ML13317B240
| ML13317B240 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 11/30/1990 |
| From: | Southern California Edison Co |
| To: | |
| Shared Package | |
| ML13317B236 | List: |
| References | |
| NUDOCS 9012070091 | |
| Download: ML13317B240 (28) | |
Text
1990 STEAM GENERATOR INSPECTION RESULTS SAN ONOFRE UNIT 1 DOCKET NO. 50-206 NOVEMBER 1990 SOUTHERN CALIFORNIA EDISON COMPANY ROSEMEAD, CALIFORNIA 901 2 CY09T 901f:29 F'DR ADOCK 05000206 G!PDC
Table of Contents Section Page I. Introduction 1
II. Technical Specification Inspection 2
A. Introduction 2
B. Steam Generator Leak Test/Corrective Action 2
C. Eddy Current Testing/Corrective Action 3
D. Summary/Conclusions 7
III.
Cold Leg Top of the Tubesheet Indications 9
A. Introduction 9
B. Results 9
C. Conclusions 10 IV. Primary Side Roll and Roll Transition Cracking 11 A. Introduction 11 B. Results 11 C. Conclusions 12 V. Secondary Side Circumferential Indications 14 A. Introduction 14 B. Results 14 C. Conclusions 15 VI.
Wrapper Support Bar Inspection 16 A. Introduction 16 B. Results 16 C. Conclusions 16 VII.
Steam Generator Inspection Summary and Conclusions 17 A. Summary of Results 17 B. Conclusions 17 VIII.
References 18 Appendix A - SG-A, SG-B, and SG-C Tubesheet Maps Showing Tubes Inspected Appendix B - San Onofre Unit 1 Steam Generator Tube Axial Location Illustration Appendix C - Inspection Results for Tubes with Defects Below the Uppermost Inch of Sound Roll
I.
INTRODUCTION On June 30, 1990, San Onofre Unit 1 began the Thermal Shield Support Replacement and Cycle 11 Refueling Outage. As part of this outage, the steam generator tubing was inspected in accordance with the San Onofre Unit 1 Technical Specification (TS) 4.16, Inservice Inspection of Steam Generator Tubing. The purpose of this report is to provide detailed results of the steam generator inspections performed during the outage to facilitate the NRC review of these results and approval of the corrective action taken at San Onofre Unit 1 as it relates to the inspection of steam generators.
Consistent with the provisions of TS 4.16, an inspection was performed addressing requirements for random surveillance of the steam generator tubing and previously detected degradation. The last such inspection was conducted in March 1988. Further, in accordance with References 1 and 2, a secondary side inspection was conducted to visually inspect the intact wrapper support bars. The purpose of this inspection was to verify the bars had remained intact during operation and did not require removal.
Section II of this report contains the TS inspection program description, results, corrective actions, and conclusions.Section III.
of this report contains the cold leg top of the tubesheet indications introduction, results, and conclusions.Section IV contains the roll and roll transition primary side crackingtintroduction, results, and conclusions.Section V contains the secondary side circumferential indications introduction, results, and conclusions.Section VI contains the wrapper support bar inspection description, results, and conclusions.Section VII summarizes the overall conclusions derived from the inspection program. Finally,Section VIII provides a listing of the references used in this report.
1
II. TECHNICAL SPECIFICATION INSPECTION A.
Introduction The San Onofre Unit 1 TS steam generator tubing inspection was performed during August 23, 1990, through September 7, 1990. The previous technical specification inspection was performed in March 1988. Southern California Edison's request to conduct the next steam generator tube inspection during the Thermal Shield Support Replacement and Cycle 11 Refueling Outage commencing June 30, 1990, rather than by March 7, 1990 was approved by U. S. Nuclear Regulatory Commission Order (Reference 3).
The March 1988 and earlier inspection results indicated that steam generators "A", "B", and "C" (SG-A, SG-B, and SG-C) are behaving in a like manner. Based on TS 4.16.A.3, which allows the inspection of steam generators on a rotating schedule if they are performing in a like manner, SG-A was selected for the inspection.
The inspection plans, results, and conclusions are discussed below.
B.
Steam Generator Leak Test/Corrective Action
- 1.
Description San Onofre Unit 1 was experiencing a steam generator primary, to secondary leak of approximately 15 gallons per day (gpd) when the plant shut down on June 30, 1990. This leakage had been detected during the Cycle 10 fuel cycle and slowly increased to 15 gpd before shutdown. This leakage was well below TS limits for the steam generators. Since this leakage had been detected during the fuel cycle, a leak test had been planned to identify and remove the leaking tubes from service.
- 2.
Results and Corrective Action The secondary side of all three steam generators was pressurized to approximately 650 pounds per square inch and the primary side of the tubesheet in each steam generator channel head was scanned for leaks using.a pan and tilt camera. No leakage was observed in any cold leg channel head. A total of thirteen leaking tubes were identified in the hot leg channel heads. All leaking tubes are sleeved on the hot leg end. The breakdown of leaking tubes per steam generator is shown below:
2
Tube Number Type of Sleeve Leak Rate SG Row - Column (Upper Joint)
(Drops/Minute)
A 9 - 43 Braze 0.25 B
37 - 52 Mechanical 0.5 36 - 52 Mechanical 0.1 C
35 - 61 Mechanical 5.0 34 - 48 Mechanical 1.7 31 - 67 Mechanical 1.1 30 - 64 Mechanical 0.9 34 - 62 Mechanical 0.2 35 - 41 Mechanical 0.2 34 - 53 Mechanical 0.1 34 -
51 Mechanical
<0.1 34 - 64 Mechanical
<0.1 35 - 42 Mechanical
<0.1 All leaking tubes were inspected with eddy current over their full length, including the sleeved portion. There were no eddy current indications which correlated to the leakage. All leaking tubes-were.removed from service by mechanical plugging.
- 3.
Conclusions It is inferred that the observed leakage is associated with the sleevejoints based on the lack of correlatable eddy current indications.
The leakage for each leak limiting sleeve was within the design basis as discussed in Reference 4 (210 drops per minute).
C.
Eddy Current Testing/Corrective Action
- 1.
Description The conventional bobbin coil probe was used to provide the best possible assessment of the general condition of the inspected length of the non-sleeved portion of the steam generator tubes. The 8x1 probe and motorized rotating pancake coil (MRPC) probe were used to supplement the bobbin probe when necessary. The magnetically biased bobbin probe and the crosswound probe were employed to assess the condition of the sleeves inspected.
3
The general eddy current testing-programeconsisted of inspecting the non-sleeved length of 300 steam generator tubes in SG-A (at least 3% of the total number of tubes in service in all steam generators). In addition, the sleeved portion of 412 tubes (6.5% of the total number of sleeved tubes in service in all steam generators) was inspected.
Unsleeved tubes for two pitches around the sleeving boundary and a random pattern in the remaining.peripheral tubes were inspected from the hot leg tube end through the lowermost hot leg support. Inspection of these 474 unsleeved tubes (12.7% of the total number of unsleeved tubes in service in all steam generators) served the dual purposes of detection of indications of secondary side intergranular attack (IGA) at the top of the hot leg tubesheet and detection of primary side roll and roll transition cracking near the hot leg tube end. Also, previous eddy current indications in SG-A, greater than or equal to 20% through-wall, were inspected.
The inspection of the cold leg indicated there were tubes with imperfections in excess of the plugging limit at the top of the cold leg tubesheet in SG-A. As a result of identifying these imperfections it was necessary to inspect three percent of the tubes in one of the uninspected steam generators (SG-C was chosen) in accordance with TS 4.16.8.1.
Also, since these imperfections were in excess of the plugging limit, this required inspection of an additional
'three percent of the tubes in SG-A and inspection of three percent of the tubes in SG-B and SG-C in accordance with Technical Specification 4.16.B.2. The increased inspection in SG-A included the tubes necessary to surround all defective tubes by two pitches. A total of 1794 of the tubes (53.4%) in SG-A were inspected at the top of the cold leg tubesheet, significantly exceeding all possible expansion criteria, including any that may have been required by that of TS 4.16.B.3 (6% of the tubes in SG-A).
A total of 6 tubes with imperfections in excess of the plugging limit at the top of the cold leg tube sheet in SG-A were found. Based on eddy current testing results for SG-B and SG-C no tubes with imperfections were found in these steam generators at the top of the cold leg tube sheet.
4
Three imperfections were found in excess of the plugging limit between the top of the hot leg tubesheet and the lowermost support in SG-A. As a result of identifying these imperfections it was necessary to inspect three percent of the tubes in one of the uninspected steam generators (SG-C was chosen) in accordance with TS 4.16.B.1.
Also, since these imperfections were in excess of the plugging limit, this required inspection of an additional three percent of the tubes in SG-A and inspection of three percent of the tubes in SG-B and SG-C in accordance with TS 4.16.B.2. The increased inspection in SG-A included the tubes necessary to surround all defective tubes by two pitches. Based on the eddy current testing results for SG-C no imperfections in excess of the plugging limit were found. The increased inspection in SG-B identified one imperfection in excess of the plugging limit prompting inspection of an additional 6%
of the tubes in SG-B in accordance with TS 4.16.B.3. Three tubes were identified by this additional inspection as having imperfections in excess of the plugging limit. Two tubes were identified by this additional inspection as having secondary side circumferential indications at the top of the hot leg tubesheet, and were conservatively handled in the same manner as defective tubes would be. Additional inspection was-performed to surround all defective tubes in SG-B by two pitches and gain data beyond that required by the TSs. A total of 998 tubes (76.8% of the unsleeved tubes in SG-B) were tested in the SG-B expansion sequence.
Tubesheet maps showing inspected tubes in SG-A, SG-B, and SG-C are provided in Appendix A.
- 2.
Results and Corrective Action As a result of the general technical specification and additional eddy current testing program, a total of 16 tubes were removed from service. This consists of 10 tubes in SG A and 6 tubes in SG-B as listed in the following table.
Appendix B provides an elevation view of the steam generator illustrating the axial location designations used in the listing.
5
Tube Number Flaw Size Axial SG Row - Column
% Throuqhwall Location A
30 - 32 67 TSC + 3.0 33 - 38 57 TSC + 3.0 33 - 41 53 TSC + 3.0 27 - 52 53 TSC + 7.9 4 - 18 51 TSC + 0.5 34 - 42 50 TSC + 2.2 40 - 36 94 TSH + 2.9 40 - 38 63 TSH + 6.6 15 - 70 50 TSH + 42.7 1 - 68 Note (1) 01H B
45 -
51 DRI/IDI (2)
TEH + 2.0 34 - 71 DRI/IDI TEH + 1.9 25 - 79 DRI/IDI TEH + 2.2 28 - 79 DRI/IDI TEH + 2.6 34 - 33 DTI/SCI (3)
TSH + 0.2 35 - 34 DTI/SCI TSH + 0.0 Notes:
(1) Restricts passage of a 0.460" diameter probe (2) DRI/IDI - Distorted roll indication per bobbin probe, Inside diameter indication per MRPC probe.
(3) DTI/SCI - Distorted tubesheet indication per bobbin probe, Secondary side circumferential indication per MRPC probe.
Section III addresses cold leg top of tubesheet indications (six tubes removed from service) in detail.
Section IV addresses primary side roll and roll transition cracking (four tubes removed from service) in detail.
Section V addresses secondary side circumferential indications (three tubes removed from service) in detail.
The following paragraphs address the three remaining tubes removed from service.
The defect in SG-A tube 40-38 is in the parent tubing above the sleeve. It is a typical hot leg "volumetric" (not crack-like) indication whose elevation above the hot leg tubesheet is not unusual.
It is representative of other indications previously found in tubing at the same elevation. Surrounding tubes within two pitches of this tube were inspected and found to be free of defects.
6
The defect.in SG-A tube 15-70 is in the.parent tubing above the sleeve in a typically unflawed axial location. It is not associated with any support structure in the steam generator. It is 42.7 inches above the hot leg top of the tubesheet, 12.7 inches above the top of the sleeve and 2.5 inches below the lowermost hot leg support plate.
Surrounding tubes within two pitches of this tube were inspected and found to be free of similar indications. No similar indications have been noted in any of the tubes inspected during this inspection or previous inspections.
Tube 1-68 in SG-A restricted passage of a 0.460 inch diameter probe at the lowermost hot leg support. This tube restricted passage of a 0.500 inch diameter probe in previous inspections. Considering the accuracy limitations of the gaging technique, the isolated nature of this indication, and other available data, this restricted tube does not alter the previous conclusion (Reference 1) that denting is not progressing.
- 3.
Conclusions The tubes selected for this inspection included random tubes and tubes in critical areas identified by Unit 1 and other similar plant experience. All tubes classified as defective,.based on eddy current testing results, were removed from service by mechanical plugging. Other tubes were preventively removed from service by mechanical plugging -consistent with eddy current testing results.
D.
Summary/Conclusions A total of 3,949 tubes were inspected (39.5% of the tubes in service), and 29 tubes were removed from service by mechanical plugging. Tubesheet maps showing inspected tubes in SG-A, SG-B, and SG-C are provided in Appendix A. The 29 tubes which were plugged included:
13 leaking sleeves 6 defects at the top of the cold leg tubesheet 4 indications of primary side hot leg roll transition cracking 3 secondary side top of the tubesheet circumferential indications 2 defects in parent tubing above hot leg sleeves 1 tube restricting passage of a 0.460 inch diameter eddy current probe 7
.This inspection has demonstrated that.limited.progression of previously identified degradation mechanisms has occurred. These mechanisms include secondary side degradation at the cold leg top of tubesheet, primary side roll transition cracking, and secondary side circumferential indications at the hot leg top of tubesheet.
There has been no detectable progression of denting, anti vibration bar wear, or sleeve degradation.
This inspection has further demonstrated that this limited degradation progression can be monitored in subsequent routine inspections, and defective tubes removed from service in a timely manner. Accordingly, it is concluded that the remedial action taken (plugging) is appropriate to resolve steam generator tube degradation identified during this inspection and no further action is required.
8
III.
COLD LEG.TOP OF THE TUBESHEET INDICATIONS A.
Introduction Degradation on the secondary side of the tubing at the cold leg top of the tubesheet has been noted at San Onofre Unit 1 since 1978. Significant inspection in this region of the tube bundle started at this time in response to increasing industry awareness of the potential for degradation in regions other than the hot leg and U bend regions. The degradation is dispersed throughout the region of the tube bundle in which a sludge pile is expected.
However, indication depths tend to be stable, and rarely exceed the plugging limit.
As reported in Reference 5, apparent growth of indications in this region in 1985 prompted comparison of a population of 296 indications, using data collected in 1980 as a baseline. The results of this comparison and subsequent evaluation in 1988 (Reference 1) indicated growth of indications in this region is very limited.
B.
Results A total of.2398 tubes (1794 in SG-A, 303 'in SG-B, and 301.in SG-C) were inspected at the top of the cold leg tubesheet to monitor growth of indications in this region. Using the results of this inspection, 260 of the indications previously compared in 1985 (indications in those tubes remaining in service) were compared over a three fuel cycle interval from 1980 to 1990 with the following results:
Number of Average Growth Rate SG Indications Compared (Percent Throuqhwall Per Cycle)
A 171
-1.09 B
36
-0.68 C
53
-1.01 In addition to the foregoing comparison, previous data for the six defective tubes detected in this inspection was re-analyzed using state-of-the-art data analysis techniques to determine the maximum and mean growth rate per fuel cycle. Data from the Cycle 9 (1985)
Refueling Outage was available for comparison with the present Cycle 11 (1990) Refueling Outage data. This provides an interval of two operational cycles. A comparison of the data from these two cycles is provided below. The maximum growth rate from this comparison is 7.5% per cycle for tube 34-42. The mean growth rate for all six indications is 3.8% per cycle.
9
Re-Analyzed Indication Cycle 9 Cycle 11 Growth Tube Axial Indication Depth Indication Depth
(% Per Number Location
(% Throuqhwall)
(% Throughwall)
Cycle) 30 - 32 TSC + 3.0 62 (Note 1) 67 2.5 33 - 38 TSC + 3.0 44 57 6.5 33 - 41 TSC + 3.0 50 (Note 2) 53 1.5 27 - 52 TSC + 7.9 46 53 3.5 4 -
18 TSC + 0.5 48 51 1.5 34 - 42 TSC + 2.2 35 50
7.5 Notes
(1) This indication was recorded as 46% during the Cycle 9 outage; thus this tube was not classified as defective, and accordingly was not plugged., Re-analysis, consistent with Cycle 11 techniques, provides a result of 62%.
(2) This indication was recorded as 43% during the Cycle 9 outage; thus this tube was not classified as defective, and accordingly was not plugged. Re-analysis, consistent with Cycle 11 techniques, provides a result of 50%. This difference in analysis results of 7 percent is within the expected eddy current measurement uncertainty (10%).
C.
Conclusions The results of the comparison of 260 indications over three fuel cycles shows there is no significant growth for the cold leg top of the tubesheet indications when considered as a group.
Although the change in the indications for the six tubes with defects demonstrate that for some individual tubes limited degradation may be progressing, the mean growth rate of 3.8% per cycle for this group is well within that assumed in the safety analysis which defines the basis for the TS 4.16. Therefore, existing requirements to inspect previously identified problem regions during future inspections will ensure corrective actions are performed as necessary to prevent potential failures.
10,
IV.
PRIMARY SIDE ROLL AND ROLL TRANSITION CRACKING A.
Introduction A 100% inspection of the hot leg unsleeved tubes in all three steam generators was done in February 1988 for primary side roll and roll transition cracking. The 147 tubes affected by this degradation mechanism were removed from service. Another 44.tubes with imperfections below the uppermost one inch of sound roll were left in service based on TS 4.16.D.1.e. The results for inspection of the cold leg end of the tubes indicated this problem was not present in the cold leg side.
Comparison of 1985 and 1988 eddy current data was done in 1988 to determine if primary side roll transition zone cracking was active. This comparison showed a slight change in the vertical distortion in only 3 out of the 13 tubes compared.
B.
Results A total of 1610 tubes (43% of the unsleeved tubes in service) were examined in the hot leg roll and roll transition region in the three steam generators using the bobbin probe. Hot leg primary side-roll or -roll-transition cracking was not detected in any of the 474 tubes examined (40%) in SG-A, or any of the 188 tubes examined (15.4%) in SG-C. However, primary side roll transition zone cracking was detected and confirmed in four tubes of the 948 tubes examined (73%) in SG-B.
The 44 tubes with previous imperfections below the uppermost inch of sound roll continue to meet technical specification criteria for remaining in service. Appendix C contains examination results for these 44 tubes as required by TS 4:.16.D.5.
As a by-product of examination for other purposes, 2398 tubes were examined (24% of the tubes in service) in the cold leg roll and roll transition region in the three steam generators. The results of the inspection of the cold leg tubes continues to confirm that this problem is not present in the cold leg side.
A review was conducted in 1990 of 1988 data for all four of the tubes in SG-B with primary side roll transition zone cracking.
All of these indications were present to a limited degree in the 1988 data. A comparative review of the 1990 bobbin probe data for these indications, relative to indications at corresponding locations in tubes removed from service in 1988, provided an order of magnitude estimate of the extent of the cracking depth. This comparison indicated that the signal amplitudes for these four tubes is approximately 30% of the typical signal amplitudes for tubes removed from service in 1988. The small amplitude of these signals indicates that cracking in these tubes is in the early stages.
11
C.
Conclusions The limited number of tubes affected by primary side roll and roll transition cracking, and the small amplitude of the bobbin coil eddy current signals for these tubes indicate that primary side roll and roll transition cracking is not progressing significantly.
Future inspections will provide timely detection of tubes affected by this degradation mechanism. This will support timely removal of defective tubes from service. Leak test results continue to demonstrate that no leakage has been experienced at San Onofre Unit 1 due to this degradation mechanism.
Further, continued growth monitoring of in service tubes with imperfections below the uppermost one inch of sound roll, per technical specifications, will provide for timely removal of appropriate tubes from service.
12
V.
SECONDARY-SIDE CIRCUMFERENTIAL INDICATIONS A.
Introduction San Onofre Unit 1 has a history of secondary side circumferential indications at the hot leg top of the tubesheet. In 1980-1981 approximately 65% of the tubes were sleeved on the hot leg end in response to secondary side circumferential intergranular attack (IGA) at the top of the hot leg tubesheet. Tubes in the unaffected outer periphery of the tube bundle were not sleeved.
In 1988 two unsleeved tubes adjacent to sleeved tubes were identified to have IGA-like indications at the top of the hot leg tubesheet based on MRPC data. Correlation of MRPC data with corresponding bobbin probe data for these two indications indicated that the degradation was less than 20 percent through wall.
These two tubes were removed from service and a detailed report was provided to the NRC (Reference 6).
It was concluded that IGA was not progressing.
B.
Results A total of 1610 tubes (43% of the unsleeved tubes in service) were inspected at the hot leg top of the tubesheet region. This includes 474 tubes (40%) in SG-A, 948 tubes (73%) in;SG-B, and 188 tubes (15.4%) in SG-C. 87% of the unsleeved tubes adjacent to sleeved tubes were inspected.
- 1. SG-A Tube 40-36 One tube (40-36) in SG-A had a 94% through wall outside diameter indication located 3-inches above the top of the hot leg tubesheet. It was detected and quantified using the bobbin coil probe. The MRPC data shows that the indication is circumferentially oriented, is less than 120 degrees (about 3/4-inch) in circumferential extent, and is about 1/4-inch in axial extent. The indication had some, but not all, of the characteristics of IGA, as previously found at San Onofre Unit 1.- The indication was not present on the eddy current test data taken in 1988. Tube 40-36 is adjacent to sleeved tubes. As indicated above, 87% of the tubes adjacent to the sleeved tubes were inspected. Among these tubes it is the only tube with an indication at this or a similar axial location.
Further, unsleeved tubes within two pitches of this tube were inspected using both bobbin and MRPC probes and were found free of defects.
13
Based on the results of the evaluation of tubes "pulled" for evaluation in 1980-1 the occurrence of IGA degradation at 3 inches above the top of the hot leg tubesheet in a tube adjacent to sleeved tubes would not be unexpected. However, experience at San Onofre Unit 1 indicates that the probability is very low for occurrence of IGA at locations other than at the top of the hot leg tubesheet.
Accordingly, it is concluded that the probability of other tubes experiencing IGA, at locations above the top of the tubesheet, is also very low. Further, based on the results of tube pressure testing reported in Reference 7, it is concluded that in the as-found condition tube 40-36 in SG-A had adequate strength to successfully withstand design basis accident conditions.
- 2. SG-B Tubes 34-33 and 35-34 Two tubes (34-33 and 35-34) in SG-B had secondary side circumferential indications detected by the bobbin probe at the top of the hot leg tubesheet. The characteristics of these indications are typical of IGA, as previously found at San Onofre Unit 1. These indications were not precisely quantified because of interfering factors at this location.
-However, the data indicates that their depth is less-than..
the plugging limit of 50% through wall.
MRPC data, subsequently collected, showed these indications to be circumferentially oriented, 180 degrees in extent. These tubes are also adjacent to sleeved tubes.
Unsleeved tubes within two pitches of these tubes were inspected with both bobbin and MRPC probes and found free of similar indications.
All three affected tubes were in the special group of tubes specifically inspected for circumferential indications at the top of the hot leg tubesheet. This group includes all unsleeved tubes forming a boundary 2 tubes wide, completely surrounding the area of sleeved tubes. For each inspection, in the steam generator chosen for the technical specification inspection, this group is inspected with both the bobbin probe and a probe (8x1 or MRPC) to enhance response of circumferential indications.
14
-The eddy current testing program was aggressively expanded in response to the three indications. Thus, the region of the tube bundles where the highest probability exists for this degradation was extensively inspected. In SG-A, unsleeved tubes within two tubes of sleeved tubes were inspected with both the bobbin probe and the 8x1 probe as part of the initial inservice inspection program. In SG-B, unsleeved tubes within two tubes of sleeved tubes were inspected with the bobbin probe. In SG-C, unsleeved tubes within one tube of sleeved tubes (with the exception of row 1 tubes) were inspected with the bobbin probe. Additionally, the three affected tubes, and surrounding unsleeved tubes within two tubes of the affected tubes were inspected with the MRPC probe.
The bobbin probe detection capabilities demonstrated in this inspection are consistent with capabilities discussed in Reference
- 6. Reference 8 reported that "based on correlation of 1980 ECT data with the pulled tube metallurgical results,"... (of 17 tubes)..." the bobbin coil can be used to detect IGA, as found at San Onofre Unit 1, at levels in excess of 20%".
All three of the secondary side circumferential indications were detected by the bobbin probe. No additional indications were identified in the testing done with the 8x1 probe and MRPC probe.
C.
Conclusions The identification of three tubes with indications of potential intergranular attack (IGA) at or near the top of the hot leg tubesheet indicates that there may be very limited IGA progression at San Onofre Unit 1.
The depth of the indication in tube 40-36 in SG-A is of concern; however, no other similar flaws have been detected in any of the large number of tubes inspected. Further, even if-other tubes were to become similarly affected, based on the limited circumferential extent of the observed indication, it is concluded that a tube rupture would be extremely unlikely. Therefore, the limited number of tubes affected out of the large number of tubes inspected and the location of these tubes adjacent to the previously sleeved tubes indicates that the progression of IGA is slow and that current inspection requirements and practices are adequate.
As previously discussed in Section II.C.2, the above three tubes were removed from service by mechanical plugging.
15
.VI.
WRAPPER SUPPORT BAR INSPECTION A.
Introduction The original wrapper support design for the Westinghouse Series 27 steam generator, including San Onofre Unit 1, included six symmetrically located and vertically positioned bars welded to the base of the wrapper on the inside diameter and threaded into the tubesheet. The wrapper rested on these bars and the bars were intended to accept the vertical wrapper loads specified in the steam generator equipment specification.
Subsequent modifications to Series 27 steam generators involved installing two brackets (Type I) in each steam generator, one end of the bracket welded to the transition section of the upper portion of the wrapper assembly with the other end attached to the feedwater ring bracket close to the steam generator shell.
These brackets were designed to prevent vertical displacement of the wrapper assembly even if all of the existing wrappers support bars were not in place. In order to provide further support to the wrapper, these two support brackets were supplemented by a third bracket (Type II) welded to the wrapper and attached to the feedwater ring nozzle support.
During the secondary side visual inspections conducted in 1982, all but three of the wrapper support bars were found to be either broken or missing. The subsequent investigation required the loose support bars to be removed but allowed the three intact support bars to remain.
A commitment was made to visually inspect the intact wrapper support bars in SG-A and SG-B during the Cycle 11 Refueling Outage in References 1 and 2.
B.
Results A visual inspection of the intact wrapper support bars was conducted. The results of the inspection showed that the support bars are still intact and have not moved.
C.
Conclusions Based on the results of the wrapper support bar investigation documented in Reference 9 and the fact that the wrapper support bars in SG-A and SG-B remain intact, the wrapper support bars can be left in place without affecting tube integrity.
16
VII.
STEAM GENERATOR INSPECTION
SUMMARY
AND CONCLUSIONS A.
Summary of Results This inspection has demonstrated that only limited progression of previously identified degradation mechanisms has occurred. These mechanisms include secondary side degradation at the cold leg top of the tubesheet, primary side roll transition cracking, and secondary side circumferential degradation at the hot leg top of the tubesheet. Observed sleeve joint leakage during operation and during leak testing was within technical specification and design limits. A total of 3,949 tubes were inspected (39.5% of the tubes in service), and 29 tubes were removed from service by mechanical plugging.
This inspection has further demonstrated that sleeve joint leakage and the limited degradation progression can be monitored in subsequent inspections, and leaking or defective tubes removed from service in a timely manner.
The wrapper support bar visual inspection results demonstrate that the three remaining wrapper support bars in SG-A and SG-B are intact.
B.
Conclusions The information provided in Sections II through VI of this report establishes the basis for concluding the remedial action taken to resolve sleeve joint leakage and steam generator tube degradation identified during this inspection is appropriate. Accordingly, no further action is-required and power operation can be safely resumed.
In regards to the wrapper support bars, the information provided in Section VII of this report and Reference 9 provides adequate basis for leaving the intact bars in SG-A and SG-B. To ensure these support bars remain intact, an inspection will be conducted during the next steam generator inspection.
In summary, the information presented in this report provides adequate basis for the approval of the corrective action taken at San Onofre Unit 1 as it relates to TS inspection of steam generator tubing.
17
VIII. REFERENCES
- 1.
Letter, M. 0. Medford (SCE) to USNRC (NRC), "Steam Generator Inspections," dated March 25, 1988
- 2.
Letter, F. R. Nandy (SCE) to USNRC (NRC), "Steam Generator Inspection," dated December 23, 1988
- 3.
Letter, G. W. Knighton (USNRC, NRR) to Harold B. Ray (SCE), "Order Confirming Licensee Commitments on Full-Term Operating License Open Items," dated January 2, 1990
- 4.
"Technical Evaluation Report for Hybrid Sleeve," Westinghouse Electric Corporation Report No. NS-MFSE-81-054 dated March 1981 (Proprietary Version), Submitted by Letter K. P. Baskin (SCE) to D. M. Crutchfield (NRC), "Steam Generator Repair Program," dated March 5, 1981
- 5.
Letter, M. 0. Medford (SCE) to USNRC (NRC), "Steam Generator Inspection Report," dated April 14, 1986
- 6.
Letter, M. 0. Medford (SCE) to USNRC (NRC), "Steam Generator Inspection Report," dated May 23, 1988
- 7.
Steam Generator Repair Program, Return to Power Report, San Onofre Unit 1, April 1981.
- 8.
"1985 Re-Evaluation of Steam Generator Inspection Interval, San Onofre Nuclear Generating Station, Unit 1" dated March 1985, submitted by letter, M. 0. Medford (SCE) to J. A. Zwolinski (NRC),
March 19, 1985
- 9.
Letter, K. P. Baskin (SCE) to D. M. Crutchfield (NRC), "Steam Generator Inspection Report," dated September 12, 1982 18
APPENDIX A SG-A, SG-B, AND SG-C INSPECTION TUBESHEET MAPS
TUBESHEET MAP ILLUSTRATING TUBES INSPECTED IN THE 1990 INSERVICE INSPECTION PLANT:
SAN ONOFRE UNIT I GENERATOR:
A TOTAL TUBES:
3794 OUT OF SERVICEW@: 435 A-TU1BES INSPECTED (2201)
TOTAL TUBES ASSISNEM 2201
_j AAA
__A AAA AA,1,,
__S- --
A-1,1 LA S AL L
L L
4
-AS-
.. A....A A-
-ASS
--SSSSSSSLSS
-AL-0-AAL-.---
A
- A-LLLL AA AA SAALLLA
-:A
- -SSSSSSSSSA-A A
LLALAL AA-5 5-- -LAAL -A A-
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A A
L A
LAAA-AAA-ASSAAAAOAAAAL.SL-5
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TUBESHEET MAP ILLUSTRATING TUBES INSPECTED IN THE 1990 INSERVICE INSPECTION PLANT:
SAN ONOFRE UNIT i GENERATOR:
B TOTAL TUBES:
3794 OUT OF SERVICEG(): 457 A = TUBES INSPECTED (1281)
TOTAL TUBES ASSIGNED' 1281 A AAAAA
A -
A-A
-- A--
A A&
-d0
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-S -A - S-S---- AAAAA A AAAAAAAA
-SS S AAA AA-A---
A-AA--A-A
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AA--
---- A--
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AAAAAAAAAAAAAQAA
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A -
A0-- -AAAAAAAAAAAAAAAA
-AAAA-A-AA--------------
A-----------------
A A--SA--A AA-AAO AAAAAAAAAA A S------
5-- O-A-
A--------00-A-0*00-------
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AAA-AAASAAAAAAAAAAAAA A-A---A ----
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A&----- 401 40-------**----S SA-AA--------------AAAAAAAAA A
A----
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----- 5-*--SA--S--SSS-S-S--AAAAAAAAAA
-60
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A O * - A 0 ----------------- 0
--- SS SSSSSS SSSSSSAAA A AA A
A A
A-
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A A
A A
AA A
A A
A A
A A
A A
A A
A A
A S
A A
A A
A AAAAAA--
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A A
A 0-0--A A00AA A
A A AAAA A A II A:
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0 -0
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A A A A A A A A - A - 0
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A A O A A A A A A A A A I
A : - -
A A A A A : : -
A
- A O -
- A A A A A A A A A AV AO O AO A: -
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-A 0
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A A A
A A A
NOZL OUTET(Codeg PiAr ace COUN
->A
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TUBESHEET MAP ILLUSTRATING TUBES INSPECTED IN THE 1990 INSERVICE INSPECTION PLANT:
SAN ONOFRE UNIT I GENERATOR:
C TOTAL TUBES:
3794 OUT OF SERVICE(C@: 494 A -
TUBES INSPECTED (467)
TOTAL TUBES ASSIGNED.
467
_j -- - - -- -- 48
. g
-45
SA------A-
- AAAA----------A A---
A-A-A------
A
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0----
A-- AA ----
AA A A A
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A
A
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0-A
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g
A - - O -
A----------A-A -
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- A
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A
-A -
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A-*AA------ ---
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0 0 -- -----
3 NOZZLE OUTLET (Cold Leg) - Prima-y Face COLUMNS MANNAY C
- A A -
2
-L
-0 0 -
aA A -
A
-A 0 -
APPENDIX B STEAM GENERATOR TUBE AXIAL LOCATION ILLUSTRATION
SERIES 27 TUBE SUPPORT DIAGRAM AV2 AV3 AV1 AV4 ANTI-VIBRATION BARS TUBE SUPPORT NUMBER 04H 04C 4525
.03H 1
03C 45.25 02H 02C 45.25 01H 01C 45.25 TSH L TSC Nominal 2.26'"
TRH-23.
TRC 2.00
. BRH-------------------BRC HOT LEG COLD LEG TSH -TUBE SHEET HOT TRH -TOP.OF ROLL HOT BRH - BOTTOM OF ROLL HOT TEH - TUBE END HOT
.4 4
APPENDIX C INSPECTION RESULTS FOR TUBES WITH DEFECTS BELOW THE UPPERMOST INCH OF SOUND ROLL
INSPECTION RESULTS FOR TUBES WITH DEFECTS BELOW THE UPPERMOST INCH OF SOUND ROLL SAN ONOFRE UNIT 1 STEAM GENERATORS The purpose of this Appendix C is to provide inspection results in accordance with Technical Specification 4.16.D.5, for tubes in service which have defects below the uppermost one inch of tube roll expansion. All these tubes were identified during the 1988 Inservice Inspection and re-inspected during the 1990 Inservice Inspection. There were no additional tubes with imperfections below the uppermost inch of sound roll identified in the 1990 Inservice Inspection.
A listing of tubes in service which have defects below the uppermost one inch of tube roll expansion follows. Testing with an F Star type bobbin probe verified that the locations and sizes of imperfections remain below the uppermost one inch of sound roll.
Tube Number Tube Number Tube Number SG Row - Column Row -
Column Row -
Column A
4 - 3 29 -16 B
35 - 31 36-83 C
6 -1 7 -1 6-2 7 -2 4 -3 6-3 7 -3 4 -4 6-4 6 -5 6 -6 7-6 15 -
6 2 -
7 6 -
7 12 -7 6 -8 12-8 6 -
9 30 -
13 29 -
16 25 -17 34 -17 25 -18 28 -18 37 -18 1 -20 41 - 34 41 -35 39 -37 40 - 38 47 -48 47 -49 38 - 63 47 -63 39 -71 1 - 75 36 -81 29 -84 29 - 85 24 -87 25 -87