ML20207F430
| ML20207F430 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 06/01/1999 |
| From: | Sorensen J NORTHERN STATES POWER CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9906080258 | |
| Download: ML20207F430 (37) | |
Text
Northern States Power Company Prairie Island Nuclear Generating Plant 1717 Wakonade Dr. East Welch, Minnesota 55089 June 1,1999 Technical Specification 4.12.E U S Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 PRAIRIE ISLAND NUCLEAR GENERATING PLANT Docket Nos. 50-282 License Nos. DPR-42 50-306 DPR-60 1999 Unit 1 Steam Generator Inspection Results in accordance with Technical Specification 4.12.E.1, the following information on steam generator tube inspection and repair is provided for the information of the NRC Staff:
Following the recent inservice inspection of the Unit 1 steam generators,84 tubes were plugged for the first time. The percentage of tubes plugged is 4.6% in 11 steam generator and 11.3% (equivalent) in 12 steam generator. The inspection results are summarized in Attachment 1.
As a result of the visual and eddy current inspections,8.7% (282 of 3239) of the inspected tubes in 11 Steam Generator contained defects requiring repair. Seven of l these tubes were plugged and the remaining 275 tubes were left in service using previous and new Additional Roll Expansions and the F-Star (F*) and Elevated F-Star (EF*) alternate repair criteria.
As a result of the visual and eddy current inspection,8.6% (269 of 3117) of the inspected tubes in 12 Steam Generator contained defects requiring repair. Seventy-seven of these tubes were plugged,182 tubes were sleeved, and 10 tubes were left in service using previous Additional Roll Expansions and the (F*) alternate repair criteria.
In accordance with Technical Specification 4.12.E.2, this information will be expanded upon in the Inservice Inspection Report for Unit 1 which will be submitted within 90 days of the end of the current refueling outage.
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USNRC NORTHERN STATES POWER COMPANY June 1,1999 Page 2 In accordance with Generic Letter 95-05, the 90 day report required for the use of the voltage based repair criteria in Unit 1 will be submitted within 90 days of Unit 1 startup.
The results of the inspection of 11 Steam Generator and 12 Steam Generator were classified as Category C-3 in accordance with Technical Specification 4.12 because more than 1% of the inspected tubes in each Steam Generator were defective. The NRC Staff was informed of the Category C-3 classification by telephone on April 26, 1999. In accordance with Technical Specification 4.12.E.3, a 30 day special report on the Category C-3 steam generator inspection is provided as Attachment 2 to this letter.
During the inspection and repair of tubes, F-Star (F*) and Elevated F-Star (EF*)
Alternate Repair Criteria were utilized. Elevated rerolling was done in 11 Steam Generator. There are 266 tubes classified as F* tubes and 19 tubes classified as EF*
tubes. In accordance with Technical Specification 4.12.E.4, the identification of F* and EF' tubes by Row and Column and the location and extent of degradation are included in Attachment 3 to this letter. lists the tubes pressure tested in situ to support the condition monitoring assessment.
Steam generator tubing examination and repairs were conducted from April 20,1999 through May 14,1999. Please contact Jeff Kivi(651-388-1121) if you have any questions related to this letter.
Joel P. Sorensen Site General Manager Prairie Island Nuclear Generating Plant sgt99ui doc
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USNRC NORTHERN STATES POWER COMPANY June 1,1999 j Page 3 I c: Regional Administrator - Region ill, NRC ;
Senior Resident inspector, NRC l NRR Project Manager, NRC J E Silberg Attachments:
- 1. Steam Generator Plugged Tube and F* /EF* Tube Summary j
- 2. Prairie Island Unit 1 Steam Generator Category C-3 Tube inspection Special 1 Report f
- 3. EF* and F* Tube Report
- 4. Prairie Island Unit 1 April 1999 in Situ Pressure Tests
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ATTACHMENT 1 Steam Generator Plugged Tube and F*/EF* Tube Summary l
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Attichmint 1 Juna 1,1999 Page 2 11 Steam Generator Pluaced Tube and F*/EF* Tube Summary Summary New Indications Plugged this Outage: 7' Total Plugged Tubes: 156 Total F* Tubes: 256 Total EF* Tubes: 19 11 Steam Generator % Plugged: 4.60%
Inspection Scope All open tubes were examined full length with the bobbin coil, except for Rows 1 and 2 U-bends.
All Rows 1 and 2 U-bends were examined with rotating probes.
All hot leg tubes were examined with rotating probe technology (including the + Point" coil) from tube end hot to 3 inches above the top of the tubesheet.
All non-quantifiable bobbin coil indications, including all distorted tube support plate indications were examined with rotating probe technology (including the + Point coil)
Indications of Defective Tubes Two hundred eighty-two defective tubes were identified with the following types of degradation:
- 1. Wastage One tube was plugged for thinning at the cold leg tube support plate.
- 2. Secondary Side IGA / SCC in Hot Leg Tubesheet Region l
Six tubes contained single or multiple indications in the tubesheet crevice region indicative of secondary side IGA / SCC occurring in the tubesheet region. One tube with the longest indication was tested in situ with zero leakage and was plugged.
Three tubes were successfully repaired using elevated rerolls and the EF* criteria.
Two tubes were plugged when ODSCC indications appeared in the new elevated reroll region.
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- 3. Secondary Side IGA / SCC at Tube Support Plates l
No tubes contained indications which required repair at the hot leg tube support plates. Previously tubes have been plugged due to axial or volumetric indications i at hot leg tube support plate indicative of secondary side IGA / SCC and/or l wastage.
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! 4. Primary Water Stress Corrosion Cracking (PWSCC) at the Hot Leg Roll Transition Zone I
Sixteen tubes contained single or multiple axial indications at the Roll Transition Zone. All sixteen tubes became EF* tubes after successful Elevated Additional Roll Expansions.
- 5. Primary Water Stress Corrosion Cracking (PWSCC) at the Rows 1 and 2 U-bends ;
There were no indications of tube degradation in the rows 1 and 2 u-bends. !
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- 6. Possible PWSCC Near the Tube End Two hundred fifty tubes (141 new) contained short axial indications near the hot leg tube end. These tubes were all classified as F*0 tubes (tubes with tube end l cracks that meet F* requirements).
- 7. Other Three tubes contained free span outside diameter single axial indications. They were located in the mid free-span above 01H,03H, and 06H. The indications were identified by bobbin coil and confirmed by rotating coil examination. The bobbin coil indications were present and unchanged in historical data back to 1988 and 1990. The most likely cause is manufacturing artifacts. The longest indication,0.3 inches, was pressure tested in situ with no leakage. All three tubes were plugged.
- 8. Existing Repairs Six previous rerolled F* tubes remain in service.
One hundred nine old F*0 tubes remain in service.
Visual Tube Plua inspection A visualinspection was done of allinstalled tube plugs. Four Westinghouse Alloy 690 plugs were replaced due to unusual boric acid deposits.
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Attichm:nt 1 !
Juns 1,1999 Page 4 i
Visual Tube Leak Inspection A visual inspection for tube leakage was conducted following the reroll repairs with the secondary side pressurized to greater than 100 psig following repairs. There were no signs of leakage.
Tube Plua Removal Four tube plugs required repair. These were Westinghouse Alloy 690 mechanical plugs with indications of unusual boric acid buildup. In Technical Bulletin ESBU-TB-99-02, Westinghouse alerted utilities that mechanical plugs installed in previously plugged tubes may not always seal tightly if the tube had been altered during the plug removal process. One of these plugs had been identified as needing replacement based on prior work history.
Rotatina Probe Inspections in order to best identify those tubes which have minor degradation in the tubesheet region and which could leak during the next fuel cycle, and in accordance with the !
requirements of Generic Letter 95-03, a complete examination of the hot leg tubesheet region of allinservice tubes was conducted using a Rotating Coil Probe which contained three different coils. These coils were a 0.115 inch pancake coil, a 0.080 inch pancake coil for discrimination of inside versus outside diameter signals and the
+ Point
- coil.
I' A + Point
- probe was also used to examine all dents greater than 5 volts located at tube to tubesheet or tube support plate intersections (which is more than 20% of all dents greater than 5 volts).
The rotating coil probes were used to resolve distorted signals called by the bobbin probe eddy current inspection.
CircumferentialIndications Two tubes contained circumferential indications in the lower region of the hard roll.
One tube met the F* requirements without rerolling while the other tube was repaired by rerolling.
Cateaory C-3 l
.The results of this inspection program of 11 Steam Generator were classified as Category C-3 by Technical Specification 4.12 because more than 1% (including rotating probe indications) of the inspected tubes in 11 Steam Generator were defective. The sgt99utdoc
Attachmint 1 June 1,1999 Page 5 NRC staff was informed of the Category C-3 classification by telephone on April 26, 1999.
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AttichmInt 1 Juns 1,1999 Page 6 12 Steam Generator Pluaned Tube and F*/EF* Tube Summary Summary New Indications Plugged this Outage: 77 j New Indications Sleeved this Outage 182 '
Total Plugged Tubes: 348 Total Sleeved Tubes 969 1 l
Total F* Tubes: 10 Total EF* Tubes: 0 12 Steam Generator % Plugged: 11.29% (equivalent)
I Inspection Scope All open tubes were examined full length with the bobbin coil, except for Rows 1 and 2 U-bends and the sleeve sections of sleeved tubes. The sleeves were inspected with the rotating coil probe.
All Rows 1 and 2 U-bends were examined with rotating probes.
All hot leg tubes were examined with rotating probe technology (including the + Point coil) from tube end hot to 3 inches above the top of the tubesheet.
Indications of Defective Tubes Two hundred sixty-nine defective tubes were identified with the following types of degradation: .
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- 1. Wastage No tubes were plugged for thinning at the cold leg tube support plate. l l
- 2. Secondary Side IGA / SCC in Hot Leg Tubesheet Region Forty-six tubes contained single or multiple indications or volumetric indications in '
the tubesheet crevice region indicative of secondary side IGA / SCC occurring in the tubesheet region. Eleven of these tubes also contained an indication of primary water stress corrosion cracking at the roll transition zone. Two tubes (the largest voltage and the longest indication) bounding these indications were pressure tested in situ with zero leakage. All of these tubes were plugged or sleeved.
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! Attachment i June 1,1999 Page 7 Three tubes had axial indications above the tubesheet. Two tubes were pressure tested in situ with zero leakage and plugged. The other tube was sleeved. l
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- 3. Secondary Side IGA / SCC at Tube Support Plates One tube contained a volumetric indication at tube support plates indicative of secondary side IGA / SCC and/or wastage. Since this morphology could not be determined to meet the requirements of GL 95-05, this tube was plugged. I All of the tube support plate intersections with distorted bobbin coil indications were examined by rotating coil probes. The only confirmed indications was volumetric and was plugged. I
- 4. Primary Water Stress Corrosion Cracking (PWSCC) at the Hot Leg Roll Transition Zone One hundred forty-four tubes contained single or multiple axial indications at the Roll Transition Zone. One tube with the largest voltage indication (smaller than previous in situ pressure tests) was pressure tested in situ with zero leakage. All 1 indications were repaired by sleeving or plugging.
- 5. Primary Water Stress Corrosion Cracking (PWSCC) at the Rows 1 and 2 U-bends There were no indications of tube degradation in the rows 1 and 2 u-bends.
- 6. Possible PWSCC Near the Tube End Four tubes contained short axial indications near the hot leg tube end. These tubes were all classified as F*0 tubes (tubes with tube end cracks that meet F*
requirements).
- 7. Previously Installed Sleeves One sleeve was plugged due to a restriction which prevented examination with a rotating coil probe. This restriction was determined visually to be a small dimple in the lower end of the sleeve above the lower hard roll joint. One sleeve exhibited extensive permeability variation which could mask defects and was plugged.
Fifty sleeves contained weld zone indications which only marginally met or did not i meet the acceptance criteria for ABB CE sleeves and were plugged. Two of these sleeves (largest voltage indication and longest indication) were pressure tested in situ with zero leakage. Sleeve selection for in situ pressure testing was based on the extent and the voltage of the eddy current signal.
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r Attachm:nt 1 June 1,1999 Page 8 I
- Thirteen sleeves contained new, mostly circumferential, indications in the parent tubes. Three of these sleeves were pressure tested in situ with zero leakage. Two of these sleeves have been removed for metallurgical examination, the results of which will be presented to the NRC within 90 days of startup. One of the '
indications was in the parent tube above the sleeve weld and the other indication was in the parent tube at the elevation of the sleeve weld. The remaining eleven sleeved tubes were plugged.
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- 8. Previously Installed Rerolls l
Six tubes meeting F* criteria with previously installed rerolls remain in service.
Visual Tube Plua and Sleeve End Inspection l
A visual inspection was done of all installed tube plugs and sleeves. No plug or sleeve end anomalies were identified.
Post Maintenance Visual Tube Leak Inspection I
A visual inspection for tube leakage was conducted following the sleeve and welded tubesheet plug installations with the secondary side pressurized to greater than 100 psig following repairs. There were no signs of leakage.
Tube Plua Removal )
l No tube plugs required repair.
Rotatina Probe inspections I In order to best identify those tubes which have minor degradation in the tubesheet region and which could leak during the next fuel cycle, and in accordance with the requirements of Generic Letter 95-03, a complete examination of the hot leg tubesheet region of allinservice tubes was conducted using a Rotating Coil Probe which contained three different coils. These coils were a 0.115 inch pancake coil, a 0.080 inch g"ancake coil for discrimination of inside versus outside diameter signals and the +
Point coil.
A + Point probe was also used to examine all dents greater than 5 volts located at tubesheet and tube support plate intersections (which is more than 20% of all dents greater than 5 volts). The rotating coil probes were used to resolve distorted signals called by the bobbin probe eddy current inspection.
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Attachmsnt 1 Juns 1,1999 Page 9 Circumferential Indications Circumferential indications were found in the parent tubes of 12 sleeved tubes. Forty-eight sleeves contained circumferential weld zone indications attributable to previous weld cleanliness problems. Two of the sleeves with parent tube indications were removed for metallurgical examination. The remaining sleeve indications were plugged.
Cateaorv C-3 The results of this inspection program of 12 Steam Generator were classified as Category C-3 by Technical Specification 4.12 because more than 1% (including rotating probe indications) of the inspected tubes in 12 Steam Generator were defective. The NRC staff was informed of the Category C-3 classification by telephone on April 26, 1999.
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ATTACHMENT 2 Prairie Island Unit 1 Steam Generator Category C-3 Tube inspection Special Report I
Attachm:nt 2 June 1,1999 Page 2 Prairie Island Unit 1 Steam Generators Category C-3 Tube inspection Special Report Purpose This report fulfills the special reporting requirements of Prairie Island Technical Specification 4.12.E.3. This report is required whenever the steam generator tube inservice inspection finds more than 10% of the total tubes inspected are degraded tubes or more than 1% of the inspected tubes are defective. This report summarizes the inspection results, the causes of degradation, the condition monitoring assessment, and the operational assessment.
Summary An inservice inspection consisting of inspection of 100% of the full length of tubing with the bobbin coil and 100% of hot leg tubesheet region and the row 1 and 2 u-bends with mechanical rotating probe with + Point coil was conducted in Unit 1 Steam Generators from April 20,1999 through May 14,1999.
As a result of the visual and eddy current inspections,8.7% (282 of 3239) of the inspected tubes in 11 Steam Generator contained defects requiring repair. Seven of these tubes were plugged and the remaining 275 tubes were left in service using previous and new Additional Roll Expansions and the F-Star (F*) and Elevated F-Star (EF*) alternate repair criteria.
As a result of the visual and eddy current inspection,8.6% (269 of 3117) of the inspected tubes in 12 Steam Generator contained defects requiring repair. Seventy-seven of these tubes were plugged,182 tubes were sleeved, and 10 tubes were left in service using previous Additional Roll Expansions and the (F*) alternate repair criteria.
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Attichm:nt 2 Juns 1,1999 Page 3
Background
Table 1 provides data on the Prairie Island Nuclear Generating Plant which is significant for the steam generators.
Table 1: PRAIRIE ISLAND PLANT DATA Location: On Mississippi River near Red Wing Minnesota
)1 Nuclear Steam Supply System: Westinghouse 2-Loop 560 MWE I Steam Generators: Westinghouse Model 51 Mill-Annealed Alloy 600 Tubing Open Tubesheet Crevices - 2.75 inch hard roll at bottom of tube Circulating Water: Mississippi River / Cooling Towers ,
Secondary Systems Tubing: Stainless Steel / Carbon Steel '
Startup Dates : Unit 1 - December 16,1973 Unit 2 - December 21,1974 j Effective Full Power Years as of Unit 1 (EOC 18)- 20.8 EFPY's End of Previous Cycle: Unit 2 (EOC 17)- 20.3 EFPY's HOT LEG TEMPERATURE: 590 degrees Fahrenheit The current status of each steam generator at Prairie Island is shown in the attached Table 2: " Prairie Island Steam Generator Tube Degradation and Repair Status."
Causes of Major Tube Degradation There are two major causes of the degradation of tubes in Unit 1 steam generators.
Secondary side intergranular attack and stress corrosion cracking (IGA / SCC or ODSCC) is occurring in the hot leg tubesheet crevice region, at the top of the hot leg tubesheet, and in the hot leg tube support plate intersection. This cause was identified by .
metallurgical examination of three hot leg tubesheet region sections of the inconel 600 I tubing removed from Steam Generator 12 in January 1985. This was confirmed by examination of a parent tube section removed during the sleeve pulls in 1996. The degradation is characterized as single or multiple axial indications. Except for the early years, these axial indications are located in the lower one-half of the tubesheet crevice region. In addition, three tubes were removed for GL 95-05 Voltage Based Repair Criteria in 1997 and ODSCC along with apparent old wastage was identified at the hot leg tube support plates.
Rotating pancake coil (MRPC) of the tube samples and experience gained from other utilities provides tools to confirm the type of degradation occurring in the tubesheet region. MRPC examinations of all tubes with non-quantifiable indications in the tubesheet region have been done routinely since February,1987. The MRPC results have confirmed the type of degradation as secondary side IGA / SCC.
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Attachmrnt 2 Junn 1.1999 Page 4 Also, tubes with indications representative of primary water stress corrosion cracking (PWSCC) at the roll transition region have been identified by MRPC and by metallurgical examination of one roll transition zone removed during the sleeve pulls in 1996.
Comparison of Number of Defective Tubes in Unit 1 Steam Generators, October 1997 to April 1999.
The number of new defective tubes identified in Unit 1 Steam Generators decreased slightly in 12 steam generator and increased slightly in 11 steam generator in the tubesheet crevice region. In both steam generators, roll transition zone PWSCC is more dominant than ODSCC In 11 steam generator, tube end cracking is a dominant mode of degradation. In 12 steam generator, a substantial number of sleeves were removed from service due to weld zone indications, all of which were previously present, using the improved inspection techniques and conservatively interpreting the acceptance criteria.
Indications at hot leg tube support plates due to ODSCC occurring remained similar. Of the combined total of 466 distorted indications detected at TSP intersections in both SGs, only 10 indications exceed 1 volt and none exceed 2 volts. Further details will be provided in the 90 day report for the voltage based repair criteria.
New Sleeve installation Data Only 2 of the 184 new sleeves installed required plugging due to weld zone indications identified by eddy current examination. i Condition Monitoring Condition Monitoring evaluates the as found condition of the steam generator tubing against leakage and structural integrity criteria. There were no tubes identified which exceeded the structural integrity requirement of no tube burst at three times the normal operating differential pressure. Degradation mechanisms located in the tubesheet crevice region can not burst due to the constraints of the tubesheet. Axial degradation mechanisms are not expected to burst unless the indication is greater than 0.38 inches long in the free span. There were no tubes identified by in situ pressure testing which exceeded leakage limits at main steam line break conditions . There were no tubes identified with qualified sizing techniques which approach structural integrity limits.
In Situ Tests To demonstrate adequate leakage and structural integrity, twelve tubes were pressure j
' tested in situ. Tubes were selected based on largest extent and voltage of the eddy ;
current indications and each type of degradation was tested. Tests were done at Main Steam Line Break (MSLB) conditions for indications in the tubesheet crevice region.
Tests were done at Main Steam Line Break pressure and at three times normal sgt99ui. doc
Attichmint 2 Juna 1,1999 Page6 operating differential pressure (3dp) for indications in free span regions. The test pressure for Main Steam Line Break conditions was 2816 psig and for 3dp conditions was a maximum of 5650 psig. The list of tubes tested in situ is in Attachment 4. No tubes challenged the structural integrity criteria of 3 times normal operating differential pressure. No tubes leaked at Main Steam Line Break or 3dp pressures.
Operational Assessment for Each Degradation Mechanism Unit 1 ~ Cycle 19 length was abnormally short at 440 EFPD. Unit 1 Cycle 20 length is planned to be 598 EFPD. Unit 1 Cycle 18 length was 565 EFPD. Continued operation for the longer Cycle 20 is based in part on successful operation during the previous longest Cycle 18.
- 1. Wear at Tube Bundle Structural Components and Foreign Objects (Loose Parts)
AVB wear was identified at 28 locations this outage. No AVB locations required plugging. The maximum growth seen for indications which were greater than 10% last cycle was 10%. The AVB wear degradation mechanism growth rate does not challenge structural integrity during the next cycle.
- 2. Thinning at the Cold Leg Tube Support Plates CLTSP thinning was identified at 65 locations this outage. One of these locations required plugging. The largest percent call was 42% which had been an indication not reportable last inspection. The maximum growth seen for indications which were greater than 10% last cycle was 17%. The average growth rate was 2.3% since 21 indications had negative or zero growth rate. The cold leg tube support plate degradation mechanism does not challenge structural integrity during the next cycle.
- 3. Assessment of Secondary Side IGAISCC in the Tubesheet Region Secondary side IGA / SCC is identified as axial or volumetric indications and is repaired on detection and thus growth rates are not available. The maximum length of IGA / SCC seen in the tubesheet region was a 11.9 inch MAI in 11 SG R19C48. This tube was pressure tested in situ with zero leakage. Three of the secondary side indications in the tubesheet region were pressure tested in situ and all had zero leakage under MSLB conditions. Therefore, the secondary side IGA / SCC in the tube sheet region does not present a challenge to structural or leakage integrity for the next cycle.
4.-- Secondary Sido IGAISCC at the Top of the Tubesheet Region There were three axial indications located at the top of the tubesheet. These indications are plugged or sleeved on detection. Two indications were pressure tested in situ at sgt99ui. doc
Attichm:nt 2 June 1,1999 Page 6 MSLB conditions and at 3 times normal operating differential pressure. There was no i leakage at MSLB pressure and there was no leakage or rupture at 3dp. Therefore, none of the indications at the top of the tubesheet presented challenges to structural or ,
leakage integrity and new indications are not expected to present challenges during the next cycle.
- 5. Assessment of Primary Water Stress Corrosion Cracking at the Roll Transition i Zones (PWSCC at RTZ)
The largest voltage (1.36 volts) new indication of PWSCC at Roll Transition Zones was pressure tested in situ. No leakage was identified. This is the third inspection using the
+ Point coil of the roll transition zones. Since this indication and larger (2.35 volts) from the previous inspection did not leak, new indications are not expected to leak either and )
do not present leakage or structural integrity concerns during the next cycle.
- 6. Primary Water Stress Corrosion Cracking at the Low Row U-bends (PWSCC at U-bends) i No low row u-bend indications were identified during this inspection. Since the + Point coil was used to examine all of the row 1 and 2 u-bends, there is reasonable assurance that u-bend degradation growth will not exceed structural and leakage integrity for the l next cycle based on previous operating cycle experience.
- 7. Secondary Side IGA / SCC at the Tube Support Plates All of the distorted bobbin coilindications at the tube support plates were examined by
+ Point coil. The one confirmation was volumetric and not associated with cold leg tube support plate thinning and was plugged. None of the bobbin coilindications at IGA / SCC locations exceeded 2 volts. In accordance with Tech Specification 4.12 and Generic Letter 95-05, a report will be submitted for the voltage based repair criteria within ninety days of Unit 1 startup. Preliminary operational assessment calculations meet the acceptance criteria for main steam line break leakage and for conditional probability of burst. Therefore, this degradation mechanism does not present leakage or structural integrity concerns during the next cycle.
- 8. Manufacturing Burnishing Marks in crevice regions All manufacturing bumishing marks could be traced back to 1988 and showed no change. Therefore, there does not appear to be any degradation associated with the manufacturing burnishing marks.
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- 9. Degradation at Dented Tube Support Plates Locations All dents at tube support plate and tubesheet locations > 5.0 volts were examined with
+ Point . No indications of degradation were found.
- 10. Indications at Tube Ends There is an increasing number of indications associated with the tube ends in 11 steam generator. The number has increased from 29 in 1996 to 113 in 1997 to 261 in 1999.
These indications are located at or below the seal weld. There is sufficient hard roll present above these indications to meet F* criteria. These indications do not present a structural or leakage integrity concern.
Forty eight old sleeves and two new sleeve contained weld zone indications requiring l resolution. The sleeve weld zone indications were confirmed by magnetically biased rotating probes and were conservatively plugged. Non-magnetic biased probe data i indicated the presence since installation. Thirty-eight of the 48 old sleeves had been installed in 1996, the year that weld cleanliness problems were discovered. Changes in the use of the magnetic biased probe in 1999 resulted in reclassifying these sleeve weld zone indications.
This increase in number of indications is attributed to the knowledge gained from the Prairie Island 1996 sleeve pulls, reexamination in 1999 with magnetic biased probes of all sleeve weld zone indications, the Site Specific Performance Demonstration for the eddy current analysts, and analyst performance tracking which gives analysts daily feedback on their performance compared to the final resolution calls.
All tubes with sleeves with eddy current indications which did not meet the new eddy current acceptance criteria for location of weld zone indications above the weld centerline were plugged. In addition, weld zone indications for which the location with !
respect to the weld centerline were ambiguous were plugged.
Previous operation with the sleeves did not present a safety issue based on the results of the 1996 sleeve pull analysis and based on in situ pressure tests with zero leakage of three sleeves during the 1997 inspection and two sleeves during the 1999 inspection.
As stated in NSP's June 27,1996 letter to the NRC on sleeving issues, the root cause of the ET indications and the discontinuities in the sleeve welds was inadequate removd of the contaminants and oxide from lnside of the parent tube prior to sleeve insertion resulting in oxide inclusions captured in the sleeve weld.
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Attachmsnt 2 Juns 1,1999 Page 8
'12. Degradation in Additional Roll Expansions (Re-Rolls)
There were no F* rerolls with new degradation.
- 13. Structural Degradation of the Tube Support Plates During the April 1999 eddy current examination, bobbin coil data was analyzed to determine if indications of possible tube support plate ligament anomalies were present. ,
When bobbin coil data identified such anomalies, they were coded PSI and rotating I coil technology (RPC) was used to reexamine the PSI intersections. From the RPC l data,10 tube support plate intersections in 11 SG and 3 tube support plate intersections in 12 SG were confirmed to have indications of possible tube support plate ligament " cracks". These indications are mainly at patch plate locations and in the ;
outer periphery suspect locations identified in Westinghouse letter WOG-97-186, j
" Transmittal of NEl Sponsored Steam Generator Internals Degradation Interim inspection Guidelines".
The Plus-Point eddy current probe characterization showed that none of these indications reflected significant missing ligaments. (The largest possible ligament gap was 51 degrees. The minimum gap that would permit a tube to move into a larger displacement mode under flow induced vibration is 146 degrees). It is also noted that there is no detectable tube degradation at the locations of the possible degraded tube support plate ligaments. Therefore, none of these indications required plugging.
The bobbin coil data for these possible support plate ligament indications was reviewed from 1988 and found to be unchanged. Thus it is likely that these conditions reflect
-steam generator as-built conditions which resulted from misalignment of drilling of flow holes or tube holes as has been visually verified at Diablo Canyon. I Therefore, since there is no indication of active degradation in the tube support plates !
or in the tubes at the suspect locations, the possible support plate ligament cracks do not represent a concern for the forthcoming operating cycle. The exact cause of the source of the indications is not known.
- 14. Potential Degradation in Tube Plugs All tube plugs were examined visually. Indications of leakage were observed in 4 Westinghouse Alloy 690 mechanical plugs installed in 1990 and are felt to be due to non-uniformity of the tube due to previous plug removal operations. These plugs were replaced with Alloy 690 mechanical rolled plugs.
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I AttIchmtnt 2 Juna 1,1999 Page 9
- 15. Potential Degradation in Parent Tubes of Previously Installed Sleeves There were 13 sleeved tubes with eddy current indications in the parent tubes in the region of the upper welded joint. These indications are summarized as follows
. . Eight tubes with circumferential indications below the weld in the region of the hydraulic expansion transition.
. Two sleeves with circumferential indications above the weld.
. One sleeve with axial indications below the weld.
. One sleeve with both axial and circumferential indications below the weld.
. One sleeve with circumferential indications below and above the weld.
With the exception of two sleeves which had previous indications found upon reanalysis of data, all of these parent tube indications occurred in sleeves which
.were installed in 1997. This was the first time the ABBCE TIG weld tubesheet sleeve with lower hard roll joint was installed at Prairie Island. Remedial actions were taken during the 1999 sleeve installation to reduce residual stresses in the parent tube. One action was to elevate the sleeve slightly to prevent the hard roll thrust collar from reacting on the sleeve which prevents tensile stress load being imparted on the tube below the weld joint. Another action was to eliminate the post weld heat treatment which eliminates far field stresses from affecting the parent tube above the weld joint.
Three of the sleeves were pressure tested in situ with no indication of leakage.
Two sleeve samples were removed for metallurgical examination. Helium leak l testing indicates no leakage through the defects. Metallurgical examination is !
proceeding and a full report will be provided by ABB Combustion Engineering within 90 days of startup.
Summary of Operational Assessment An evaluation of allindications of degradation confirms that none of the forms of degradation occurring presents a structural or leakage integrity concern for the next cycle of operation.
Remedial Actions Northem States Power has participated in utility funded research on steam generator related issues beginning with the Steam Generator Owners Group ll in 1982 and continuing to the present EPRI funded Steam Generator Management Project. Remedial actions to reduce and/or prevent tube degradation due to primary water stress corrosion ,
cracking and secondary side IGA / SCC have been used by the industry with only limited I sgt99ui. doc l
Attachmint 2 Juns 1,1999 Page 10 success. Prairie Island has evaluated, and in most cases, implemented the following remedial actions.
Reduced Operatina Temperature: Prairie Island has been a low temperature plant having operated with Thot at 590 F since startup. This has slowed, but not eliminated, growth of PWSCC and IGA / SCC in the Prairie Island steam generators. Additional temperature reduction has not been warranted.
1 Chemistry Control: Prairie Island has used state of the art analytical equipment since startup and has followed both the original equipment manufacturer's water chemistry guidelines as well as the EPRI secondary water chemistry guidelines.
The amounts of material found from hideout return tests during shutdowns have been small. Steam generators are sludge lanced every other outage on a cycling basis with less than 50 pounds of sludge removed from the steam generator per outage. Plasticor repairs of the condenser tubesheets has reduced circulating !
water in leakage to a very low level. The PWSCC degradation is relatively !
independent of chemistry and occurs in regions of high residual stress. {
Hiah Hydrazine Control: Prairie Island maintains a hydrazine control band of 125
+/- 25 ppb.
Molar ratio control to reduce secondary side corrosion: Molar ratio control has been attempted by adjustments to steam generator blowdown resin ratios during recent operating cycles. Operating molar ratios are normally less than 1. The object of molar ratio control is to maintain the cation to anion ratio (sodium to chloride plus sulfate) at less than one so that free sodium hydroxide can not form )
in the crevice regions.
Conduct Crevice Flushina Operations with Boric Acid: Prairie Island started crevice flushing in 1986 using two days of time. Since then we have added boric acid to the crevice flushing procedure. The time has been reduced to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since only a small amount of contaminants are being removed. This effects only the tubesheet crevice region. Crevice flushing was not conducted in 1999.
On-line addition of Boric Acid: Following the report of favorable laboratory results in 1986, Prairie Island began on-line addition of boric acid in Unit 1 in March 1987.
The effectiveness of this remedial action remains controversial within the industry (EPRI IGA / SCC workshops in May 1991 and December 1992). Prairie Island will continue to use boric acid until such time as an inhibitor of equal or greater effectiveness is justified for on-line use. One of the recommended boric acid practices, low power soaks, has not been implemented at Prairie Island. l Use of other chemicalinhibitors: At the present time, NSP supports EPRI research for other chemical inhibitors. Our current evaluations centers around the sgt99u1 doc
e Attachmsnt 2 Juns 1,1999 Page 11 use of titanium compounds to inhibit the growth of IGA / SCC. A titanium chelate, TYZOR LA Titanate has been added since January 1994.
Preventive sleevina: Sleeving is one method of reducing the probability of tube leak outages. The down side of preventive sleeving is the inability to follow the degradation mechanism and the reduction in the ability to examine tube support plate intersections above the sleeves. NSP has made the strategic decision to sleeve on an as-needed basis, to insure that we are able to best follow the tube support plate problems and to reduce our overall cost of steam generator repair and maintenance.
F* and EF* Repair Criteria: The F-Star and EF-Star Alternate Repair Criteria allow tubes to remain in service with indications below the F* or EF* distance. Additional Roll Expansion adds a new F* or EF* distance to the steam generator tubing and allows additional tubes to remain in service which have degradation in the lower tubesheet crevice region.
Detailed Inspection Plans: Although not a recommendation for remedial actions, but rather a current inspection guideline,100% of the fulllength of all tubes in service are routinely examined at Prairie Island. This was started in 1982. In addition, all tubes with indications which can not be quantified, such as NQl's, ;
DSI's, MBM's (ln the tubesheet) are examined with the rotating coil probe due to its '
higher sensitivity. Repair decisions, in those cases, are based on the RPC results.
l l
sot 99ul. doc
Table 2: Prairie Island Steam Generator Tube Degradation and Repair Status Type of Degradation' 11 SG 12 SG 21 SG 22 SG Cold Leg TSP Thinning 58 33 77 138 Antivibration Bar Wear 24 3 9 31 Tubesheet Sec Side IGA / SCC Only 16 751 24 6 Roll Transition Zone PWSCC Only 30 400 647 382 RTZ PWSCC and Sec Side IGA / SCC 2 47 17 1 Hot Leg Tube Support Plate 22 42 0 0 Voltage Based ARC TSP Distorted Indications 315 144 0 0 U-Bend PWSCC 1 2 1 0 Loose Pads 8 0 6 2 Free Span & Top of Tubesheet 16 18 5 6 Tube End AxialIndications 250 4 102 74 Other 4 3 7 5 Total Tubes Defective 747 1453 895 645
% Tubes Defective 22 % 43% 26 % 19%
Type of Repair Tubes Plugged 156 348 195 207 Voltage Based Repair Criteria 315 144 0 0 Tubesheet Sleeves (IGA / SCC)* 0 969 0 0 )
F*0 Alternate Repair Criteria 250 4 102 74 F*1 ARC w/ Aduitional Roll Expansions 6 6 576 342 F*2 ARC w/ Additional Roll Expansions 0 0 22 22 EF* ARC w/ Additional Roll Expansions 19 0 0 0 Total Tubes Repaired
- 747 1477l 895l 645 l
% Equivalent Plugged 4.60 % 11.29 % 5.76 % 6.11 %
% Equivalent Pluggedper Unit 7.95 % 5.93 %
'Except for sleeved tubes, only one degradation classification given per tube 2
includes 24 preventive sleeves installed in 1988 28 Sleeves = 1 plug !
ATTACHMENT 3 EF* and F* Tube Repod l
l 1
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Attichment 3 Juns 1,1999 Page 2 l
i l 11 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 1 9 sal TRH -2.80 TO-2.70 F*0 11 H 8 9 SCI TRH -2.56 TO-2.51 F*0 11 H 1 12 SAI TRH -2.70 TO-2.62 F*0 11 H 2 12 SAI TRH -2.47 TO-2.43 F*0 11 H 6 12 MAI TRH -2.52 TO 2.44 F*0 11 H 2 13 SAI TRH -2.53 TO-2.44 F*0 11 H 1 14 SAI TRH -2.67 TO-2.59 F*0 11 H 2 14 SAN TRH -2.59 TO-2.36 F*0 11 H 3 14 SAN TRH -2.47 TO-2.39 F*0 4
11 H 1 15 MAI TRH -2.76 TO-2.62 F*0 11 H 1 16 sal TRH -2.81 TO-2.66 F*0 11 H 1 17 MAI TRH -2.69 TO-2.60 F*0 11 H 2 17 MAN TRH -2.67 TO-2.56 F*0 11 H 1 18 SAI TRH -2.68 TO-2.61 F*0 I 11 H 1 19 SAI TRH -2.73 TO-2.61 F*0 11 H 1 20 MAI TRH -2.69 TO-2.59 F*0 11 H 10 20 SAI TRH -2.80 TO-2.62 F*0 11 H 1 21 SAI TRH -2.70 TO-2.63 F*0 11 H 3 21 MAN TRH -2.80 TO-2.57 F*0 11 H 10 21 MAI TRH -2.59 TO-2.50 F*0 11 H 1 22 MAI TRH -2.49 TO-2.40 F*0 1 I
11 H 3 22 SAI TRH -2.53 TO-2.46 F*0 11 H 1 23 SAI TRH -2.87 TO-2.76 F*0 11 H 6 23 MAI TRH -2.54 TO-2.47 F*0 11 H 1 24 SAI TRH -2.82 TO-2.74 F*0 11 H 2 24 MAI TRH -2.52 TO-2.44 F*0 11 H 1 25 MAN TRH -2.78 TO-2.70 F*0 11 H 2 25 SAI TRH -2.54 TO-2.46 F*0 11 H 3 25 MAI TRH -2.76 TO-2.69 F*0 11 H 4 25 MAN TRH -2.59 TO-2.48 F*0 !
11 H 5 25 MAN TRH -2.68 TO-2.55 F*0 11 H 10 25 SAN TRH -2.57 TO-2.49 F*0 11 H 12 25 SAI TRH -2.62 TO-2.58 F*0 11 H 20 25 MAI TRH -2.48 TO-2.37 F*0 11- H 21 25 SAI TRH -2.57 TO-2,48 F*0 11 H 1 26 MAI TRH -2.74 TO-2.65 F*0 11 H 6 26 SAI TRH -2.48 TO-2.41 F*0 l 11 H 7 26 SAI TRH -2.64 TO-2.56 F*0 >
l 11 H 8 26 SAI TRH -2.65 TO-2.56 F*0 11 H 17 26 SAI TRH -2.53 TO-2.45 F*0 11 H 19 26 SAI TRH -2.62 TO-2.54 F*0 11 H 20 26 MAI TRH -2.54 TO-2.47 F*0
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Attichm nt 3 Juns 1,1999 Page 3 11 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS l 11 H 1 27 MAN TRH -2.80 TO-2.62 F*0 1 11 H 2 27 MAI TRH -2.62 TO-2.52 F*0 )
11 H 4 27 SAI TRH -2.66 TO-2.58 F*0 11 H 5 27 SAI TRH -2.72 TO-2.61 F*0 11 H 6 27 SAN TRH -2.64 TO-2.52 F*0 1 11 H 7 27 sal TRH -2.71 TO-2.60 F*0 I 11 H 19 27 MAI TRH -2.51 TO-2.45 F*0 11 H 20 27 MAI TRH -2.47 TO-2.36 F*0 11 H 1 28 SAN TRH -2.73 TO-2.65 F*0 11 H 4 28 SAI TRH -2.63 TO-2.51 F*0 11 H 5 28 SAI TRH -2.76 TO-2.64 F*0 11 H 7 28 SAI TRH -2.62 TO-2.48 F*0 11 H 9 28 SAI TRH -2.65 TO-2.54 F*0 11 H 12 28 SAI TRH -2.58 TO-2.49 F*0 11 H 16 28 SA1 TRH -2.49 TO-2.42 F*0 11 H 19 28 sal TRH -2.49 TO-2.41 F*0 11 H 20 28 MAI TRH -2.51 TO-2.43 F*0 11 H 1 29 MAN TRH -2.90 TO-2.75 F*0 11 H 2 29 SAI TRH -2.56 TO-2.48 F*0 11 H 5 29 SAN TRH -2.70 TO-2.58 F*0 11 H 8 29 SAI TRH -2.59 TO-2.47 F*0 11 H 12 29 MAI TRH -2.54 TO-2.43 F*0 11 H 18 29 sal TRH -2.56 TO-2.48 F*0 11 H 19 29 MAN TRH -2.62 TO-2.48 F*0 11 H 20 29 MAI TRH -2.54 TO-2.42 F*0 l 11 H 1 30 SAN TRH -2.75 TO-2.61 F*0 11 H 5 30 SAN TRH -2.66 TO-2.58 F*0 11 H 7 30 MAN TRH -2.64 TO-2.47 F*0 11 H 9 30 SAN TRH -2.78 TO-2.67 F*0 11 H 13 30 SAN TRH -2.76 TO-2.71 F*0 '
11 H 14 30 MAN TRH -2.59 TO-2.48 F*0 11 H 15 30 SAI TRH -2.61 TO-2.57 F*0 11 H 16 30 SAI TRH -2.59 TO-2.51 F*0 11 H 19 30 MAN TRH -2.82 TO-2.72 F*0 11 H 20 30 MAI TRH -2.54 TO-2.46 F*0 11 H 21 30 SAN TRH -2.73 TO-2.63 F*0 11 H 1 31 MAN TRH -2.49 TO-2.33 F*0 11 H 5 31 SAN TRH -2.71 TO-2.67 F*0 11 H 9 31 MAN TRH -2.71 TO-2.65 F*0 11 H 10 31 MAN TRH -2.74 TO-2.64 F*0 11 H 13 31 SAN TRH -2.78 TO-2.67 F*0 l
11 H 15 31 MAN TRH -2.44 TO-2.38 F*0 11 H 19 31 MAN TRH -2.70 TO-2.62 F*0 sgt99ut. doc L
Attrchment 3 Jun31.1999 Page 4 11 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 21 31 SAN TRH -2.68 TO-2.55 F*0 11 H 1 32 MAN TRH -2.77 TO-2.61 F*0
$1 H 4. 32 sal TRH -2.52 TO-2.48 F*0 11 H 6 32 SAN TRH -2.68 TO-2.54 F*0 11 H 8 32 sal TRH -2.78 TO-2.67 F*0 11 H 13 32 SAN TRH -2.58 TO-2.47 F*0 11 H 19 32 MAI TRH -2.73 TO-2.62 F*0 11 H 21 32 MAI TRH -2.54 TO-2.44 F*0 11 H- 1 33 sal TRH -2.53 TO-2.45 F*0 11 H 2 33 SAN TRH -2.47 TO-2.46 F*0 11 H 7 33 SAI TRH -2.62 TO-2.54 F*0 11 H 11 33 sal TRH -2.60 TO-2.53 F*0 11 H 12 33 SAN TRH -2.63 TO-2.53 F*0 11 H 13 33 sal TRH -2.60 TO-2.51 F*0 11 H 14 -33 MAN TRH -2.71 TO-2.60 F*0 11 H 16 33 SAI TRH -2.56 TO-2.45 F*0 11 H 17 33 SAI TRH -2.56 TO-2.49 F*0 11 H 18 33 SAN TRH -2.65 TO-2.49 F*0 11 H 19 33 SAN TRH -2.68 TO-2.61 F*0 11 H 1 34 SAN TRH -2.71 TO-2.56 F*0 11 H 6 34 SAN TRH -2.64 TO-2.55 F*0 11 H 7 34 SAI TRH -2.93 TO-2.85 F*0 11 H 8 34 SAI TRH -2.53 TO-2.45 F*0 11 H 9 34 SAN TRH -2.57 TO-2.52 F*0 11 H 10 34 MAI TRH -2.62 TO-2.51 F*0 4 11 H 11 34 mal TRH -2.61 TO-2.54 F*0 l 11 H 12 34 MAI TRH -2.60 TO-2.47 F*0 l 11 H 13 34 SAN TRH -2.60 TO-2.50 F*0 11 H 17 34 sal TRH -2.57 TO-2.49 F*0 11 H 19 34 MAI TRH -2.72 TO-2.62 F*0 11 H 1 35 SAN TRH -2.87 TO-2.73 F*0 11 H 2 35 SAN 7RH -2.61 TO-2.52 F*0 11 H 12 35 sal iRH -2.58 TO-2.50 F*0 11 H 13 35 SAI TRH -2.57 TO-2.51 F*0 11 H 14 35 sal TRH -2.70 TO-2.62 F*0 11 H 15 35 SAN TRH -2.42 TO-2.39 F*0 11 H 16 35 SAI TRH -2.74 TO-2.63 F*0 11 H 1 36 MAN TRH -2.60 TO-2.31 F*0 11 H 2 36 MAI TRH -2.48 TO-2.33 F*0 11 H 4 36 SAI TRH -2.60 TO-2.52 F*0 11 H 5 36 SAI TRH -2.48 TO-2.45 F*0 11 H 13 36 MAN TRH -2.69 TO-2.49 F*0 11 H 14 36 MAI TRH 2.61 TO-2.50 F*0 sgt99ui doc
Attichm':nt 3 Jun31,1999 Page 5 11 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 15 36 SAI TRH -2.55 TO-2.50 F*0 11 H 16 36 MAN TRH -2.71 TO-2.58 F*0 11 H 20 36 SAI TRH -2.70 TO-2.59 F*0 11 H 21 36 SAN TRH -2.62 TO-2.46 F*0 11 H 1 37 mal TRH -2.59 TO-2.38 F*0 11 H 2 37 MAN TRH -2.57 TO-2.45 F*0 11 H 6 37 MAI TRH -2.55 TO-2.42 F*0 11 H 9 37 SAN TRH -2.59 TO-2.50 F*0 11 H 11 37 SAI TRH -2.55 TO-2.44 F*0 l 11 H 16 37 MAN TRH -2.78 TO-2.59 F*0 l 11 H 19 37 sal TRH -2.75 TO-2.66 F*0 l 11 H 1 38 SAN TRH -2.55 TO-2.47 F*0 11 H 4 38 MAI TRH -2.G1 TO-2.53 F*0 11 ll 8 38 MAN TRH -2.77 TO-2.64 F*0 11 H 9 38 MA) TRH -2.62 TO-2.52 F*0 11 H 13 38 SAN TRH -2.64 TO-2.55 F*0 11 H 14 38 MAI TRH -2.~4 TO-2.55 F*0 11 H 15 38 SAI TRH -2.62 TO-2.53 F*0 11 H 16 38 SAN TRH -2.73 TO-2.60 F*0 11 H 21 38 SAI TRH -2.64 TO-2.52 F*0 ;
11 H 22 38 SAN TRH -2.71 TO-2.68 F*0 1 11 H 1 39 MAN TRH -2.43 TO-2.32 F*0 11 .H 2 39 MAN TRH -2.52 TO-2.42 F*0 1 11 H 4 39 SAI TRH -2.61 TO-2.54 F*0 1 11 H 7 39 MAN TRH -2.42 TO-2.32 F*0 l 11 H 12 39 SAI TRH -2.70 TO-2.62 F*0 l 11 H 14 39 SAI TRH -2.74 TO-2.68 F*0 11 H 15 39 SAI TRH -2.46 TO-2.38 F*0 :
11 H 20 39 SAN TRH -2.96 TO-2.74 F*0 !
11 H 21 39 SAI TRH -2.68 TO 9.58 F-0 11 H 22 39 SAN TRH -2.64 TO-2.43 F*0 11 H 35 39 SAN TRH -2.66 TO-2.53 F*0 11 H 1 40 MAN TRH -2.57 TO-2.44 F*0 11 H 5 40 SAI TRH -2.40 TO-2.32 F*0 11 H 9 40 IAAI TRH -2.57 TO-2.46 F*0 11 H 13 40 MAI TRH -2.46 TO-2.38 F*0 11 H 14 40 SAI . TRH -2.70 TO-2.67 F*0 11 H 15 40 SAI TRH -2.47 TO-2.37 F*0 11 H 19 40 MAI TRH -2.66 TO-2.57 F*0 11 H 20 40 mal TRH -2.81 TO-2.64 F*0 11 H 22 40 SAN TRH -2.67 TO-2.52 F*0 11 H 1 41 SAN TRH -2.49 TO-2.38 F*0 11 H 4 41 SAN TRH -2.80 TO-2.69 F*0 sgt99ui. doc
r Attrchm:nt 3 ,
Juna 1,1999 Page 6
)
, J 11 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 12 41 SAI TRH -2.75 TO-2.63 F*0 11 H 15 41 MAI TRH -2.44 TO-2.29 F*0 11 H 16 41 sal TRH -2.69 TO-2.62 F*0 11 H 17 41 sal TRH -2.49 TO-2.42 F*0 11 H 18 41 SAN TRH -2.71 TO-2.61 F*0 '
11 H 20 41 SAN TRH -2.91 TO-2.72 F*0 11 H 4 42 MAI TRH -2.74 TO-2.59 F*0 11 H 12 42 MAI TRH -2.72 TO-2.57 F*0 11 H 14 42 SAI TRH -2.73 TO-2.66 F*0 11 H 16 42 SAI TRH -2.70 TO-2.60 F*0 11 H 19 42 SAI TRH -2.51 TO-2.40 F*0 11 H 20 42 SAN TRH -2.66 TO-2 51 F*0 11 H 21 42 SAN TRH -2.47 TO-2.37 F*0 11 H 1 43 SAN TRH -2.60 TO-2.46 F*0 11 H 2 43 SAI TRH -2.68 TO-2.57 F*0 11 H 6 43 MAI TRH -2.69 TO-2.56 F*0 11 H 7 43 MAI TRH -2.39 TO-2.34 F*0 11 H 8 43 SAI TRH -7. 68 TO-2.62 F*0 11 H 12 43 sal TRH 2.66 TO-2.61 F*0 11 H 17 43 MAN TRH -2.61 TO-2.50 F*0 11 H 22 43 SAN TRH -2.69 TO-2.55 F*0 11 H 1 44 SAN TRH -2.77 TO-2.65 F*0 =
11 H 5 44 SAI TRH -2.54 TO-2,47 F*0 i 11 H 6 44 SAI TRH -2.62 TO-2.52 F*0 11 H 10 44 MAN TRH -2.87 TO-2.60 F*0 11 H 12 44 SAI TRH -2.63 TO-2.56 F*0 11 H 14 44 MAI TRH -2.73 TO-2.66 F*0 11 H 16 44 mal TRH -2.72 TO-2.68 F'O 11 H 17 44 MAI TRH -2.71 TO-2.49 F*0 11 H 19 44 MAN TRH -2.56 TO-2.43 F*0 11 H 21 44 SAN TRH -2.57 TO-2.43 F*0 11 H 22 44 SAN TRH -2.57 TO-2.47 F*0 11 H 1 45 SAN TRH -2.66 TO-2.48 F*O 11 H 6 45 SAN TRH -2.56 TO-2.43 F*0 11 H 8 45 SAI TRH -2.70 TO-2.59 F*0 11 H 9 45 SAI TRH -2.49 TO-2.42 F*0 11 H 10 45 SAI TRH -2.72 TO-2.58 F*0 11 H 12 45 SAI TRH -2.60 TO-2.53 F*0 11 H 14 45 MAI TRH -2.95 TO-2.72 F*0 11 H 15 45 MAI TRH -2.79 TO-2.70 F*0 11 H 17 45 sal TRH -2.62 TO-2.52 F*0 11 'ci 19 45 MAN TRH -2.70 TO-2.51 F*0 11 H 21 45 MAI TRH -2.94 TO-2.78 F*0 agtmi dx
l I Attichm nt 3 i
~
f Juns 1.1999
( Page 7 j l ,
l '11 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 4 46 MAI TRH -2.87 TO-2.75 F*0 <
11 H 6 46 SAI TRH -2.79 TO-2.72 F*0 11 H 7 46 MAI TRH -2.67 TO-2.61 F*0 !
11 H 11 46 SAI TRH -2.71 TO-2.66 F*0 l 11 H 21 46 MAN TRH -2.76 TO-2.54 F*0 1 11 H 19 47 SAI - TRH -2.67 TO-2.60 F*0 !
11 H 22 47 SAI TRH -2.68 TO-2.57 F*0
- 11. H 1 48 SAN TRH -2.91 TO-2.79 F*0 11 H 1 49 sal TRH -2.47 TO-2.42 F*0 11 H 2 49 MAI TRH -2.55 TO-2.32 - F*0 l 11 H 1 50 MAN TRH -2.70 TO-2.60 F*0 I 11 H 1 51 SAN TRH -2.58 TO-2.47 F*0 11 H 1 52 MAI TRH -2.69 TO-2.52 F*0 11 H 1 54 MAN TRH -2.64 TO-2.55 F*0 11 H 1 55 SAN TRH -2.56 TO-2.39 F*0 11 H 5 55 MAN TRH -2.48 TO-2.40 F*0 11 H 1 56 SAN TRH -2.52 TO-2.40 F*0 11 H 1 57 SAI TRH -2.48 TO-2.36 F*0 11 H 1 58 SA; TRH -2.63 TO-2.51 F*0 11 H 1 59 SAI TRH -2.65 TO-2.56 F*0 11 H 1 60 SAI TRH -2.53 TO-2.46 F*0 11 H 4 60 SAI TRH -2.46 TO-2.39 F*0 11 H 19 60 MAN TRH -2.37 TO-2.21 F*0 11 H 2 62 sal TRH -2.43 TO-2.28 F*0 11 H 12 63 SAN TRH -2.65 TO-2.54 F*0 11 H 11 64 SAI TRH -2.57 TO-2.50 F*0 11 H 1 68 SAN TRH -2.71 TO-2.64 F*0 11 H 1 70 MAN TRH -2.76 TO-2.58 F*0 11 H 1 71 SAI TRH -2.73 TO-2.65 F*0 ,
11 H 1 72 SAN TRH -2.76 TO-2.63 F*0 l 11 ';
. 1 73 SAN TRH -2.72 TO-2.65 F*0 11 H 1 74 SAI TRH -2.74 TO-2.62 F*0 11 H 1 75 sal TRH -2.75 TO-2.67 F*0 I 11 H 1 76 SAN TRH -2.72 TO-2.64 F*0 11 H 1 78 SAN TRH -2.81 TO-2.62 F*0 11 H 1 87 SAN TRH 2.67 TO-2.47 F*0 '
Grand 250 Count F*0 = F* TUBE WITHOUT ADDITIONAL ROLL EXPANSION MAI = MULTIPLE AXlAL INDICATION SAI = SINGLE AXIAL INDICATION sgt99ut. doc
m Attichm:nt 3 Juna 1,1999 Page 8 MAN = MULTIPLE AXIAL INDICATION, NO CHANGE SAN = SINGLE AXlAL INDICATION, NO CHANGE 4 SCI = SINGLE CIRCUMFERENTIAL INDICATION )
TRH = TOP OF ROLL HOT LEG l
1 jl l
1 i
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AttIchmtnt 3 Juns 1,1999 Page9 11 STEAM GENERATOR F*1 TUBES, April,1999 l S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 23 17 SAN 1BH -2.07 TO-1.84 F*1 11 H 8 27 SAD 1BH -1.12 F*1 11 H 30 46 SAD 1BH -1.02 F*1 11 H 5 56 SAN 1BH -1.37 TO-1.29 F*1 11 H 5 57 SAD 1BH -1.07 F*1 11 H 8 78 MAN 1BH -2.98 TO-2.28 F*1 l Grand 6 Count F*1 = F* TUBE WITH ONE ADDITIONAL ROLL EXPANSION SAD = SINGLE AXIAL INDICATION, No longer detectable i MAN = MULTIPLE AXIAL INDICATION, NO CHANGE I SAN = SINGLE AXIAL INDICATION, NO CHANGE 1BH = BOTTOM OF ADDITIONAL HARD ROLL 1 l
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Attichmtnt 3 Jun:s 1,1999 Page 10 11 STEAM GENERATOR EF* TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 11 H 3 26 SAI TRH -0.02 TO+0.02 EF*
11 H 13 29 SAI TRH +0.21 TO+0.35 EF*
11 H 7 31 sal TRH -0.02 TO+0.02 EF*
11 H 14 32 SAI TRH +0.23 TO+0.32 EF*
11 H 10 33 MAI TRH +0.18 TO+0.39 EF*
11 H 14 34 SAI TRH +0.19 TO+0.24 EF*
11 H 4 37 SAI TRH +0.09 TO+0.17 EF*
11 H 14 37 SAI TRH +0.02 TO+0.14 EF*
11 H 4 40 SAI TRH +0.12 TO+0.15 EF*
11 H 10 40 SCI TRH -1.23 TO-1.09 EF*
11 H 4 44 MAI TRH +0.18 TO+0.30 EF*
11 H 16 50 SAI TRH +1.91 TO+2.25 EF*
11 H 17 51 SAI TRH +1.82 TO+2.04 EF*
11 H 20 53 SV1 TRH +0.69 TO+0.74 EF*
11 H 5 54 SAI TRH +0.10 TO+0.17 EF*
11 H 12 60 SAI TRH +0.22 TO+0.33 EF*
11 H 8 66 MAI TRH -0.03 TO+0.04 EF*
11 H 6 74 SAI TRH -0.04 TO+0.03 EF*
11 H 7 87 SAI TRH +0.01 TO+0.22 EF*
Grand 19 Count EF* = EF* TUBE WITH ELEVATED ADDITIONAL ROLL EXPANSION MAI = MULTIPLE AXIAL INDICATION SAI = SINGLE AXIAL INDICATION :
SCI = SINGLE CIRCUMFERENTIAL INDICATION SVI = SINGLE VOLUMETRIC INDICATION <
TRH = TOP OF ROLL HOT LEG Sgt99ul DOC l
Atttchment 3 l Juns 1,1999 l Page 11 12 STEAM GENERATOR F*0 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 12 H 5 2 SAI TRH -2.43 TO-1.96 F*0 12 H 27 10 SAI TRH -2.93 TO-2.87 F*0 12 H 25 68 SAI TRH -2.60 TO-2.46 F*0 12 H 10 88 SCI TRH -2.68 ' TO-2.61 F*0 q Grand 4 Count F*0 = F* TUBE WITHOUT ADDITIONAL ROLL EXPANSION SAI = SINGLE AXIAL INDICATION SCI = SINGLE CIRCUMFERENTIAL INDICATION i TRH = TOP OF ROLL HOT LEG i
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Atttchmrnt 3 i
Juns 1,1999 l Page 12 l
l 12 STEAM GENERATOR F*1 TUBES, April,1999 S/G LEG ROW COL PERCENT LOCATION STATUS 12 H 34 31 MAN 1BH -1.17 TO-1.08 F*1 12 H 37 38 MAN 1BH -1.25 TO-1.11 F*1 l 12 H 31 46 SAN 1BH -1.10 TO-1.03 F*1 12 H 31 47 MAD 1BH -1.00 F*1 12 H 32 47 MAD 1BH -0.81 F*1 l
12 H 4 71 MAN 1BH -1.55 TO-1,19 F*1
! Grand 6 l Count F*1 = F* TUBE WITH ONE ADDITIONAL ROLL EXPANSION MAD = MULTIPLE AXIAL INDICATION, No longer detectable MAN = MULTIPLE AXlAL INDICATION, NO CHANGE SAN = SINGLE AXIAL INDICATION, NO CHANGE 1BH = BOTTOM OF ADDITIONAL HARD ROLL 1 l
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