ML25141A100
| ML25141A100 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  (DPR-042) |
| Issue date: | 05/21/2025 |
| From: | Currier B Nuclear Management Co, Xcel Energy |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| L-Pl-25-018 | |
| Download: ML25141A100 (1) | |
Text
fl Xcel Energy May 21, 2025 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant, Unit 1 Docket No. 50-282 Renewed Facility Operating License No. DPR-42 1717 Wakonade Drive Welch, MN 55089 L-Pl-25-018 TS 5.6.7 Prairie Island Nuclear Generating Plant (PINGP) 2024 Unit 1 180-Day Steam Generator Tube Inspection Report Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy (hereafter "NSPM"), hereby submits the report of steam generator tube inspections performed during the 2024 refueling and maintenance outage on Unit 1 per Tech*nical Specification 5.6.7, Steam Generator Tube Inspection Report.
If you have any questions about this submittal, please contact Carrie Seipp, Senior Regulatory Engineer, at 612-330-5576.
Summary of Commitments Thi r
r
- c::
commitments and no revisions to existing commitments.
Bryan C;ier Plant Manager, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota Enclosure (1) cc:
Administrator, Region Ill, USNRC Project Manager, Prairie Island, USNRC Resident Inspector, Prairie Island, USNRC State of Minnesota
ENCLOSURE 1 Prairie Island Nuclear Generating Plant - Unit 1 2024 Steam Generator Tube Inspection Report In accordance with Prairie Island Nuclear Generating Plant (PINGP), Unit 1 Technical Specification 5.6.7, Xcel Energy Nuclear Department submits this report of steam generator tube inspections performed during the 2024 refueling and maintenance outage for Unit 1 (1 R34).
PINGP Unit 1 has two Framatome Model 56/19 Replacement Steam Generators (RSGs) with approximately 5,600 square meters of heat transfer area utilizing tubes with 19 millimeter outside diameter. Each RSG has 4,868 thermally-treated Alloy 690 U-tubes manufactured by Sandvik which have an outside diameter of 0.750 inch and a nominal wall thickness of 0.043 inch. The tubes are configured in a square pitch of 1.0425 inches with 55 rows and 114 columns (see Figure 1). The tube u-bends vary in radius from 2.7000 inches for a row 1 tube to 58.9950 inches for a row 55 tube. The tubes vary in length from 738.16 inches for row 1 tubes to 923.04 inches for row 55 tubes. Row 1 through row 9 tubes were subject to stress relieving following the bending process using the thermal treatment process for an additional 2-hour minimum soak time. The tubes were hydraulically expanded at each end for the full depth of the tubesheet with the expansion transition being between 0.079 inches and 0.236 inches below the secondary tubesheet face.
The tubesheet is low alloy steel 21.46 inches thick with alloys 82 and 182 cladding 0.375" thick for an overall thickness of 21.835 inches. The tubes are supported by eight tube support plates (TSPs) and five anti-vibration bars (AVBs) intersecting tubes between 1, 3, 5, 7 and 9 times (see Figure 2). There is one straight bar that intersects all rows at the center of each bend, two 57-degree bars that intersect rows 13 through 55 and two 14-degree bars that intersect rows 25 through 55. In addition, there are 24 peripheral tubes with nine staples (one at each AVB location) that carry the entire load of the complete AVB assembly. All TSPs are constructed from Type 410 stainless steel. The TSPs have a minimum thickness of 1.18 inch and have quatrefoil-shaped holes through which the tubes pass. The AVBs are constructed from Type 405 stainless steel and are rectangular in cross section (nominally 0.5 inch by 0.3 inch).
Each RSG is equipped with a Loose Parts Trapping Systems (LPTS), which is composed of screens at the top of the downcomer and at the top of the primary separators (cyclones).
These screens (0.14" square mesh formed from 0.031" diameter wire), prevent foreign material from entering the steam generator tube area from the main feedwater and auxiliary feedwater systems (see Figure 2).
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loose Parts T rarring Sy:sl:ems UPPERMOST TSP Figure 2 The original Westinghouse Model 51 Steam Generators (SGs) were replaced during the 2004 refueling outage after 25.73 EFPY of operation. During the 2006 refueling outage the first in service inspection (100% full length bobbin) was conducted on the RSGs after accumulating the initial 1.36 EFPY of RSG operation. Based on the lack of a definitive root cause for TSP wear and only a single cycle growth rate trend for both AVB and TSP wear identified during 1 R24, NSPM conservatively elected to inspect the RSGs during 1 R25 (2009 refueling outage) after an additional 1.62 EFPY of RSG operation (2.98 RSG cumulative EFPY). Based on the inspection results of both 1 R24 and 1 R25, NSPM elected to skip two inspections (1 R26 and 1 R27; 2009 and 2011 refueling outages, respectively) and perform an inspection of the RSGs during 1 R28 (2012 refueling outage) after an additional 4.17 EFPY of RSG operation (7.15 RSG cumulative EFPY). Based on the inspection results of 1 R28, NSPM elected to skip two additional inspections (1 R29 and 1 R30; 2014 and 2016 refueling outages, respectively) and perform an inspection of the RSGs during 1 R31 (2018 refueling outage) after an additional 5.17 EFPY of RSG operation (12.32 RSG cumulative EFPY). Most recently, there were two skip outages in 2020 and 2022, 1 R32 and 1 R33, amounting to 5.26 EFPY accumulated leading up to the 1 R34 inspection, which was 17.58 EFPY total on the RSGs.
There was no operational leakage reported during this operating interval. The average T HOT during the inspection interval was 591.4 °F in SG11 and 590.3 °F in SG12. There were no Degradation-Assessment-defined sub-populations of tubes with increased degradation susceptibility. There were no deviations taken from Mandatory and/or Needed (Shall) requirements important to tube integrity from the EPRI Guidelines referenced by NEI 97-06 since the last inspection.
NOTE:
Italicized text represents technical specification excerpts. Each excerpt is followed by the appropriate information intended to address each specific requirement, and also includes additional details based on benchmarking previous submittals, EPRI Tube Integrity Assessment Guidelines reporting requirements, and NRC Staff requests for additional information of peer Licensees. A legend of codes and field names is included at the end of the report.
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- 5. 6 Reporting Requirements
- 5. 6. 7 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5. 5. 8, Steam Generator (SG) Program.
Initial entry into MODE 4 occurred on December 1, 2024, dictating submittal of this report on or before May 30, 2025.
The report shall include:
a.
The scope of inspections performed on each SG, Table 1 and the notes that follow, provides the scope of inspections performed during 1 R34. There was no NOE inspection scope expansion required during Prairie Island 1 R34.
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Examination Probe Extent 100% Full Length of Open Bobbin Tube-End to Tube-End Tubes (Note 1)
Tubesheet Periphery An-ay TSP 0lH!C to Tube End
(?: 5 tubes into bundle)
Special Interest Array All new and existing wear indications detected from bobbin probe (AVB, TSP, Volumetric)
MRPC (Note 1)
PLPs and 1\vo-Tube Box-in of Target Tube MRPC (Note 1)
Existing Foreign Objects (DA Table 9-1)
New Foreign Objects (Two-Tube Box of Target Tube)
An-ay Indications in Tubes Adjacent to PreYiously Plugged Tubes Array Ne,v Tube Proximity Calls (PRX) or Bobbin Signal Changes in Tubes,,.,ith Historical PRX (DA Table 5-1)
Array Bobbin I-Codes Mag-Biased Penueability Variations (PVN)
Probe Plug Visual Inspection Visual All HL and CL installed plugs FOSAR Visual Secondary Side in-btmdle, annulus, tubelane and as-required locations based on ECT results Channel Head Visual HL and CL side per Reference 7 Notes:
- 1) Rows 1 thru 6 were inspected as two separate exams from both the hot leg and the cold leg tube end to A VB5 to complete the 100% inspection of these low row tubes
- 1) Alternative. array probe can be used for special interest exams of tubes with PLP signals or kno\\\\'11 foreign objects.
Page 5 of 12 TABLE 1
b.
The nondestructive examination techniques utilized for tubes with increased degradation susceptibility, Prairie Island does not have any specifically identified tubing areas with an increased degradation susceptibility. However, Array probe examination was implemented for the tubesheet periphery to a depth of at least 5 tubes. The examination was from the tube end to the first tube support on both the hot leg and cold leg sides for enhanced detection and sizing of potential loose parts.
- c. 1.
Nondestructive examination techniques utilized for each degradation mechanism
- found, Primary Side Inspections:
AVB wear and TSP wear were the only degradation mechanisms found in either of the SGs during 1 R34. The findings of the 1 R34 steam generator examination are bounded by the through-wall depth behavior projected in the 1 R31 operational assessment. Specifically, the deepest % TW sizing of any AVB wear indication by bobbin probe observed during U1 R34 was measured at 22% TW for SG12 tube R4 7C53. The deepest % TW sizing of any AVB wear indication by array probe observed during U1 R34 was measured at 24% TW for SG12 tube R35C53. Both of these depths are considerably less than the worst case projected AVB support wear indication of 33% TW from the U1 R31 Operational Assessment (OA).
Additionally, the deepest % TW sizing of any TSP wear indication by bobbin probe during 1 R34 was 24% at SG11 tube R25C08 and the deepest % TW sizing of any TSP wear indication by array probe during 1 R34 was 22% for SG12 tube R55C55.
Both of these depths are considerably less than the worst case projected TSP wear indication of 41 % TW from the U1 R31 OA.
None of AVB or TSP wear indications approached the condition monitoring (CM) limit. The Upper 95th percentile growth rates from 1 R34 have stabilized at low levels, having increased slightly for AVB wear and decreased slightly for TSP wear as compared to 1 R31, and the actual number of indications reported in 1 R34 is less than the projected number of indications in the 1 R31 operational assessment.
Secondary Side Inspections:
The steam separators, feed ring, and loose parts trapping system were examined in 1 R34, and no degradation or loose parts intrusion was detected.
Top-of-Tubesheet-During post sludge lancing and post eddy current FOSAR inspections, no tube degradation was observed that was associated with foreign objects visually observed or eddy current PLP indications recorded.
Table 2 and the notes that follow, provide the Electric Power Research Institute (EPRI) Examination Technique Specification Sheet (ETSS) (techniques) utilized during 1 R34 for existing and potential degradation.
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TABLE 2 CLASSIFICATION CD MECHANISM LOCATION PROBE TECHNIQUE<Il Existing Wear TSP AVB and Existing Wear Staple Potential Wear PLP Potential Wear Tube-to-Tube Bobbin X-ProbeTM Bobbin X-ProbeTM Bobbin X-ProbeTM
+Point' Bobbin X-Probe'
+Point' M96043.4 Rev. 1 M11956.1 Rev. 4 M96041.1 Rev. 8 M17909.2 Rev. 1 27091.2 Rev. 2 1790X.Y Rev. O© 2790Z.1 Rev. #<3>
13091.1 Rev. 0 13902.1 Rev. 0 13901.1 Rev. 1 Notes:
CD Existing or Potential degradation as defined in the EPRI SGMP: Steam Generator Integrity Assessment Guidelines, Revision 5.
a> Each listed technique was site validated for both detection and sizing except for PLP wear with the Bobbin probe which utilized the above listed technique for detection while sizing would have been based on the X-Probe TM and/or +Point' had PLP wear been detected.
M indicates the cited ETSS is an Appendix I qualified technique with system performance quantified using Model Assisted Probability of Detection (MAPOD).
© X represents 1 through 6 where the user selects the best EPRI ETSS based on the as found wear scar shape, Y represents.1 or.3 based on the applicable coil detection set and the user applies the published performance indices for that ETSS.
(3) b. represents 1 through 7 where the user selects the best EPRI ETSS based on the as found wear scar shape, '!1. represents the current revision and the user applies the published performance indices for that ETSS.
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d.
Location, orientation (if linear), and measured sizes (if available) of service induced indications, and voltage responses of each indication. For tube wear at support structures less than 20 percent through-wall, only the total number of indications needs to be reported Table 3 provides the location, orientation, and measured size of each reported AVB wear indication >=20% by bobbin or array in 12 Steam Generator for the degradation found during 1 R34. There were no indications >=20% in 11 Steam Generator. Additionally, not shown, there were 32 indications in SG11 and 62 indications in SG12 less than 20%. All the tubes were returned to service.
Tables 4 and 5 provide the location, orientation and measured size of each reported TSP wear indication >=20% by bobbin or array in each steam generator respectively for the degradation found during 1 R34. Additionally, not shown, there were 230 indications in SG11 and 134 indications in SG12 less than 20%. All the tubes in these two tables were returned to service.
There were no tubes preventatively plugged in 1 R34.
Table 3 -12 SG AVB Wear Indications>= 20%
Row Col Volts Ind Per Locn 35 53 2.46 VOL 24 AV5 47 53 2.13 VOL 23 AV6 47 53 0.8 PCT 22 AV6 54 54 1.75 VOL 21 AV6 54 54 0.66 PCT 21 AV8 39 66 1.68 VOL 20 AV4 39 66 2.23 VOL 23 AV7 Table 4 -11 SG TSP Wear Indications >=20%
Row Col Volts Ind Per Locn 25 8
0.27 PCT 24 05C 19 49 0.85 VOL 20 05H 54 50 0.86 VOL 20 05H 54 52 0.87 VOL 20 04H 55 58 0.22 PCT 20 03H 54 65 0.22 PCT 21 02C 48 66 0.22 PCT 21 03H 54 67 0.21 PCT 20 02C 53 68 0.23 PCT 21 02C 40 71 0.21 PCT 20 04H 49 72 0.22 PCT 21 03H 49 77 0.22 PCT 20 04H 51 77 0.22 PCT 20 02C 48 84 0.21 PCT 20 03H 11 111 0.21 PCT 20 05C Page 8 of 12
Table 5 -12 SG TSP Wear Indications >=20%
Row Col Volts Ind Per Locn 51 36 0.21 PCT 20 03H 51 41 0.26 PCT 23 04H 52 41 0.88 VOL 20 04H 52 41 0.24 PCT 22 04H 55 55 1.09 VOL 22 02C 55 57 0.21 PCT 20 04C 55 57 0.22 PCT 20 03C 55 57 0.23 PCT 21 02C 55 57 0.24 PCT 22 0lC 55 57 0.84 VOL 20 03C 54 59 0.8 VOL 20 02C 53 60 0.21 PCT 20 05C 25 108 0.24 PCT 22 04C Page 9 of 12
e.
Number of tubes plugged during the inspection outage for each degradation mechanism, There were no tubes plugged during 1 R34.
f The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator, and Table 6 provides the total number and percentage of tubes plugged to date.
TABLE 6 PLUGGING SG 11 SG12 TOTAL 8
12 PERCENT 0.16%
0.25%
g.
The results of condition monitoring, including the results of tube pulls and in-situ testing.
During 1 R34, a total of 99 AVB support wear indications were reported in 45 tubes.
The largest indication detected at 1 R34 was 22% TW measured from bobbin probe in SG12 R47C53 tube at AV6. This indication was sized at 23% TW from the array probe. The CM limit for a 0.8-inch AVB wear flaw is 47.4% TW. This CM limit contains material, burst relation, and NOE measurement uncertainties from ETSS 196041.1 at 95% probability and 0.50 confidence level (95/50). Therefore, the NOE measured flaw can be compared directly to this Condition Monitoring limit. The entire AVB wear population demonstrates sufficient margin to the Condition Monitoring limit. Therefore, the Condition Monitoring SG structural performance criteria has been satisfied for the AVB wear degradation mechanism.
During 1 R34, a total of 390 TSP wear indications were reported in 321 tubes. The largest indication detected at 1 R34 was 24% TW measured from the bobbin probe in SG11 tube R25C08 at 05C. This indication was sized at 18% TW from the array probe. The CM limit for a 1.25-inch TSP wear flaw is 45.0% TW. This CM limit contains material, burst relation, and NOE measurement uncertainties from 196043.4 at 95% probability and 0.50 confidence level (95/50). Therefore, the NOE measured flaw can be compared directly to this CM limit. It should also be noted that this CM limit is for TSP wear exhibiting a flat wear profile. The vast majority of the TSP wear population was observed to be tapered during 1 R34, which would correlate to a higher Condition Monitoring limit using the concepts of structural equivalent depth and length. However, the entire flaw population is conservatively treated as flat wear. The entire TSP wear population demonstrates sufficient margin to the Condition Monitoring limit. Therefore, the Condition Monitoring SG structural performance criteria has been satisfied for the TSP wear degradation mechanism.
Additionally, an operational assessment (OA) was performed that provides reasonable assurance that the performance criteria will not be exceeded until the next planned SG inspection.
The deterministic worst-case degraded tube Operational Assessment predicts a projected depth of:
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- 47.2% for the largest AVB wear indication returned to service,
- 47.0% for the largest TSP wear indication returned to service, based on the bobbin results after an 8.0 EFPY operating interval. Since the largest indication returning to service is greater than the 95th percentile detection threshold for the inspection for both AVB and TSP wear, this conclusion also applies to the assumed undetected indications. The OA also concludes that the structural and leakage integrity performance criteria will be maintained for a 4-cycle inspection interval for all degradation mechanisms observed.
Wear projections employed wear rates bounding of the 95th percentile wear rates for AVB wear and TSP wear experienced over the last three inspections for each Unit.
The structural limit for the OA assessment considered material property and burst relation uncertainties combined using Monte Carlo method Undetected flaws are considered in the OA with an assumed depth equal to the 95th percentile using MAPOD software with EPRI ETSS specific voltage-depth correlation and bounding site-specific noise measurements from the current inspection inputs.
A confirmatory fully probabilistic OA was also run using the software Full Bundle Model (FBM), Version 3.0, which showed for the limiting case, the 4-cycle burst pressure for AVB wear was 4917 psi and the 1.52-cycle burst pressure for TSP wear was 4596 psi, against a performance criterion of 4500 psi.
A top of tubesheet deposit cleaning process was performed in both SGs during Prairie Island U 1 R34. There are two main purposes of the cleaning process.
The first is to remove hardened deposits that tend to form at the top of the tubesheet and the second is to force and filter out any loose parts or foreign objects that have migrated to the SG secondary side during operation. The dry mass of deposit material and debris removed by the top of tubesheet cleaning process was 11.6 lbs. in SG11 and 15.2 lbs. in SG12. The subsequent secondary side visual inspections showed the tubesheet to be essentially free of deposits with only limited hard sludge piles.
Visual inspections were performed of the SG channel head bowl in both SGs.
These inspections are performed based on industry operating experience and guideline requirements. Visual inspections of the SG hot leg and cold leg divider plate, inclusive of the entire divider-plate-to-channel-head weld and all visible clad surfaces, were performed in accordance with the latest revision of Westinghouse NSAL-12-1. Satisfactory inspection results were observed in both SGs with no indications of corrosion or cladding damage observed. Further, all previously installed tube plugs were also visually inspected by remote video camera from the primary side in each SG. The inspection results were satisfactory and showed no indication of tube plug leakage or failure.
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LEGEND OF FIELDS AND CODES FIELD Row Col Volts Ind Pct Locn FIELD Ind Locn EXPLANATION Row number of tube location Column number of tube location Measured Voltage Three Digit Code - see below Measured percent through wall Location of landmark - see below CODE VOL WAR O?H AV?
O?C EXPLANATION Volumetric Wear
? = First through Eighth tube support plate on hot leg side
? = First through Ninth anti-vibration bar
? = First through Eighth tube support plate on cold leg side Page 12 of 12