ML20198N719
| ML20198N719 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 12/28/1998 |
| From: | Sorensen J NORTHERN STATES POWER CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9901060196 | |
| Download: ML20198N719 (53) | |
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Northern States Power Company Prairie Island Nuclear Generating Plant 1717 Wakonade Dr. East Welch, Minnesota 55089 December 28,1998 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 1998 Unit 2 Steam Generator Inspection Results in accordance with Technical Specification 4.12.E.1, the following information on steam generatcr tube inspection and repair is provided for the information of the NRC Staff; Following the recent inservice inspection of the Unit 2 steam generators,44 tubes were plugged for the first time. The percentage of tubes plugged is 5.8% in 21 steam generator and 6.1% in 22 steam generator. The inspection results are summarized in.
In accordance with Technical Specification 4.12.E.2, this information will be expanded upon in the Inservice Inspection Report for Unit 2 which will be submitted within 90 days of the end of the current refueling outage.
The results of the inspection of 21 Steam Generator and 22 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 November
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17,1998. In accordance with Technical Specification 4.12.E.3, a 30 day special report i
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*) Alternate Repair Criteria was 01 fD utilized and rerolling was done using the improvements implemented during the Unit 2 January 1997 outage. There are 1138 tubes classified as F* tubes. In accordance with 990106h196b512287 P D *.
ADOCK 05000282 G
PDR_
USNRC NORTHERN STATES POWER COMPANY L
December 28,1998 Page 2 Technical Specification 4.12.E.4, the identification of F* tubes by Row and Column and the location and extent of degradation are included in Attachment 3 to this letter.
There are no new NRC commitments in this letter. Please contact Jeff Kivi (612-388-1121)if you have any questions related to this letter.
Joel P. Sorensen Plant Manager Prairie Island Nuclear Generating Plant c: Regional Administrator - Region lil, NRC Senior Resident inspector, NRC NRR Project Manager, NRC J E Silberg Attachments:
- 1. Steam Generator Plugged Tube and P Tube Summary
- 2. Prairie Island Unit 1 Steam Generator Category C-3 Tube Inspection Special Report l
- 3. P Tube Report i
- 4. Prairie Island Unit 2 In Situ Test List -
November 1998 Refueling Outage O
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ATTACHMENT 1 Steam Generator Plugged Tube and F* Tube Summary I
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Attachm:nt 1 Dic:mb:r 28,1998 Page 2 21 Steam Generator Plugged Tube and F* Tube Summary Summary J
New Indications Plugged this Outage:
30
. Total Plugged Tubes:
195 Total F* Tubes:
700 21 Steam Generator % Plugged:
5.76 %
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 (int,luding the + Point
- coil) from tube end hot to 3 inches above the top of the tubesheet. The cold leg tubesheet was not examined with rotating coil technology since twenty percent of the cold leg tubes were examined with rotating probe technology (including the + Point coil) from tube end cold to 1 inch above the top of the tubesheet in 1997 with no need for expansion.
I New Indications New tubes were identified with the following types of degradation:
- 1. Wastage:
Six tubes were plugged for thinning at the cold leg tube support plate.
- 2. Secondary Side IGA / SCC in Hot Leg Tubesheet Region Two tubes contained single or multiple indications in the tubesheet crevice region indicative of secondary side IGA / SCC occurring in the tubesheet region. One tube was tested in situ with zero leakage. Both tubes were plugged. Single or multiple axialindications indicative of tubesheet crevice secondary side IGA / SCC appeared in eleven tubes after installation of an additional roll evpansion and were plugged.
- 3. Secondary Side IGA / SCC at Tube Support Plates sgt97u2 doc
Attachmsnt i Dzetmber 28,1998 Page 3 There was no confirmation of secondary side IGA / SCC at the tube support plates.
All of the tube support plate intersections with distorted bobbin coil indications were examined by rotating coil probes.
- 4. Primary Water Stress Corrosion Crackirg (PWSCC) at the Hot Leg Roll Transition Zone Two hundred new tubes contained single or multiple axial indications at the Roll Transition Zone. One hundred eighty four tubes became F* tubes after successful Additional Roll Expansions. Two tubes were plugged due to unsatisfactory Additional Roll Expansions profilometry results. Eleven tubes were plugged due to unsuccessful Additional Roll Expansion caused by appearance of secondary side indications. Three tubes were plu0ged after successful in situ pressure testing.
- 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 One hundred two tubes (32 new) contained short axial indications near the hot leg tube end. These tubes were all classified as F* tubes.
- 7. Other One tube contained a free span volumetric indication on the cold leg side above the tubesheet which was pressure tested in situ with zero leakage and then plugged.
One tube with a volumetric indication at the seventh cold leg tube support plate was plugged.
Four tubes with wear scars probably due to a washer lost in 1995 during upper bundle hydraulic cleaning were plugged. The washer could not be confirmed or retrieved. Eddy current indications indicate it has resided in the same location for two cycles. The best estimate highest tube degradation was 67% through wall.
The two largest indications were pressure tested in situ with no leakage.
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Page 4 Maximum Length of Ro!l Transition Zone Indications L
The maximum length of the indications in the Roll Transition Zone was one tube at 0.4 inches. This tube was pressure tested in situ with no leakage.
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- Visual Tube Plug Inspection i
.A visual inspection was done of all installed tube plugs. No abnormalities were observed.
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Visual Tube Leak Inspection l
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3 A visual inspection for tube leakage was conducted following the reroll repairs and installations with the secondary side pressurized to greater than 100 psig following repairs. There were no signs ofleakage.
Tube Plug Replacement l '.
No plugs required replacement. All of the Westinghouse Alloy 600 mechanical plugs have been previously replaced in 21 steam generator.
Rotating Probe Inspections In order to best identify those tubes which have minor degradation in the tubesheet l
' 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 all inservice 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 discriminction of inside versus outside diameter signals and the
+ Point
- coil.
A + Point
- probe was also used to examine all dents greater than 5 volts and to reso!
distorted signals called by the bobbin probe eddy current inspection.
Free Span Dent Examination l
In the 1997 Unit 1 St6c.m Generator Inspection Result Report dated December 8,1997, h
NSP committed to the following: The remaining uninspected free span dents in Unit 2 will be inspected during the Fall 1998 Unit 2 refueling outage.
All free span dents (17) identified in 21 Steam Generator were examined by + Point coil and no degradation was found in November 1998, t
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l Attachment i Dectmber 28,1998 Page5 l
Circumferential Indications t.
No circumferential indications were found.
l Category C-3 The results of this inspection program of 21 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 21 Steam Generator were defective. The NRC staff was informed of the Category C-3 classification by telephone on November 17,1998.
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Attachment i DIcimber 28,1998 Page 6 4
22 Steam Generator Plugged Tube and F* Tube Summary Summary New Indications Plugged this Outage:
14 Total Plugged Tubes:
207 Total F* Tubes:
438 22 Steam Generator % Plugged:
6.11 %
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" t
coll) from tube end hot to 3 inches above the top of the tubesheet. The cold leg tubesheet was not examined with rotating coil technology since twenty percent of the cold leg tubes were examined with rotating probe technology (including the + Point coil) from tube end cold to 1 inch above the top of the tubesheet in 1997 with no need for expansion.
i New Indications New tubes were identified with the following types of degradation:
- 1. Wastage:
Eight tubes were plugged for thinning at the cold leg tube support plate.
- 2. Secondary Side IGA / SCC in Hot Leg Tubesheet Region Two tubes contained single or multiple indications in the tubesheet crevice region Indicative of secondary side IGA / SCC occurring in the tubesheet region. Both tubes were tested in situ with zero leakage. Both tubes were plugged. Single or multiple axial!adications indicative of tubesheet crevice secondary side IGA / SCC appeared in one tube after installation of an additional roll expansion and was plugged.
- 3. Secondary Side 1GA/ SCC at Tube Support Plates egt97u2. doc
....__.__--__..-_..___.__._._._.______._._-_.___.-__.m._m._._____
Dtcember28,1998
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Page 7 There was no confirmation of secondary side IGA / SCC at the tube support plates.
All of the tube support plate intersections with distorted bobbin coil indications were examined by rotating coil probes.
- 4. Primary Water Stress Corrosion Cracking (PWSCC) at the Hot Leg Roll Transition l
Zone One hundred fifty seven new tubes contained single or multiple axial indications 1
at the Roll Transition Zone. One hundred fifty three tubes became F* tubes after successful Additional Roll Expansions. One tube was plugged due to unsuccessful Additional Roll Expansion profilometry results. One tube was plugged due to unsuccessful Additional Roll Expansion caused by appearance of secondary side indications. One tube was plugged due to a rerolling brush stuck i
in the tube. One tube was pressure tested in situ with zero leakage.
- 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 Seventy four tubes (29 new) contained short axial indications near the hot leg tube end. These tubes were all classified as F* tubes.
- 7. Other There were no other indications requiring repair.
Visual Tube Plug Inspection A visual inspection was done of allinstalled tube plugs. Two plug were observed to
. slightly extend beyond the tubesheet. They were dispositioned as acceptable since the status was confirmed to be present at initial installation and met installation acceptance criteria. Two Westinghouse explosive plugs exhibited unusual boric acid residue and were replaced with welded Alloy 690 tubesheet plugs.
Post Maintenance Visual Tube Leak Inspection A visual inspection for tube leakage was conducted following the reroll repairs and welded tubesheet plug installations with the secondary side pressurized to greater than 800 psig.
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Attachmsnt 1 December 28,1998 Page 8 Tube Plug Removel No other tube plugs required repair. All the Westinghouse Alloy 600 mechanical plugs have been replaced in 22 steam generator.
Rotating 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 all inservice 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 +
l Point coil.
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A + Point probe was also used to examine all dents greater than 5 volts and to l
resolve distorted signals called by the bobbin probe eddy current inspection.
l Free Span Dent Examination l
In the 1997 Unit 1 Steam Generator inspection Result Report dated December 8,1997, l
NSP committed to the following: The remaining uninspected free span dents in Unit 2 will be inspected during the Fall 1998 Unit 2 refueling outage.
All free span dents (30) identified in 22 Steam Generator were j
examined by + Point coil and no degradation was found in November 1998.
' Circumferential Indications
. No circumferential indications were found.
Category C-3 l=
The results of this inspection program of 22 Steam Generator were classified as Category C-3 by Technical Specification 4.12 because more than 1% (including rotating j
probe indications) of the inspected tubes in 22 Steam Generator were defective. The NRC staff was informed of the Category C-3 classification by telephone on November 17,1998.
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Dic mbit 28,1998 Page 9 Summary of 21 and 22 Steam Generator Inspections and Repairs
. NSP plugged 30 additional steam generator tubes in the 21 Steam Generator and 14 l
additional steam generator tubes in the 22 Steam Generator. Repairs were completed on December 12,1998.
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No sleeves were installed.
The voltage based repair criteria is not in use on Unit 2.
All free span dents were inspected with rotating coil probes and no degradation was
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1 Prair;e Island Unit 2 Steam Generator Category C-3 Tube Inspection Special Report i
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Dec2mber 28,1998 Page 2 Prairie Island Unit 2 Steam Generators l
Category C-3 Tube inspection Special Report i
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 regions and the row 1 and 2 u-bends with mechanical rotating probe with + Point coil was conducted in Unit 2 S:eam Generators from November 14,1998 through December 12,1998.
l As a result of the eddy current inspections,7.5% (242 of 3223) of the inspected tubes in l
21 Steam Generator contained defects requiring repair. ThMy of these tubes were plugged and the remaining tubes were left in service using previous and new Additional Roll Expansions and the F-Star (F*) alternate repair criteria. Repairs were completed on December 12,1998.
As a result of the eddy current inspection,6.1% (196 of 3195) of the inspected tubes in Steam Generator 22 contained defects requiring repair. Fourteen of these tubes were plugged and the remaining tubes were left in service using previous and new Additional Roll Expansions and the (F*) alternate repair criteria. Repairs were completed on December 12,1998.
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Decsmber 28,1998 Page 3
' Background
. Table 1 provides data on the Prairie Island Nuclear Generating Plant which is significant l-for the steam generators.
Table 1: PRAIRIE ISLAND PLANT DATA Location: On Mississppi River near Red Wing Minnesota
- Nucleer Steam Supply System: Westinghouse 2-Loop 560 MWE l
Steam Generators: Westinghouse Model 51 I
Mill-Annealed Alloy 600 Tubing Open Tubesheet Crevices - 2.75 inch hard roll at bottom of tube L
- Circulating Water: Mississippi River / Cooling Towers l
Secondary Systems Tubing: Stainless Steel / Carbon Steel
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,Startup Dates :
Unit 1 - December 16,1973 7
Unit 2 - December 21,1974 l
Effective Full Power Years as of End of Previous Cycle:
'4 Unit 1 (EOC 18)- 19.6 EFPY's Unit 2 (EOC 18)- 20.3 EFPY's 2 JT 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 Plug and Sleeve Status."
Causes of Major Tube Degradation There is one major cause of the degradation of tubes in Unit 2 steam generators. Primary l
water stress corrosion cracking is occurring at the roll transition zones in this partial depth i
.tubesheet expansion plant. To a lesser extent, secondary side intergranular attack and L
' stress corrosion cracking (IGA / SCC or 9 SCC) is occurring in the hot leg tubesheet crevice region, also. The remaining sic,dicant degradation is wastage or thinning at the cold leg tube support plates on the outer periphery of the tube bundle. This was characterized by a tube pullin 1980.
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. 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 U
' exceeded the structural integrity requirement of no tube burst at three times the normal operating differential pressure. Degradation mechanisms located in the tubesheet f.
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Drcember 28,1998 Page 4 crevice region can not burst due to the constraints of the tubesheet. Axial degradation l
mechanisms are not expected to burst unless the indication is greater than 0.38 inches l
long in the free span. There were no tubes identified by in situ pressure testing which j
exceeded leakage limits at main steam line break conditions.
In Situ Tests To demonstrate adequate leakage and structural integrity, ten tubes were pressure j
tested in situ. Tubes were selected based on largest extent and voltage of the eddy current indications. 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 operating differential pressure (3dp) for ir.dications in free span regions. The test pressure for Main Steam Line Break conditions was 2816 psig and for 3dp conditions was 5624 psig. The list of tubes tested in situ is in. No tubes challenged the structuralintegrity criteria of 3 times normal operating differential pressure. No tubes leaked at Main Steam Line Break pressures.
Operational Assessment for Each Degradation Mechanism Unit 2 Cycle 18 length was 538 EFPD. Unit 2 Cycle 19 length is planned to be 482 EFPD.
- 1. Wear at Tube Bundle Structural Components and Foreign Objects (Loose Parts)
There were 41 active AVB wear locations this outage. No AVB locations required plugging. The maximum growth seen for indications which were greater than 10% last cycle was 11%. The AVB wear degradation mechanism growth rate does not challenge structural integrity during the next cycle. Four wear scars due to a possible loose part were plugged. The part appears to have been located at the same location for two cycles.
- 2. Thinning at the Cold Leg Tube Support Plates There were 203 active CLTSP thinning locations this outage. Fourteen of these locations required plugging. The largest percent call was 49% which had increased from 14% the previous outage. The maximum growth seen for indications which were greater than 10% last cycle was 35%. The 95%/95% growth rate was 19%. The l
average growth rate was -1.5% since 116 indications had negative or zero growth rate.
The cold leg tube support plate degradation mechanism does not challenge structural i
integrity during the next cycle.
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Dictmber 28,1998 Page5
- 3. Secondary Side IGA / SCC in the Tubesheet Region l
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 2.35 inch MAI in 21 SG R22C33. This tube was l
pressure tested in situ with zero leakage. Two of the secondary side indications were pressure tested in situ and all had zero leakage under MSLB conditions. Therefore, the secondary side IGA / SCC does not present a challenge to structural or leakage integrity l
for the next cycle.
' 4. Secondary Side IGA / SCC at the Top of the Tubesheet Region Thera were no volumetric or axial indications located at the top of the tubesheet.
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- 5. Primary Water Stress Corrosion Cracking at the Roll Transition Zones (PWSCC at RTZ)
Four of the approximately 357 new indications of PWSCC at RTZs were pressure tested in situ including the largest voltage indications. No leakage was identified. This is the third inspection using the + Point coil of the roll transition zones. Thirteen indications of PWSCC at RTZs havo been previously tested in situ with no leakage at Prairie Island. Since these indications did not leak, new indications are not expected to l
leak either and do not piesent leakage or structural integrity concerns during the next l
cycle.
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- 6. Primary Water Stress Corrosion Cracking at the Low Row U-bends (PWSCC at U-bends)
There were no indications in the low row U-benc'a. 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 next cycle.
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- 7. Secondary Side IGA / SCC at the Tube Support Plates
- All of the distorted bobbin coil indications at the tube support plates were examined by
+ Point coil. One was confirmed as volumetric at 07C 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 (largest was 1.16 volts). If IGA / SCC is present, this degradation mechanism does not appear to present leakage or structural integrity concems during the next cycle.
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Attachm nt 2 December 28,1998 Page 6 l
- 8. Manufacturing Burnishing Marks in crevice regions l
All manufacturing burnishing marks could be traced back to 1988 and showed no l
change. Therefore, there does not appear to be any degradation associated with the i
manufacturing burnishing marks.
- 9. Degradation at Dented Tube Support Plates and All Other Locations All dents > 5.0 volts were examined with + Point. No indications of degradation were found.
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- 10. Indications at Tube Ends There is an increasing number of indications associated with the tube ends. The l
number has increased from 135 in 1997 % 176 in 1998. These indications are located at or below the seal vield. There is sufficient hard roll present above these indications to meet F* criteria. These indications do not present a structural or leakage Integrity concerr
- 11. Degradation in Sleeves j
There are no sleeves in the Unit 2 steam generators.
- 12. Degradation in Additional Roll Expansions (Re-Rolls)
There were 8 F* rerolls with new degradation in the new reroll region which were i
repaired. These indications are indicative of Primary Water Stress Corrosion Cracking
. at the new roll transitions and are expected to behave similar to the original roll transition zones and not present a structural or leakage integrity concern.
- 13. Structural Degradation of the Tube Support Plates During the November 1998 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 coil technology (RPC) was used to reexamine the PSI intersections. From the RPC data, one tube support plate intersection in 22 SG was confirmed to have an indication of possible tube support plate ligament " cracks". The indication is at a patch plate location.
The Plus-Point eddy current probe characterization showed that this indication did not reflect significant missing ligaments. (The largest possible ligament gap was less than l
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Attachm*nt 4.
December 28,1998 Page 7 50 degrees. The minimum gap that would permit a tube to move into a larger i
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 l
possible degraded tubs support plate ligaments. Therefore, none of these indications required plugging.
The bcbbin coil data for these possible support plate ligament indications was reviewed l
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 l
holes or tube holes as has been visually verified at Diablo Canyon.
1 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. Two Westinghouse explosive Alloy 600 plugs had signs of leakage and were repaired. All plugs are visually examined each refueling
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outage and repaired as necessary.
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 11 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 success. Prairie Island has evaluated, and in most cases, implemented the following L
remedial actions:
Reduced Operating Temperature: Prairie Island has been a low temperature plant i
having operated with Thot at 590 F since startup. This has slowed, but not l
eliminated, growth of PWSCC and IGA / SCC in the Prairie Island steam i
generators. Additional temperature reduction has not been warranted.
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December 28,1998 Page 8 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 retum tests during shutdowns have been small. Steam generators are sludge lanced every other outage on a cycling basis with less than 80 pounds of sludge removed from the steam generator per outage. The PWSCC degradation is relatively independent of chemistry and occurs in regions of high residual stress. Plasticor repairs of the condenser tubesheets has reduced circulating water in leakage to a very low level.
High 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 the last operating cycle. Operating molar ratios are normally less than 1. The object of molar ratio control is to maintain the cation to anion ratio (sodium to j
chloride plus sulfate) at less than one so that free sodium hydroxide can not form in the crevice regions.
Conduct Crevice Flushing 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 tubeshoet crevice region. A decision was made to stop crevice flushing beginning with this outage.
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.
Use of other chemical inhibitors: At the present time, NSP supports EPRI research for other chemical inhibitors. Our current evaluations centers around the use of l
titanium compounds to inhibit the growth of IGA / SCC. A titanium chelate, TYZOR I
LA Titanate has been added since January 1994.
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Attachm:nt 2 December 28,1998 Page 9 Preventive sleeving: Sleeving is one method of reducing the probability of tube i
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 hac 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* Repair Criteria: The F-Star Altemate Repair Criteria allows tubes to remain in service with indications below the F* distance. Additional Roll Expansion adds a new F* distance to the steam generator tubing and allows additional tubes to l
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 full length 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 (in 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.
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Table 2: Prairie Island Steam Generator Tube Degradation and Repair Status i
Type of Degradation' 11 SG 12 SG 21 SG 22 SG Cold Leg TSP Thinning 57 33 77 138 Antivibration Bar Wear 24 3
9 31 Tubesheet Sec Side IGA / SCC Only 10 716 24 6
Roll Transition Zone PWSCC Only 14 255 647 382 RTZ PWSCC and Sec Side IGA / SCC 2
36 17 1
Hot Leg Tube Support Plate 22 41 0
0 Voltage Based ARC TSP Distorted Indications 256 163 0
0 U-Bend PWSCC 1
2 1
0 Loose Pads 8
0 6
2 Free Span & Top of Tubesheet 13 16 5
6 Tube End AxialIndications 113 0
102 74 Other 4
3 7
5 Total Tubes Defective 524 1268 895 645
% Tubes Defective 15%
37 %
26%
19%
Type of Repair Tubes Plugged 149 271 195 207 Voltage Based Repair Criteria 256 163 0
0 Tubesheet Sleeves (IGA / SCC)2.
0 852 0
0 F*0 Alternate Repair Criteria 113 0
102 74 F*1 ARC w/ Additional Roll Expansions 0
0 576 342 i
F*2 ARC w/ Additional Roll Expansions 6
6 22 22 Total Tubes Repaired 524 1292 895 645
% Equivalent Plugged 4.40 %
8.90 %
5.76%
6.11 %
% Equivalent Plugged per Unit 6.65 %
5.93 %
'Except for sleeved tubes, only one degradation classification given per tube 2 includes 26 preventive sleeves installed in 1988 in 12 SG 28 Sleeves = 1 plug i
l ATTACHMENT 3 i
I F* Tube Report i
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2 8
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4 9
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2 10 SAN TRH
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2 12 SAN TRH
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7 12 SAN TRH
- 2.6TO-2.5 F*0 21 H
15 12 SAN TRH
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28 12 MAN TRH
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27 15 SAN TRH
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2 16 SAN TRH
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7 17 MAN TRH
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26 22 SAI TRH
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33 24 SAI TRH
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33 25 SAI TRH
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33 30 SAI TRH
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46 INF 1BH 1.6TO-1.5 F*1 sgt97u2. doc
Drcember 28,1998 Page ;2 l
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17 46 INF 1BH
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19 46 INF 1BH 1.2 F*1 21 H
21 46 INF 1BH
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24 46 INF 1BH 1.3 F*1 21 H
28
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8 47 SAN 1BH 1.2TO-1.2 F*1 21 H
9 47 SAN 1BH
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- 1.STO-1.4 F*1 21 H
12 47 SAN 1BH
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13 47 MAN 1BH
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24 47
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9 48 INF 1BH 1.4 F*1 21 H
11 48 INF 1BH
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December 28.1998 Page 13 21 H
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21 54 INF 1BH 1.1 TO-1.1 F'1 sot 97u2. doc
December 28,1998 Page 14 21 H
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- 1.3 F*1 21 H
34 54 INF 1BH
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19 57 INF 1BH 1.3 F*1 21 H
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2 58 INF 1BH 1.4 F*1 21 H
4 58 INF 1BH 1.4 F*1 l
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- 1.4TO-1.2 F*1 21 H
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21 58 MAN 1BH 1.3TO-1.2 F*1 l
21 H
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3 59 INF 1BH
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- 1.2TO-1.1 F*1 21 H
11 59 MAN 1BH 1.3TO-1.1 F*1 21 H
13 59 MAN 1BH 1.2TO-1.1 F*1 21 H
14 59 MAN 1BH
- 1.4TO-1.3 F*1 21 H
21 59 l INF 1BH 1.3 F*1 i
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Decamber 28,1998 Page 15 21 H
28 59 INF 1BH 1.2 F*1 21 H
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4 60 MAN 1BH 1.4TO-1.1 F*1 21 H
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- 1.5TO-1.3 F*1 21 H
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14 60 MAN 1BH 1.4TO-1.2 F*1 21 H
16 60 MAN 1BH
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29 60 INF 1BH 1.3 F*1 21 H
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16 63 INF 1BH 1.4TO-1.3 F*1 21 H
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6 64 MAN 1BH 1.2TO-1.1 F*1 21 H
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Attachm:nt 3 December 28,1998 Page 16 21 H
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14 64 MAN 1BH
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17 64 SAN 1BH
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22 64 INF 1BH 1.4 F*1 21 H
34 64 NDD F*1 21 H
35 64 INF 1BH 1.3 F*1 21 H
2 65 INF 18H
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4 65 INF 1BH
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16 66 SAN 1BH
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17 66 INF 1BH 1.4TO-1.4 F*1 21 H
18 66 INF 1BH
- 1.4TO-1.3 F*1 21 H
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35 66 INF 1BH 1.4 F*1 21 H
1 67 INF 1BH
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3 67 INF 1BH 1.4 F*1 21 H
5 67 INF 1BH
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6 67 INF 1BH
- 1.3 F*1 21 H
11 67 INF 1BH
- 1.3TO-1.3 F*1 21 H
24 67 MAN 18H
- 1.0TO- 0.9 F*1 21 H
25 67 SAN 1BH
- 3.9TO-3.8 F*1 21 H
34 67 INF 1BH 1.4 F*1 21 H
4 68 MAN 1BH
- 1.7TO-1.2 F*1 21 H
5 68 MAN 1BH
- 1.4TO-1.2 F*1 21 H
7 68 MAN 1BH
- 1.4TO-1.2 F*1 21 H
12 68 INF 1BH 1.3 F*1 21 H
13 68 INF 1BH
- 1.4 F*1 21 H
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- 1.4TO-1.2 F*1 21 H
4 69 INF 1BH 1.4 F*1 21 H
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December 28.1998 Page 17 21 H I 14 69 INF 1BH
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16 69 INF 1BH
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- 1.3TO-1.2 F*1 21 H
5 71 INF 1BH
- 1.4TO-1.3 F*1 21 H
9 71 INF 1BH
- 1.5TO-1.4 F*1 21 H
10 71 MAN 1BH
- 1.4TO-1.2 F*1 21 H
11 71 MAN 1BH
- 1.2TO-1.1 F*1 21 H
5 72 INF 1BH
- 1.4TO-1.4 F*1 21 H
8 72 MAN 1BH
- 1.0TO- 0.9 F*1 21 H
11 72 MAN 1BH 1.3TO-1.2 F*1 21 H
17 72 INF 1BH 1.4 F*1 21 H
3 73 MAN 1BH
- 1.4TO-1.2 F*1 21 H
5 73 MAN 1BH
- 1.3TO-1.1 F*1 21 H
10 73 INF 1BH 1.5TO-1.5 F*1 21 H
11 73 MAN 1BH
- 1.3TO-1.2 F*1 21 H
3 74 SAN 1BH 1.3TO-1.2 F*1 21 H
4 74 IN_F 1BH 1.4 F*1 21 H
5 74 MAN 1BH 1.3TO-1.1 F*1 21 H
9 74 MAN 1BH
- 1.3TO-1.1 F*1 21 H
11 74 MAN 1BH
- 1.3TO-1.1 F*1 21 H
5 75 MAN 1BH 1.3TO-1.1 F*1 21 H
7 76 INF 1BH 1.4 F*1 21 H
9 76 INF 1BH 1.4 F*1 21 H
6 77 INR 1BH 1.4 F*1 21 H
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11 77 INF 1BH 1.5TT 1.4 F*1 21 H
22 77 SAN 1BH
- 1.2TO-1.1 F*1 21 H
3 78 INF 1BH
- 1.5TO-1.4 F*1 21 H
5 78 INF 1BH 1.4 F*1 21 H
7 78 MAN 1BH
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- 1.6TO-1.5 F*1 sgt9792. doc i
A,ttachment 3 Deamb:r 28,1998 Page 18 21 H
5 80 SAN 1BH
- 1.6TO-1.2 F*1 21 H
12 80 INF 1BH
- 1.5 F*1 21 H
28 80 SAN 1BH
- 1.3TO-1.2 F*1 21 H
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1 82 INF 1BH
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7 82 INF 1BH
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9 83 INF 1BH
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4 17 INF 2BH
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4 25 SAN 2BH
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13 29 SAN 2BH
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5 36 MAN 2BH
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14 36 NDF TRH
+ 0.0 F*2 21 H
14 40 MAN 2BH
- 2.9TO-1.4 F*2 21 H
10 44 SAN 2BH
- 2.9TO-2.D F*2 21 H
12 46 MAN 2BH
- 2.7TO-1.8 F*2 21 H
20 46 SAN 2BH
- 2.0TO- 0.9 F*2 21 H
6 47 SAN 2BH
- 2.9TO-2.0 F*2 4
21 H
18 47 INF 2BH
- 3.1TO-3.1 F*2 21 H
10 48 SAN 2BH
- 2.8TO-2.2 F*2 21 H
8 49 SAN 2BH
- 2.9TO-1.9 F*2 21 H
14 50 SAN 2BH
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21 H
12 52 INF 2BH
- 1.9TO-1.8 F*2 21 H
4 55 SAN 2BH
- 0.7TO- 0.6 F*2 21 H
11 55 SAN 2BH
- 0.6TO- 0.5 F*2 21 H
16 56 SAN 2BH
- 2.0TO-1.7 F*2 21 H
7 61 SAN 2BH
- 0.7TO- 0.6 F*2 l
21 H
8 64 SAN 2BH
- 0.6TO- 0.5 F'? _
21 H
7 67 SAN 2BH
- 0.7TO- 0.5 F*2 Total Count, F*0 102 Total Count, F*1 576 l
Total Count, F*2 22 l
~
F*0 = F* TUBE WITHOUT ADDITIONAL ROLL EXPANSION F*1 = F* TUBE WITH ONE ADDITIONAL ROLL EXPANSION F*2 = F* TUBE WITH TWO ADDITIONAL ROLL EXPANSIONS l
MAI = MULTIPLE AXIAL INDICATION 3
SAI = SINGLE AXIAL INDICATION 3
MAN = MULTIPLE AXIAL INDICATION, not changed this year l l
sgt97u2. doc
Attachm:nt 3 Dec;mb:r 28,1998 Page 19 SAN = SINGLE AXIAL INDICATION, not changed this year l
l TRH = TOP OF ROLL HOT LEG l-l l
1BH = BOTTOM OF ADDITIONAL HARD ROLL 1 2BH = BOTTOM OF ADDITIONAL HARD ROLL 2 A
4 i
. sgt97u2. doc.
1 1
Dactmber 28,1998 Page 20 1
22 Steam Generator F* Tubes, November,1998 l
GEN LEG ROW COL INDICATION LOCATION & EXTENT STATUS 22 H
1 7
SAN TRH
- 2.4TO-2.3 F*0 22 H
1 27 sal TRH
- 2.6TO-2.5 F*0 22 H
2 29 SAI TRH
- 2.3TO-2.3 F*0 22 H
1 32 SAI TRH
- 2.5TO-2.4 F*0 22 H
1 33 MAN TRH
- 2.6TO-2.4 F*0 22 H
1 34 SAN TRH
- 2.GTO-2.5 F*0 22 H
42 35 SAI TRH
- 2.6TO-2.5 F*0 22 H
1 36 SAI TRH
- 2.7TO-2.6 F*0 22 H
1 37 MAN TRH
- 2.3TO-2.2 F*0
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22 H
1 41 MAN TRH
- 2.3TO-2.2 F*0 22 H
2 42 SAN TRH
- 2.3TO-2.2 F*0 22 H
1 43 MAN TRH
- 2.6TO-2.3 F*0 22 H
1 45 MAN TRH
- 2.4TO-2.2 F*0 22 H
2 45 SAI TRH
- 2.1TO-2.0 F*0 22 H
9 48 SAN TRH
- 2.3TO-2.2 F*0 l
22 H
10 48 SAI TRH
- 2.3TO-2.2 F*0 22 H
37 eB SAI TRH
- 2.3TO-2.2 F*0 22 H
5 49 SAN TRH
- 2.5TO-2.4 F*0 22 H
7 49 SAN TRH
- 2.8TO-2.5 F*0 22 H
7 50 SAN TRH
- 2.6TO-2.5 F*0 22 H
10 50 SAI TRH
- 2.4TO-2.4 F*0 22 H
1 51 MAN TRH
- 2.7TO-2.5 F*0 22 H
3 51 SAI TRH
- 2.4TO-2.4 F*0 i
22 H
4 51 MAN TRH
- 2.5TO-2.4 F*0 22 H
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22 H
12 79 MAN 1BH 1.2TO-1.0 F*1 i
22 H
13 79 MAN 1BH
- 1.2TO-1.0 F*1 22 H
14 79 MAN 1BH 1.2TO-1.1 F*1 22 H
15 79 INF 1BH
- 1.3TO-1.3 F*1 22 H
22 79 INF 1BH
- 1.3 F*1 l
22 H
25 79 INF 1BH
- 1.4 F*1 22 H
26 79 INF 1BH 1.5TO-1.5 F*1 22 H
9 80 MAN 1BH 1.2TO-1.1 F*1 22 H
10 80 INF 1BH
- 1.4 F*1 22 H
12 80 INF 1BH
- 1.4 F*1 22 H
13 80 MAN 1BH 1.2TO-1.1 F*1 22 H
15 80 INF 1BH
- 1.4 F*1 22 H
17 80 INF 1BH
- 1.5 F*1 22 H
9 81 INF 1BH
- 1.3 F*1 l
22 H
18 81 INF 1BH 1.3 F*1 22 H
22 81 SAN 1BH 1.5TO-1.4 F*1 22 H
12 82 INF 1BH
- 1.3 F*1 22 H
17 82 INF 18H
- 1.4 F*1 4
22 H
22 83 SAN 1BH
- 1.6TO-1.6 F*1 22 H
21 22 NDD l
F*2 ogt97u2. doc 4
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. _, _ _ _ ___ _ -.. _ _ _ _. _ _. _. _ _. _ _ _ _...... _.. ~.. _...... _. _ _.. _.. -
December 28,1998 Page 30 l
22 H
17 28 INF 2BH
- 2.1TO-1.9 F*2 22 H
27 30 SAN 2BH
- 2.0TO-1.8 F*2 22 H
15 31 INF 2BH
- 0.4TO- 0.3 F*2 22 H
14 35 SAN 2BH
- 3.1TO-2.9 F*2
-22 H
19 35 INF 2BH
- 3.2TO-3.2 F*2 22 H
37 35 INF 2EH
- 0.9TO- 0.8 F*2 l
22 H
19 36 INF 2BH
- 3.3 F*2 22 H
1 44 INF 2BH
- 3.3TO-3.2 F*2 -
l~
22 H
17 45 MAN 2BH
- 3.2TO-2.8 F*2 l
22 H
15 46 INF 2BH
- 3.3 F*2 22 H
27 48 SAN 2BH
- 3.1TO-3.0 F*2 _
22 H
26 50 INF 2BH
- 3.2TO-3.1 F*2 22.
H 18 52 INF 2BH- - 3.5 F*2 l
22 H
24 52 MAN 2BH
- 3.7TO-3.5 F*2 22 H
12 53 SAN 2BH
- 3.1TO-3.0 F*2 l
l 22 H
37 56 INF 2RH
- 3.2TO-3.2 F*2 l
22 H
13 58 SAI 2BH
- 0.6TO- 0.5 F*2 l
22 H
9 60 SAN 2BH
- 1.6TO-1.4 F*2 22 H
20 60 SAN 2BH
- 3.4TO-3.4 F*2 l
22 H
16 65 INF 2BH
- 3.1TO-3.0 F*2
)
l 22 H
19 74 SAN 2BH
- 2.2TO-1.6 F*2 Total Count, F*0 74 Total Count, F*1 342 Total Count, F*2 22 L
F*0 = F* TUBE WITHOUT ADDITIONAL ROLL EXPANSION l.
F*1 = F* TUBE WITH ONE ADDITIONAL ROLL EXPANSION l
F*2 = F* TUBE WITH TWO ADDITIONAL ROLL EXPANSIONS l
MAI = MULTIPLE AXIAL INDICATION sal = SINGLE AXIAL INDICATION l
MAN = MULTIPLE AXIAL INDICATION, not changed this year SAN = SINGLE AXIAL INDICATION, not changed this year INF = Indication Not Found from Last Year TRH = TOP OF ROLL HOT LEG l
l l
1BH = BOTTOM OF ADDITIONAL HARD ROLL 1 2BH -- BOTTOM OF ADDITIONAL HARD ROLL 2 l-t i
sot 97u2. doc l
t
ATTACHMENT 4 Prairie Island Unit 2 In Situ Test List - November 1998 Refueling Outage l
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Diczmber 28,1998 Page 2 Prairie Island Unit 2 Nov 1998 Steam Generator In Situ Pressure Tests Length Width Leakage Max.
SG Row Column Indication Location Voltage Reason inch deg.
Result Pressure 21 44 58 SVI TSC +7.8"
.0.13 Free Span VOL 0.2" 117 0
5350 21 22 23 MAI TRH + 2.9" 0.14 ODSCC 2.3" 137 0
2900 21 9
13 SAI TRH + 0.18" 1.83 RTZ PWSCC 0.1" 16 0
2900 21~
10 27 SAI TRH + 0.3" 0.79 RTZ PWSCC 0.4" 10 0
2900 21 13 58 MAI TRH + 0.07" 1.76 RTZ PWSCC 0.3" 20 0
2900 21 8
58 PLP 04H +0.4" 0.45 WEAR 0.4" 112 0
5350 21 9
58 PLP 04H +0.4" 0.3 WEAR 0.2" 105 0
5300 22 28 39 sal TRH + 18.5" 0.11 ODSCC 0.2" 100 0
2900 22 4
54 sal TRH + 2.5" 0.64 PWSCC 0.9" 5
0 2900 22 29 26 MAI TRH-0.23" 1.81 RTZ.PWSCC 0.1" 18 0
2900 l
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l l-l i'
l sgt97u2. doc i.
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