratively address actual valve stroke times for each power operated valve in the station's pump and valve Test Program Plan.
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This work effort was performed by the licensee under engineering work request, EWR 88-050 which was approved by the. Station Nuclear Safety and Operating Committee on February 18, 1989.
The basic mettadology behind.the administrative limits is to allow a valve's stroke time to
' increase from. its typical time at a rate slightly below the ASME delta ~ stroke.-time requirements for three consecutive tests before identifying 'the valve as e potential problem.
The valve typical stroke times were developed by' averaging.the valve's past stroke test performance.
If the typical stroke. time was less then 2 seconds,-the administrative limit.was set at 4 seconds.
If the typical ' stroke time was 10 seconds' or greater, the administrative limit was set at 1.728 times the typical.' stroke time (based on an increase of'20% over three consecutive tests).
If the typical stroke time was equal to 2.
seconds,. the administrative limit was set at 5.488 (based on an increase of 40% over three consecutive tests). 'Those valves with typical stroke times between 2 and 10 seconds were assigned administrative limits based on a linear interpolation between 'the administrative: limits for 2 and 10 seconds.
Implementation of these administrative limits is accomplished through ADM ISI-2.0, ASME Section XI Pump and Valve Program.
D'scussion with the licensee's cognizant engineer disclosed that this e ea is currently under further review in response to Generic Letter No. 89-04.
The inspectors reviewed completed inservice test procedures and the calculated. basis for the acceptance ranger and stroke times for
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. valves in the following system:
Periodic Test No.
Date Performed System Valve No.
1-PT-213.21 April 17,1989 Auxiliary Steam
.FCV-AS-100A and -100B 1-PT-213.9 May 12, 1989 Safety Injection TV-SI-100, -101,
-1842, -1859; TV-1884A, l-1884B, -1884C 2-PT-213.5 May 18, 1989 Miscellaneous Numerous i
2-PT-213.2C April 21, 1989 Charging Pump MOV-2270A, B, (NOVs)
MOV-2286C, MOV-22870, MOV-2275C*
- This valve failed its original test due to the manual engagement of the handwheel.
The manual engagement was released and the valve tested satisfactorily on May 3, 1989.
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(0 pen) IFI. 50-338/88-17-01, Rework Governor Valves #2 and #3 and
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Associated Dump Valves
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This item was identified in response to a review of LER 338-88-13-00 dated March 19, 1988, and the circumstances which led to a Unit-1 automatic reactor trip from low power level on March 19, 1989.
The trip occurred while the turbine speed control was being transferred from the throttle valve to governor valve control as the turbine was being placed in operation.
Following a review of various reports on circumstances which contributed to the trip, the inspectors ascertained that the dump valves, associated with governor valves #2 and #3, would not seal satisfactorily following valve actuation.
Commitment #01-88-5148-003 was issued to inspect all control valve actuators and associated dump valves during this (1989) refueling outage.
This commitment was applicable to both units.
A review of maintenance records disclosed that all Unit-2 control valve actuators and dump valves were inspected and repaired, as necessary, and stroke and pressure tested satisfactorily.
Of the four valves involved, valve "C" exhibited poor seating contact and required light machining to obtain 100% contact.
The repair work was performed under the following work orders:
Valve Work Order No.
02-MS-G0V-1A 5900080497 02-MS-G0V-1A 5900080495 02-MS-G0V-1C 5900080493 02-MS-G0V-10 5900080492 These records were reviewed for completeness and accuracy.
In that no work had been done on Unit-1 valves, this item will remain open for a future inspection.
3.
Reactor Pressure Vessel, Ten Year Inservice Examination, Data Review and Evaluation, Unit 1 (73755)
On May 30, 1989 the licensee's cognizant engineer contacted the inspectors to report that the Automated Ultrasonic inservice inspection (ISI) of the Reactor Vessel had revealed code rejectatie indications in the flange-to-vessel weld, identified as welu No. 1, and in the vessel-to-outlet "B" nozzle weld, identified as weld No. 11.
On June 6-9, 1989 the inspectors visited the North Anna Power Station and discussed the details of the inspection findings with representatives of W and Dynacon.
Through these discussions the inspectors ascertained that the indication in the flange-to vessel weld was detected during the 60 degree shear wave automated examination.
The indication was circumferential, lying within the weld joint, near the weld centerline.
The peak amplitude of the indication occurred at a depth of 10 inches from the sound entry
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surface.
This corresponds to the vessel wall thickness which led to the supposition that the indication might have been from a surface associated flaw.
The indication was found to have a length of 12.75 inches and a maximum depth of 1.37 inches.
On_ the basis of this data and on the supposition that a surface related flaw existed, W performed a preliminary fracture mechanics analysis to assess the effect of the indication on ' the integrity of the reactor vessel.
The analysis was performed using the rules of ASME Code,Section XI (Code).
Results were subsequently plotted on a flaw evaluation chart constructed to present the largest flaw meeting the acceptance criteria of ASME Code Sections III and XI regardless of flaw shape.
The chart showed the plotted indication was acceptable.
Concurrently, Dynacon using data imaging capabilities of the Ultrasonic Data Recording and Processing System (UDRPS), performed detailed analysis of the computerized data obtained from the 0, 45 and 60 examinations.
This analysis showed that no evidence of a corner trap signal existed, that the ligament between the indication and the outside surface of the vessel was approximately one inch, that the linear target (indication) had no resolvable through wall dimension, and no defraction tip signals, characteristic of a p?anar flaw, were -observed.
By using_ the resolution limit of a 2.25 MHz shear wave transducer, the cognizant engineers determined that the conservative upper limit on the through wall dimension of the target / indication was 0.15 inches.
The data image analysis also showed that affects from entry surface variations and vessel geometry at the target location combined to place the indication on the OD surface of the vessel.
On the basis of this analysis, it was determined that the subject indication was caused by a linear slag inclusion, one inch below the outer surface of the vessel.
To corroborate this conclusion the licensee performed a supplemental manual contact ultrasonic examination in the area of interest from the OD surface of the vessel.
This examination was performed using 45 and 0 transducers.
A liquid penetrant examination was also performed in this area to check for possible surface indications.
Results of these examinations showed that no surface indications / flaws existed in the area of interest.
The indication (slag line) was detected with the 45' and 0 transducers at a depth of about 0.9 inches.
Considering the sensitivity level required to detect the indication from the outside surface, it was estimated that the response from the indication would have been below the recording criteria in the preservice contact ultrasonic examinations.
In the 45 degree manual contact scans, estimates of peak depth and linear extent were consistent with results obtained in the automated exams.
In the 0 degree scans, numerous intermittent responses were noted at an average depth of 0.9 inches, along the 45 degree detection lines.
Numerous lower amplitude (comparatively) responses were noted near the slag stringer line which were interpreted as porosity.
On May 31, 1937 the licensee's cognizant engineer telephoned the I
inspectore tr report that two code reportable indications had been detected or the
"B" outlet nozzle shell weld number eleven (11).
One
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l indication was located at the 32 azimuth (indication #3) and the other (indication #1), at the -131 azimuth loo' king from the vessel interior at the nozzle.
Indication #1, had a length of.1.28 inches and a width of 1.4 inches, its edge was estimated at 2.96 inches from the closest wall.
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Indication #3 had a length of 1.3 inches and a width of 1.24 inches with
'its edge at a distancr of 1.68 inches from the closest wall.. Along with the previously discussed vessel weld indication, the inspectors reviewed the ISI data with the.' licensee and ascertained the following.
Using supplemental beam angles and imaging techniques with UDRPS, the licensee determined that indication #1 consisted of two slag lines, which appeared to be connected.
The indication exhibited a maximum through wall dimension of 0.4 inches and therefore, it was within allowable limits of Table IWB-3512-1 of the Code.
In reference to indication #3 the data imaging analysis showed no defraction tip signals or other planar characteristics.
The lack of any resolvable sizing features indicated the target (indication) was smaller than the transducer's resolution limit, which was calculated to be 0.101 inches.
Therefcre, indication #3 was evaluated as a single slag line having a maximum through wall dimension of 0.15 inches.
The licensee therefore concluded that the indication was within the allowable limits of Table IWB-3512-1 of the Code.
The licensee will prepare and submit to the Commission a report on this outage with thirty days following outage completion.
l Within the areas of inspection, no violations or deviations were l-identified.
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Inservice Inspection - Observations of Work and Work Activities, Unit-1 4.
(73753)
The inspectors observed examination activities, reviewed NDE equipment and materials certification records, and reviewed NDE personnel qualifications for personnel that had been utilized during the required ISI examinations during this outage.
The observation (s) and reviews conducted by the inspectors are as follows:
l The inspectors observed calibration activities and the ultrasonic
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examination being conducted on the safety injection system, drawing i
number VRA-2-2540 Rev. O, Weld #18, 6" dia. schedule 40 pipe.
The observations were compared with the application procedures and ASME Code Section XI (74575), in the following areas:
availability of and compliance with approved NDE procedures; use of knowledgeable NDE personnel; use of NDE personnel qualified to the proper level; type
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of apparatus used; calibration requirements; search units; beam l
angles; DAC curves; reference level for monitoring discontinuities; i
method of demonstrating penetration; extent of weld / component examination coverage; limits of evaluating and recording indications; recording significant indications; and, acceptance limits, as
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applicable.
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The following listed ultrasonic equipment and materials certification
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records were reviewed:
Ultrasonic Instrument l
Manufacturer /Model Serial No_._
Sonic, Mark 1 11225E The inspectors reviewed spectrum analysis data for the ultrasonic transducers listed below:
Serial No.
Size Frequency B18237 0.25" dia.
5.0 MHz 21114 0.25" dia.
2.25 MHz Ultrasonic Couplant Batch Number 8872 Ultrasonic Calibration Block VRA-12 Surface Thermometer, PTC Instruments, Model 312F, S/N-60.
Within the areas of inspection, no violations or deviations were identified.
5.
IE Information Notice No. 86-65, " Crack Growth in Steam Generator Girth
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Welds" - Review of Completed Data In 1982 Indian Poin'
tation Unit 3 had a leak at Weld No. 6 on one of their S/G (see infor, nation Notice 82-37).
Weld No. 6 is a full pene-tration circumferential weld located in the transition zone between the tube bundle and steam dryer areas, below the feedwater nozzles, and subject to thermal cycling.
The crack was started by corrosion and operating temperature fluctuations which caused it to grow through the wall due to low-cycle fatigue.
In 1983 Surry Power Station Unit 2 performed ultrasonic examinations of the No. 6 S/G welds.
The original construction weld (Weld 6) on Unit 2 is six inches above the weld that att. ached the lower portion of all three replacement S/G in 1980.
The examination showed widespread indications of discontinuities on the inside surface of this weld in the "A" S/G.
None of the indications were large enough to be rejected and were assumed to be surface blemishes or reflections of weld geometry.
In March 1985, an ultrasonic reexamination was performed on the original construction weld at Surry, and larger, but acceptable, discontinuities were found in the same locations.
The inside surface of the weld in S/G "A" was visually examined, but no defects were seen.
However, when magnetic particle testing was performed, at the request of the NRC, closely spaced linear cracks were found over a large portion of the circumference.
The
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l appearance of these cracks were similar to those at Indian Point.
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safety. significance is that substantial loss of secondary coolant could occur without warning if cracking degradation continued undetected.
The cracks in S/G "A" at Surry were in a narrow band at the upper edge of the weld and covered almost the entire inside diameter.
The cracks were as deep as 1/2 inch and were covered by surface oxide, which obscured detection by visual inspection.
S/Gs
"B" and
"C" at Surry also had numerous, smaller, circumferential cracks in the same location.
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surface cracks in all three S/Gs were removed by grinding; repair welding was not necessary.
Weld No. 6 was made on-site and had high residual stresses as a result of the low preheat and post weld heat treatment
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temperatures.
The material in the vicinity of the weld apparently pitted as a result of high oxygen concentrations (higher than 25 ppb) and contaminants such as chlorides and copper ions in the secondary water.
In addition to internal pressure, this portion of the S/G has a change in cross-section and undergoes thermal cycling.
Heat treatment of the nearby replacement weld in 1980 reduced the residual stresses, but could not heal any existing damage to the original construction weld.
On June 12 and 13, 1989, the inspectors held discussions with cognizant plant personnel, reviewed completed nondestructive examination records and reviewed the Westinghouse / Virginia Power Steam Generator Advisory Committee minutes of November 5, 1986, to determine whether licensee actions taken in response to NRC Information Notice No. 85-65 were sufficient to detect crack growth in the North Anna steam generator girth welds.
The inspectors review of ultrasonic examination reports and licensee memorandums revealed that indications had been reported in the Unit 1 S/G "B".
The indications were small and were not of sufficient amplitude to be recordable in accordance with the ASME Code (74S75).
However, as result of these findings in November of 1985, the licensee conducted magnetic particle examinations of the internal surface of S/G "B" in Unit 1 and S/G
"A" in Unit 2.
These magnetic particle examinations were performed at four locations, 90 degrees apart, and extended 24 inches at each location.
No cracks were revealed as a result of the examinations.
In addition, a Westinghouse / Virginia Power Steam Generator Advisory Committee reviewed pre-and post-weld heat treatment records for both Units 1 and 2 S/Gs and concluded that North Anna's welds had been subjected to favorable stress relief temperatures and times and, therefore, cracking noted at Surry and Indian Point was not expected to occur at North Anna.
The licensee's actions were determined to be adequate to resolve this issue and the inspectors consider this issue closed.
Discussions with the licensee indicate that the licensee plans to replace the S/G tube bundles and possibly the entire generators in their scheduled
. stage starting in 1993.
Within the areas examined, violations or deviations were not identified.
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Exit Interview i
The inspection scope and results were summarized on June 9 and 13,1989, with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection results listed i
above.
Proprietary information is not contained in this report.
' Dissenting comments were not received from the licensee.
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