ML24005A024

Revised Steam Generator Tube Inspection Reports, Refueling Outage 23 CC2R23

ML24005A024
Person / Time
Site:	Calvert Cliffs
Issue date:	01/05/2024
From:	Exelon Generation Co
To:	Office of Nuclear Reactor Regulation
Shared Package
ML24005A021	List: ML24005A022 ML24005A023 ML24005A024
References
TS 5.6.9
Download: ML24005A024 (1)

Text

Enclosure 2 Calvert Cliffs Nuclear Power Plant Unit 2 Revised Steam Generator Tube Inspection Report Refueling Outage 23 CC2R23 Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 2 of 22 Calvert Cliffs Nuclear Power Plant (CCNPP) Unit 2 Revised Steam Generator Tube Inspection Report Introduction In Reference 1, Constellation Energy Generation (CEG) submitted a request for an amendment to Renewed Facility Operating License No. DRP-69 for the Calvert Cliffs Nuclear Power Plant Unit 2 to adopt Technical Specifications Task Force (TSTF)-577, Revised Frequencies for Steam Generator Tube Inspections and Reference 2, Supplement to Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections". Reference 1 and 2 were approved by the Nuclear Regulatory Commission (NRC) in Reference 3. As noted in Reference 2, CEG will submit SG Tube Inspection Reports meeting the revised TS 5.6.9 requirements within 60 days after implementation of the license amendment at Braidwood. Based on NRC approval (Reference 3) TSTF-577 was implemented at CCNPP on November 15, 2023.

CCNPP Unit 2 Technical Specification (TS) 5.6.9, Steam Generator Tube Inspection Report, states A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program." This enclosure provides the 180-day report with the revised Unit 2 TS 5.6.9 reporting requirements in accordance with References 3. Each CCNPP Unit 2 TS 5.6.9 reporting requirement is listed below along with the associated information based on the inspection performed during the CCNPP Unit 2 February 2020 refueling outage (CC2R23), which was the last inspection of the CCNPP Unit 2 steam generators (SGs). The 180-Day report will follow the template provided in Appendix G to the Electric Power Research Institute (EPRI) Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 5 (Reference 4), which provides additional information beyond the CCNPP Unit 2 TS 5.6.9 reporting requirements.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 3 of 22

1. Design and operating parameters Calvert Cliffs Nuclear Power Plant Unit 2 (CCNPP2) has two recirculating steam generators designed and fabricated by Babcock and Wilcox (B&W) of Cambridge, Ontario, Canada. These replacement steam generators (RSGs), SG21 and SG22 were installed in 2003.

Table 1: CCNPP Steam Generator Design and Operating Parameters SG Model / Tube Material /

Number of SGs per Unit Babcock & Wilcox (Canada) Replacements / Alloy 690TT / 2 Number of tubes per SG /

Nominal Tube Diameter / Tube Thickness 8471 / 0.750 in. / 0.042 in Support Plate Style / Material Lattice Tube Support Grids and Fan Bars / 410 stainless steel Last Inspection Date February 2019 Effective full power months (EFPM) Since Last Inspection 46.1 EFPM [3.84 effective full power years (EFPY)]

(from CC2R21 to CC2R23)

Total Cumulative SG EFPY 15.05EFPY (as of CC2R23)

Mode 4 Initial Entry March 14th, 2019, from CC2R23 Observed Primary-to-Secondary Leak Rate No observed leakage Nominal Thot at Full Power Operation 595°F Degradation Mechanism Sub-Population Tubes located on the periphery of the tube bundle are in the highest cross-flow region and were considered in the CC2R23 Degradation Assessment to be more susceptible to foreign object wear.

SG program guideline deviations since last Inspection None SG Schematic See Figure 1 Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 4 of 22 Figure 1: Tube Support Arrangement for CCNPP B&W Replacement SGs Notes:

TEC - Tube End Cold Leg TEH - Tube End Hot Leg TSC - Top-of-Tubesheet Cold Leg TSH - Top-of-Tubesheet Hot Leg 01C - 07C - Lattice Grid Tube Supports on Cold Leg side 01H - 07H - Lattice Grid Tube Supports on Hot Leg side F01 - F12 - U-Bend Fan Bar Tube Supports Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 5 of 22

2. The scope of the inspections performed on each SG (TS 5.6.9.a) and if applicable, a discussion of the reason for scope expansion Primary Side Eddy Current Scope The following inspections were performed during CC2R23 to ensure that 100% of the tubes were inspected during the period as required by TS 5.5.8.d.2 Bobbin Probe Eddy Current Testing (ECT) Examinations:

o 100% of the in-service tubes will be inspected full length, tube-end hot (TEH) to tube-end cold (TEC), using the bobbin probe.

Array Probe ECT Examinations:

o 100% (X-Probe) examination on the Hot and Cold Legs from the first support to the tube end for potential foreign objects and associated wear.

o All previous Possible Loose Parts indications (PLPs) (part not removed) plus a one tube bounding examination of such tubes at the elevation of interest o A one-tube border region around all tubes previously plugged for Loose Part Wear (LPW) o Inspect a one-tube border region around all tubes previously plugged for PLPs Special Interest Examinations o All newly reported array probe Possible Loose Parts (PLPs) o The twenty deepest Fan Bar Wear (FBW) bobbin indications in each SG o Ten deepest wear indications detected at lattice supports in each SG (or all if there are less than ten) o All foreign objects identified by secondary side visual inspection plus a one-tube bounding examination of tubes surrounding the foreign object o A sample of Manufacturing Burnish Marks (MBMs), Dents (DNTs), and Dings (DNGs) as directed by Engineering There was no scope expansion required or performed during the CC2R23 eddy current inspections.

Primary Side Visual Inspection Scope The primary side channel head (hot and cold leg) of both steam generators was visually inspected using a remote operated camera in accordance with CCNPP inspection procedures. The channel head general area and cladding was inspected for the following: through holes or breaches that would expose carbon steel base material under the cladding, rust colored discoloration or stains visible on cladding surface, and channel head cladding degradation such as cracks or significant deformation.

The tubesheet, tube ends, and tube plugs were inspected for the following: cracking, degradation, water leakage, boron deposits, and tube sheet or tube end deformation. No degradation was observed in any of these areas in either steam generator.

The divider plate was visually inspected from both hot and cold legs using a remote camera specifically looking for the following: cracks on the divider plate surface, surface deformation, foreign material that may mask any degradation, and any other degradation. Special attention was made when inspecting the weld deposit seat bar, divider plate weld, divider plate corner windows, and the Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 6 of 22 divider plate weld heat affected zone. No degradation was observed in any of these areas in either steam generator.

Secondary Side Inspection Scope Secondary side inspections were performed with a variety of remote tooling. For each steam generator, a visual inspection (top of tubesheet) was performed after sludge lancing including:

100% of the annulus to a minimum of 6 tubes deep 100% of the no-tube lane to a minimum of 6 tubes deep Blowdown and drain holes Shroud supports Inspection of tube support structures (1st support only)

In-bundle inspection of previously identified foreign objects at the top of tubesheet In-bundle inspection of ECT-detected PLPs at the top of tubesheet A steam drum and upper internals inspection was performed on SG22. The steam drum and upper internals inspection included:

Upper Internals Visual Inspection o Primary moisture separators o Secondary moisture separators o Steam outlet venturi o Secondary deck seal skirt o General area structures, hatches, and welds o Feedwater header general area Laser profilometry of all secondary moisture separator base plates and sidewalls in SG22

3. The nondestructive examination techniques utilized for tubes with increased degradation susceptibility (TS 5.6.9.b)

Tubes located on the periphery of the tube bundle are in the highest cross-flow region and were considered in the Degradation Assessment to be more susceptible to foreign object wear, especially near the tubesheet where most foreign objects are located. As a compensatory measure, tubes in this region were tested with an array (X-probe) which has increased sensitivity for detection of foreign objects and foreign object wear close to the tubesheet. This scope encompassed 100% of the hot and cold leg tubes from the tube end to the 1st tube support (01C/01H).

4. For each degradation mechanism found: The nondestructive examination technique utilized (TS 5.6.9.c.1)

Steam Generator eddy current examination techniques used (see Table 2 below) were qualified in accordance with Appendix H or Appendix I of the EPRI PWR SG Examination Guidelines Revision 8. Each examination technique was evaluated to be applicable to the tubing and the degradation mechanisms found in the CCNPP SGs during CC2R23.

The bobbin probe was used as the primary means of detecting tube degradation except for loose Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 7 of 22 parts/wear located between the Top of Tubesheet (TTS) and the first lattice support. At this location, the Array probe was used for the primary means of detection, along with detection of TTS expansion transition Intergranular Attack / Stress Corrosion Cracking (IGA/SCC) and pitting (proactive examinations). The rotating coil probe was used primarily as a diagnostic and sizing tool for indication characterization.

Table 2: Non-Destructive Examination (NDE) Techniques for Sizing Each Existing Degradation Mechanism Found During CC2R23 Location Degradation Mechanism Orientation Probe EPRI ETSS1 EPRI ETSS1 Rev Fan Bar (U-bend)

Wear Vol Bobbin Array I-96041.1 17909.1 5

0 Lattice Grid (Horz. Support)

Wear Vol Bobbin Array 96004.1 11956.3 13 2

Foreign Object at top of tubesheet or lattice grid Wear Vol Array

+Point 17901.1 27901.1 0

1

1.

ETSS - Examination Technique Specification Sheet

5. For each degradation mechanism found: The location, orientation (if linear), measured size (if available), and voltage response for each indication. For tube wear at support structures less than 20 percent through-wall, only the total number of indications needs to be reported (TS 5.6.9.c.2)

Three degradations mechanisms were confirmed to be present in the CCNPP Unit 2 SGs. These were: 1) fan bar wear, 2) lattice grid support wear, and 3) foreign object wear. No other degradation mechanisms, including tube-to-tube wear, were detected. Table 3 provides the number of indications reported during the CC2R23 inspection.

Table 3: Number of Indications Detected for Each Degradation Mechanism in CC2R23 Degradation Mechanism SG21 SG22 Total Indications Indications Fan Bar Wear 134 287 421 Lattice Grid Support Wear 2

1 3

Foreign Object Wear 14 8

22 Table 4 provides a listing of all the fan bar wear indications 20%TW or greater reported during the CC2R23 inspection including the measured depths from the array probe.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 8 of 22 Table 4: CC2R23 Fan Bar Wear Indications >20%TW SG Row Col Location Array Depth

(%TW)

Voltage (Bobbin)

SG21 95 87 F08+1.71 20 0.36 SG21 104 88 F06-0.73 22 0.42 SG21 106 76 F06+1.20 20 0.60 SG21 108 76 F06+1.15 25 0.92 SG22 79 93 F08+1.49 26 0.56 SG22 83 73 F08+0.79 20 0.36 SG22 84 94 F08+0.79 20 0.37 SG22 87 83 F07-0.04 24 0.49 SG22 89 73 F08+0.77 21 0.39 SG22 91 65 F08+0.70 22 0.44 SG22 106 82 F07+0.80 20 0.38 SG22 106 90 F07+1.21 21 0.40 SG22 107 81 F06-0.79 22 0.43 SG22 108 82 F07+0.74 20 0.37 SG22 108 86 F06-1.20 25 0.91 SG22 109 77 F06-0.77 21 0.41 SG22 109 79 F06-0.75 23 0.45 SG22 111 73 F06-1.34 27 0.61 SG22 111 75 F06-0.83 22 0.43 SG22 111 77 F06-0.83 27 0.62 SG22 113 77 F06-0.81 28 0.68 SG22 113 91 F02-2.26 20 0.36 SG22 116 82 F07+1.25 21 0.39 SG22 123 83 F07+0.15 27 0.96

1. Flaw length data unavailable for flaws listed above Three indications of wear related to the lattice grid supports were reported during the CC2R23 outage. All three of these indications were reported in the previous inspection (CC2R21). All of these indications were inspected with array probes to confirm that the morphologies of the indications were consistent with lattice grid wear and not some other damage mechanism such as foreign object wear. No lattice grid wear indications were reported to be greater than 20%TW.

The deepest lattice grid wear indication reported was 13%TW in SG 22.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 9 of 22 Table 5 provides a listing of all the foreign object wear indications reported during the CC2R23 inspection including the measured voltages, depths, and measured dimensions from the plus-point probe. Twenty-two foreign object wear indications were detected in 18 tubes. All but one of the indications were reported in previous outages. All these indications were sized using

+Point' ETSS 27901.1 and had measured depths ranging from 14%TW to 34%TW. Since the parts were no longer present, as expected, there was no noticeable change in the depths of these indications.

All these foreign object wear indications were sized below the plugging limit. Since no objects were present to cause further wear and all wear indications were less than the 40%TW Tech Spec. plugging limit (5.5.9.c), all 18 tubes were returned to service.

Table 5: CC2R23 Foreign Object Wear Indications SG Row Col Location Array Voltage Array Depth

(%TW)

Axial Extent (Inches)

SG21 12 66 TSH +0.10 0.75 28 0.18 SG21 12 66 TSH +0.38 0.48 22 0.31 SG21 12 162 TSH +0.05 0.85 30 0.15 SG21 13 65 TSH +0.05 0.59 25 0.15 SG21 14 66 TSH +0.44 0.18 17 0.23 SG21 14 66 TSH +0.44 0.28 14 0.23 SG21 72 146 TSH +0.23 1.15 34 0.23 SG21 75 147 TSH +18.11 0.31 18 0.20 SG21 77 147 TSH +17.63 0.3 18 0.23 SG21 77 149 TSH +20.72 0.37 20 0.28 SG21 121 117 TSH +0.61 0.41 21 0.28 SG21 137 73 TSC +14.98 0.32 18 0.38 SG21 137 75 TSC +14.43 0.59 25 0.38 SG21 137 75 TSC +14.76 0.26 16 0.36 SG22 14 4

TSC +0.48 0.64 26 0.38 SG22 17 1

TSC -0.05 0.36 19 0.33 SG22 18 2

TSC +0.18 0.45 22 0.26 SG22 82 42 04H -1.33 0.66 26 0.20 SG22 112 82 04H +37.85 0.41 21 0.33 SG22 124 116 TSC +12.76 0.18 14 0.20 SG22 126 116 TSC +12.56 1.08 18 0.23 SG22 126 116 TSC 12.84 0.32 33 0.33

1. Circumferential extent unavailable for the data listed above Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 10 of 22

6. For each degradation mechanism found: A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment (TS 5.6.9.c.3). Discuss any degradation that was not bounded by the prior operational assessment in terms of projected maximum flaw dimensions, minimum burst strength, and/or accident induced leak rate. Provide details of any in situ pressure test.

A condition monitoring (CM) assessment was performed as required by the CCNPP SG program.

The tube degradation detected during the CC2R23 inspection was due to fan bar wear, lattice grid wear, and foreign object wear at lattice grid supports. The deepest indication for each mechanism met condition monitoring analytically as shown in Figures 2, 3, and 4. The margin to the structural and condition monitoring limit curve for each detected wear indication can be determined from Figures 2, 3, and 4. The CM limit curves include uncertainties for material properties and NDE depth sizing. The deepest flaws have a depth less than the conservatively determined CM limit for all degradation mechanisms; therefore, the structural integrity performance criterion was met for the operating interval prior to CC2R23. A summary of the CM results from CC2R23 as compared to the Operational Assessment (OA) predictions from the most recent prior inspection (CC2R21) is provided in Table 6.

Figure 2: Condition Monitoring Results for Fan Bar Wear Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 11 of 22 Figure 3: Condition Monitoring Results for Lattice Grid Wear Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 12 of 22 Figure 4: Condition Monitoring Results for Foreign Object Wear Table 6: Comparison of Prior OA Projections to As-Found Results Parameter CC2R23 Projection1 CC2R23 As-Found1 Inspection Interval 4.0 EFPY 3.84 EFPY Fan Bar Wear Maximum Depth 43.3 %TW 28 %TW Lattice Grid Wear Maximum Depth 33.4 %TW 13 %TW Foreign Object Wear Maximum Depth

< 29 %TW 21 %TW2

1.

NDE Depths are reported for both projected and as found results

2. No new wear associated with previously observed Foreign Object (FO) indications Volumetric wear indications will leak and burst at essentially the same pressure; therefore, accident-induced leakage integrity is also demonstrated. Operational leakage integrity was demonstrated by the absence of any detectable primary-to-secondary leakage during the Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 13 of 22 operating interval prior to CC2R23. Because tube integrity was demonstrated analytically, in-situ pressure testing was not required nor performed during CC2R23. There were no tube pulls planned or performed during CC2R23.

7. For each degradation mechanism found: The number of tubes plugged during the inspection outage (TS 5.6.9.c.4). Also, provide the tube location and reason for plugging.

No tubes required plugging during the CC2R23 SG inspections.

8. The repair methods utilized, and the number of tubes repaired by each repair method (TS 5.6.9.c.5).

No tubes were repaired during CC2R23.

9. An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results (TS 5.6.9.d). Include the effective full power months of operation permitted for the current operational assessment.

Summary Based on application of conservative fan bar, lattice grid, and foreign object wear growth rates, the condition of the CCNPP SG tubes has been analyzed with respect to continued operability of the SGs without exceeding the SG tube integrity performance criteria at the next scheduled SG eddy current inspection no later than CC2R26.

Fan Bar Wear OA For the fan bar wear OA, the Mixed Arithmetic/Simplified Statistical method from Table 8-1 of the EPRI Steam Generator Integrity Assessment Guidelines (Reference 4) was used. Using this method, a worst-case end-of-cycle (EOC) depth is projected by applying NDE uncertainties and a growth allowance to the deepest flaw returned to service. This projected EOC depth is then compared to an allowable EOC depth which is calculated using a Monte Carlo analysis which incorporates uncertainties in the burst pressure relationship and material properties.

For fan bar wear, the deepest indication returned to service was 28%TW. The NDE sizing parameters for ETSS 96041.1 are a slope of 1.01, an intercept of 0.99, and a standard error of 3.29%TW. Using the slope and intercept, a best estimate real depth of 29.3%TW is obtained for an indication with a measured depth of 28%TW.

The standard error of 3.29%TW from ETSS 96041.1 is the technique uncertainty. Further adjusting this value upward to an upper 95th percentile gives an NDE uncertainty of 5.4%TW (3.29 x 1.645).

Adding this uncertainty to the best estimate value of 29.3%TW from the previous paragraph yields a bounding real depth of 34.7%TW returned to service.

This hypothesized real depth of 34.7%TW must then be grown at an upper 95th growth rate for the next 6.0 EFPY and the upper 95th percentile growth rate is 0.8%TW per EFPY. Applying a growth of 4.8%TW (0.8 x 6.0) gives a bounding real depth at the end of the upcoming inspection interval of 39.5%TW.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 14 of 22 For an assumed bounding length of 1.8, the structural limit (SL) for this hypothesized limiting flaw is 50.7%TW (based on the SL for a 3.2 length flaw). The structural limit includes uncertainties for material properties and the burst pressure relationship and is the allowable real depth for a flaw of a given length. Since the projected real depth of 39.5%TW is less than the structural limit of 50.7%TW, there is reasonable assurance that structural integrity will be maintained until the next scheduled inspection (CC2R26).

The projected EOC depth is believed to be very conservative since it pairs the deepest indication returned to service in CC2R23 with upper 95th percentile values for both NDE uncertainties and growth rates. In addition to the conservative depth projection, a fixed length of 1.8 inches was also used. This value is likely very conservative due to the tapered shape of most of the fan bar wear indications. With a tapered flaw shape, the structural lengths of most of these flaws are expected to be less than 1 inch.

Lattice Grid Wear OA Unlike fan bar wear, there is too little data to calculate a reliable upper 95th percentile growth rate for lattice grid wear. All three of the reported lattice grid wear indications were reported in the previous CC2R21 inspection. The largest growth rate among these three indications was 1.0%TW per EFPY (4%TW over 3.83 EFPY). Due to the limited population and the low growth rates of the existing indications, an assumed growth rate of 2.0%TW per EFPY will be used in the OA. This is consistent with the 95th percentile growth rate used for the fan bar wear analysis.

The measured lengths of the lattice grid flaws are all less than 0.5 inches. However, since the high bar lattice grids are 3.15 inches tall, a bounding flaw length of 3.2 inches will be used in the analysis.

Using the same Mixed Arithmetic/Simplified Statistical method that was used for the fan bar wear analysis and bobbin ETSS 96004.1, a best estimate real depth is obtained as follows. The deepest lattice grid wear indication returned to service measured 13%TW. The NDE sizing parameters for ETSS 96004.1 are a slope of 0.98, an intercept of 2.89, and a standard error of 4.19%TW. Using the slope and intercept, a best estimate real depth of 15.6%TW is obtained for an indication with a measured depth of 13%TW.

The standard error of 4.19%TW from ETSS 96004.1 is the technique uncertainty. Further adjusting this value upward to an upper 95th percentile gives an NDE uncertainty of 6.9%TW (4.19 x 1.645).

Adding this uncertainty to the best estimate value of 15.6%TW from the previous paragraph yields a bounding real depth of 22.5%TW returned to service.

This hypothesized real depth of 22.5%TW must then be grown at an upper 95th growth rate for the next 6.0 EFPY. As discussed above, a growth rate of 2.0%TW per EFPY will be used. Applying a growth of 12.0%TW (2.0 %TW/EFPY x 6.0 EFPY) gives a bounding real depth at the end of the upcoming inspection interval of 34.5%TW.

For a flaw with an assumed bounding length of 3.2 inches, the structural limit is 49.5%TW. Since the projected depth of 34.5%TW is less than this value, there is reasonable assurance that structural integrity will be maintained until the next scheduled inspection.

Tube Wear from Existing, Remaining, and New Foreign Objects OA The maximum wear rate observed for foreign objects over the previous operating interval can be used to calculate a maximum run time for newly initiated foreign object wear. The deepest Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 15 of 22 new foreign object wear scar was 21%TW, suggesting a growth rate of 5.5%TW/EFPY over the previous operating interval of 3.83 EFPY. Assuming a similar growth rate for a newly initiated wear scar and a structural limit of 52%TW, which is associated with a conservative scar length of 1.0 and a limited circumferential extent of less than 135° a maximum run time can be calculated.

=

=

52%

5.5%/ = 9.5 The maximum calculated run time of 9.5 EFPY is longer than the next projected interval of 3 cycles before the next SG inspection (~5.7 EFPY). Provided the steam generators operate for a shorter period than this maximum run time before their next inspection, there is reasonable assurance that foreign object wear associated with the observed parts will not exceed the performance criteria prior to the next inspection of the Calvert Cliffs Unit 2 steam generators.

For those objects not detected or those objects that enter the bundle during operation, there is experience that the plant can operate multiple cycles with foreign objects in the bundle without tube wear exceeding the condition monitoring limit or leakage occurring. As such, there is reasonable assurance that foreign objects will not cause wear that exceeds the structural integrity performance criteria prior to the next tube examination in each steam generator.

Because no wear exceeding the structural criteria is expected, there is reasonable assurance that the operational leakage and accident leakage performance criteria will not be exceeded by foreign object wear prior to the next tube examination in each steam generator (CC2R26).

Table 9: Comparison of OA Projections at Next SG Inspection to Structural Limits Degradation Mechanism (wear)

Maximum depth (%) Predicted at Next Inspection Structural limit depth (%)

Fan Bar support 39.5 50.7 Lattice Grid support 34.5 49.5 Existing FO Wear No Growth (FO removed) 52.0 Remaining FOs All FOs identified capable of wear were removed New FOs

<52.0 for 3-cycles (~5.7 EFPY)

10. The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG (TS 5.6.9.e).

Table 10 shows the number of tubes plugged as of the CC2R23 outage and the percentage of tubes currently plugged (total and effective). No sleeves have been installed in the CCNPP replacement SGs. No tube plugging was required or performed in either SG during CC2R23.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 16 of 22 Table 10: Tube Plugging to Date (Number and Percentage per SG) (TS 5.6.9.e)

SG21 SG22 Total Plugged prior to CC2R23 37 32 69 Plugged during CC2R23 0

0 0

Total Plugged through CC2R23 37 32 69 Total/Effective Percent Plugged through CC2R23 0.44%

0.38%

0.41%

11. The results of any SG secondary-side inspection (TS 5.6.9.f). The number, type, and location (if available) of loose parts that could damage tubes removed or left in service in each SG.

Secondary Side Scope:

For each steam generator, a visual inspection (top of tubesheet) was performed after sludge lancing including:

100% of the annulus to a minimum of 6 tubes deep 100% of the no-tube lane to a minimum of 6 tubes deep Blowdown and drain holes Shroud supports Inspection of tube support structures (1st support only)

In-bundle inspection of previously identified FOs as directed by Engineering In-bundle inspection of ECT-detected PLPs as directed by Engineering Assessment of sludge height on both HL and CL A steam drum and upper internals inspection was performed on SG22. The steam drum and upper internals inspection included:

Upper Internals Visual Inspection o Primary moisture separators o Secondary moisture separators o Steam outlet venturi o Secondary deck seal skirt o General area structures, hatches, and welds o Upper tube bundle Laser profilometry of all secondary moisture separator base plates and sidewalls Secondary Side Visual Inspections of Tubesheet and FOSAR Secondary side tubesheet visual inspections were performed following sludge lancing activities in both SGs. High flow regions of the annulus, no tube lane and periphery (a minimum of 6 tubes deep) were visually inspected for foreign material. Additionally, multiple columns for the full depth of the tube bundle interior (kidney region) were evaluated for sludge lancing effectiveness and sludge accumulation.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 17 of 22 Water lancing was performed in both SGs followed by secondary side visual inspections of the periphery, no-tube lane, and inner bundle passes. The TTS sludge heights were measured from bobbin ECT results. Small regions of hard sludge accumulation less than 2.6 inches in height were identified in the hot and cold legs kidney region of both SGs.

Foreign object search and retrieval (FOSAR) was performed on a variety of foreign objects identified from visual inspections as well as ECT PLPs and FO Wear indications as summarized in Table 11.

All metallic or potential metallic objects that could cause wear were removed from SG21 and SG22 during CC2R23.

Table 11: Foreign Object Search and Retrieval Summary SG Row Col Location Ref ID CC2R23 Disposition Material Status 21 110 126 TSH3 2140 Legacy metallic object, position has not changed since previous inspection. All affected tubes were NDD1 with ECT, no further actions required at CC2R23 Metallic Remains 21 138 84 TSC2 21100 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 138 80 TSH 21101 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, No further actions required at CC2R23 Flex Gasket Removed 21 74 148 TSC 21109 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 133 105 TSH 21114 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 126 104 TSH 21115 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 121 55 TSC 21124 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 54 14 TSC 21126 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 18 of 22 21 52 12 TSH 21129 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 87 27 TSH 21131 Object Removed and Confirmed as Wire, all affected tubes were NDD with ECT, no further actions required at CC2R23 Wire Removed 21 123 47 TSH 21132 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 114 54 TSH 21133 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 125 73 TSH 21138 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 77 15 TSH 21141 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 21 15 63 TSH 21143 Object Removed and Confirmed as Wire, all affected tubes were NDD with ECT, no further actions required at CC2R23 Wire Removed 21 113 93 TSC 21147 Object Removed and Confirmed as Wire, all affected tubes were NDD with ECT, no further actions required at CC2R23 Wire Removed 21 106 126 TSH 21149 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex Gasket Removed 22 135 77 TSH 2210 Legacy metallic object, position has not changed since previous inspection. All affected tubes were NDD with ECT, no further actions required at CC2R23 Metallic Remains 22 126 62 TSH 2212 Legacy weld slag, position has not changed since previous inspection. All affected tubes were NDD with ECT, no further actions required at CC2R23 Metallic Remains Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 19 of 22 22 131 95 TSC 2225 Legacy wire that was identified in a previous outage, part was removed. No further actions required.

Metallic Removed 22 40 88 TSH 2234 Legacy Flex Gasket, identified as an ECT PLP2 during CC2R23, part was removed during CC2R23, all bounding tubes were NDD, no further actions necessary Flex gasket Removed 22 131 69 TSH 2240 Legacy metallic object, position has not changed since previous inspection. All affected tubes were NDD with ECT, no further actions required at CC2R23 Metallic Remains 22 93 37 TSH 2247 Legacy Flex Gasket, part was removed during CC2R23, all bounding tubes were NDD, no further actions necessary Metallic Removed 22 137 77 TSH 22100 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 138 66 TSH 22101 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 74 152 TSC 22102 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 138 84 TSC 22103 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 49 151 TSC 22105 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 115 121 TSC 22108 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 127 115 TSC 22109 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 20 of 22 22 129 57 TSH 22117 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 96 36 TSH 22119 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 92 30 TSH 22120 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 37 7

TSC 22125 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 40 10 TSC 22126 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 51 13 TSC 22127 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 102 40 TSC 22128 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed 22 112 96 TSH 22144 Object Removed and Confirmed as Wire Rod, all affected tubes were NDD with ECT, no further actions required at CC2R23 Wire Rod Removed 22 62 156 TSC 22147 Object Removed and Confirmed as Flexitallic Gasket, all affected tubes were NDD with ECT, no further actions required at CC2R23 Flex gasket Removed

1.

NDD - No Degradation Detected

2.

TSC - Tubesheet Cold

3.

TSH - Tubesheet Hot Steam drum and upper internals inspection Planned steam drum and upper tube bundle inspections were performed in SG22. No evidence of degradation or structural distortion was observed in the steam drum.

The primary and secondary separators appeared to be in good condition with no through-holes noted. This condition is typical of all secondary separators that were inspected. The separators were fabricated from carbon steel and have a minimum chromium content of 0.14% to resist Flow Accelerated Corrosion (FAC), therefore, FAC of the separators is not expected. The secondary separator base plates were scanned with a laser profilometer to determine the specific degree of degradation (if any) to the base plates. The laser scanning results confirmed Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 21 of 22 no significant degradation.

Select regions of the upper tube bundle in SG22 were visually inspected, showing some deposits on the tubes, no other anomalous conditions were identified in this region.

12. The scope, method, and results of secondary-side cleaning performed in each SG Prior to the secondary side FOSAR inspections, sludge, scale, foreign objects, and other deposit accumulations at the top of the tubesheet were removed as part of the top of tubesheet water lancing process. The weight of deposits removed from each SG by this cleaning process is provided in Table 12. CCNPP had operated 2 cycles since the last time sludge lancing was performed during CC2R21. A total of 32 lbs. of sludge was removed from both the SGs along with a variety of foreign objects such as flexitallic gaskets, wire, machining remnants as well as what is potentially small fragments of degraded moisture separators.

Table 12: CC2R23 SG Deposit Removal Weights SG Weight 21 19 lbs.

22 13 lbs.

Total 32 lbs.

13. The results of primary side component visual inspections performed in each SG.

Visual Inspection of Installed Tube Plugs and Tube-to-Tubesheet Welds All previously installed tube plugs (69) were visually inspected in both channel heads for signs of degradation and leakage. The tube-to-tubesheet welds were visually inspected during eddy current.

No degradation or anomalies were found.

SG Channel Head Bowl Visual Inspections Each SG hot and cold leg primary channel head was visually examined for evidence of breaches in the cladding or cracking in the divider-to-channel head weld and for evidence of wastage of the carbon steel channel head. No evidence of cladding breaches, wastage, or corrosion in the channel head was identified. Also, no cracking in the divider-plate-to-channel-head weld was identified.

Steam Generator Tube Inspection Report CCNPP Unit 2 Refueling Outage 23 E2 - Page 22 of 22 References

1. CEG letter to NRC, RS-22-086, Application to Revise Technical Specifications to Adopt TSTF-577, Revised Frequencies for Steam Generator Tube Inspections, dated August 10, 2022 (ML22222A068)

2. CEG letter to NRC, RS-23-050, Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" (ML23143A136)

3. NRC letter to CEG, CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 -

ISSUANCE OF AMENDMENT NOS. 346 AND 324 RE: ADOPTION OF TSTF-577, REVISED FREQUENCIES FOR STEAM GENERATOR TUBE INSPECTIONS, REVISION 1 (EPID L-2022-LLA-0115), dated August 8, 2023 (ML23188A040)

4. Steam Generator Management Program: EPRI Steam Generator Integrity Assessment Guidelines, Revision 5, EPRI, Palo Alto, CA, December 2021 (EPRI Doc. No. 3002020909)