ML22216A071

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Steam Generator Tube Inspection Report
ML22216A071
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 06/29/2022
From: Hilbert L
Virginia Electric & Power Co (VEPCO)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
22-202
Download: ML22216A071 (23)
v • d • e


Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 June 29, 2022 U.S. Nuclear Regulatory Commission Serial No.22-202 Attention: Document Control Desk NAPS/RAP RO

.Washington, D.C. 20555 Docket Nos. 50-338 50-339 License Nos. NPF-4 NPF-7 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION ENERGYVIRGINIA)

. NORTH ANNA POWER STATION UNITS.1.AND 2 * .

  • STEAM GENERA TOR TUBE INSPECTION REPORT Pursuant to Technical Specification 5.6.7 for North Anna Power Station Units 1 .and 2, Dominion Energy Virginia is required *to submit a 30-day steam generator tube inspection report upon implementation* of Technical Specification Task Force (TSTF) 577, Revised Frequencies for Steam Generator* Tube Inspections, Revision 1.

Attachments 1 and 2 to this letter provides the steam generator tube inspection reports

  • for North Anna Power Station Units 1*and 2: *
  • Should you have any questions or require additional information, please contact Mr.

Marcus Hofmann at (540) 894-2100.

Very truly yours,

~,aAJ-

  • Lisa Hilbert Site Vice President
1- {JD I Atta*chments Commitments made in .this letter
None

/Iii

cc: U.S. Nuclear Regulatory Commission Region II Marquis One Tower 245 Peachtree Center Avenue, NE Suite 1200 Atlanta, Georgia 30303-1257 Mr. G. E. Miller NRC Project Manager - North Anna U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. L. John Klos NRC Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, Maryland 20852-2738 NRC Senior Resident Inspector North Anna Power Station 2

Attachment 1 North Anna Power Station Unit 1 End of Cycle 26 Revised Steam Generator Tube Inspection Report VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION ENERGY VIRGINIA)

End of Cycle 26 Revised Steam Generator Tube Inspection Report In accordance with North Anna Power Station Unit 1 (NAPSl) Technical Specification (TS) 5.6.7, Virginia Electric And Power Company (Dominion) is submitting this Steam Generator Tube Inspection Report which describes the results of the previously completed NAPS 1 steam generator (SG) examinations. Based upon entry into Mode 4 on April 13, 2018, a report was required to be submitted by October 10, 2018. Due to adopting a revised Technical Specification, TSTF-577 Rev. 1, a revised Steam Generator Tube Inspection Report is required to be submitted within 30 days after implementation of the license amendment.

The three North Anna Unit 1 steam generators are replacement Westinghouse Model 54F lower assemblies (i.e., tube bundle, lower shell, and chahnel head). They were replaced in 1993. The standard Series 51 design primary moisture separators (three separators per SG,

~51" ID each) performed well and no modifications were deemed necessary; hence they remain in-place in their original configuration. The feedrings are also original equipment.

Each of the three SGs were fabricated with 3,592 Alloy 690TT tubing, with nominal 0.875" OD x 0.050" wall thickness. The seven broached quatrefoil support plates are fabricated from 405 Stainless Steel. Figure 1 contains a schematic depicting the general arrangement of the steam generators without dimensions.

Figures 2 and 3 contain a photo of the Disk Stack and an illustration of its position in the Feedwater Regulating Valve respectively. The Disk Stack provides an effective barrier against foreign objects in the feedwater entering the steam generators. The North Anna Unit 1 Steam Generators had accrued approximately 22. 7 Effective Full Power Years (EFPY) of operation as of the End of Cycle 26 (March 2018) and approximately 3. 7 EFPY since BOC 27. Since the first sequential period begins after the first in-service inspection, programmatically the North Anna Unit 1 Steam Generators have accrued 25 EFPY. These steam generators operate with a nominal hot-leg temperature of 612°F, with no measurable leakage, and no deviations from the Mandatory and/or Needed (Shall) requirements from the EPRI Guidelines referenced by NEI 97-06.

See Attachment 1, "Acronyms," for explanation of acronyms.

Report:

TS 5.6.7 reporting requirements (in bold text) are provided below, followed by Dominion Energy's response:

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with TS 5.5.8, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG, All operational tubes in all three steam generators (a total of 10,774 tubes), were inspected full length. with bobbin probes. An augmented sample of 5,195 tube locations was inspected with rotating coil probes.

The rotating probe examination in each SG included a 50% sample of the outer five rows of the hot and cold leg periphery and open tube lane at the top of tubesheet. The primary purpose of this examination was the detection of foreign objects or foreign object wear in the most

  • susceptible regions of the SGs. In addition, the rotating +Point probe examinations included both a pre-planned scope, and EOC26 special interest emergent scope. The pre-planned scope included a 50% sample of tubes in the sludge pile region, historical locations of interest, dents or dings (DNT or DNG), overexpansions or bulges (OXP or BLG), percent through wall indications (%TW), and a sample of non-quantifiable historical indications (NQH). The emergent scope included EOC26 bobbin coil Special Interest (SI) locations such as non-quantifiable indications (NQI) and various hot leg and cold leg bounding locations.

During EOC26 each hot and cold leg primary channel head in all three SGs was visually examined prior to the installation of eddy current probe manipulators and in an as left condition following the eddy current examination. This examination consisted of the divider plate, divider plate to tubesheet interface, previousiy plugged tubes, and the entire cladded surface in accordance with NSAL 12-1. The examination revealed no evidence of degradation and no evtdence of plug leakage. The proper tube number and plug position were verified for all four previously installed plugs (two tubes, both in SG-C).

It should be noted that both terms Dent and Ding refer to a plastic deformation of the tube that results in a reduction in the tube diameter. The two different terms were used to differentiate between the location of the signals. Historically (early generation designs) the term dent referred to local tube diameter reductions due to corrosion products from *carbon steel (typically, drilled carbon steel tube. support plates). The term ding referred to local tube diameter reductions due to mechanical means (manufacturing, vibration, incidents during maintenance activities, or impac(from foreign objects). Since the eddy current signals from both dents and dings are similar, the location of the indication was used to differentiate which term was used (dent for indications*at supports and ding for all free span indications). -

  • At NAPS, the referenced dent signals do not represent the same phenomena as classical denting on older generation units caused by drilled carbon steel support plate corrosion
  • damage. Since the NAPS units are not similar in design (i.e., quatrefoil stainless steel tube support plate design vs. drilled hole carbon steel tube support plate design) these same "denting" issues do not directly apply to the NAPS units. Tube support plate areas are not susceptible to denting caused by corrosion of the tube support plates. However, the historical nomenclature assigned to these signals has existed in the database since the steam generators were installed and has remained unchanged since that time.
b. The nondestructive examination techniques utilized for tubes with increased degradation susceptibility; Rotating +Point probe examinations were performed on a 50% sample of the outer five rows of the hot and cold leg periphery and open tube lane at the top oftubesheet in each SG for the detection of foreign objects or foreign object wear in the most susceptible regions of the SGs.
c. For each degradation mechanism found:
1. The nondestructive examination technique utilized; The only degradation mechanism found during the 1R26 tube examinations was TSP wear. The examination technique used for the detection of TSP wear was the bobbin probe. The examination technique used for sizing was the +Point probe.
2. The location, orientation (iflinear), 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; All of the TSP wear indications detected, (16 indications of TSP wear in 10 tubes) measured less than 20% through-wall.
3. 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; and An arithmetic methodology was used for condition monitoring. The maximum depth of TSP wear identified during 1R26 and returned to service was 15%TW; sized with +Point technique ETSS 96910.1. Conservatively accounting for NDE depth sizing uncertainty, the upper bound returned-to-service depth is 29.8%TW, which does not ex~eed the conservative structural limit of 57%TW and compares favorably with the previous Operational Assessment predictions (below).

Table 1: Summaryo fP. nor OA V al"d 1 ati on Assumed or Calculated in the 1R23

  • Operational Assessment Observed during 1R26 AVBWear Growth rate for three cycles going forward: No A VB wear identified.

7%TW/cycle AVBWear Minimum projected margin between end- No AVB wear identified.

  • of-three-cycle depth and the structural limit:

14%TW TSP Wear Growth rate for three cycles going forward: Maximum growth rate observed, 13/4TW 4%TW/cycle from 2013 to 2018 (3 cycles):

0.33%TW/cycle TSP Wear Minimum projected margin between end- Minimum observed margin between max of-three-cycle depth and the structural limit: 1R26 depth and structural limit: 27.2 3/4TW 12.2 3/4TW Operational Projected: 0 Actual, cycles 24, 25 and 26: 0 Leakage

4. The number of tubes plugged during the inspection outage.

No tubes were plugged during this examination.

d. An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results; An arithmetic methodology was used in the forward-looking integrity assessment for structure wear as summarized below.

Bobbin probe technique ETSS 96041.1 was relied upon during EOC 26 for the detection of A VB wear. The EOC 26 Degradation Assessment (DA) conservatively estimated the depth at 95% POD to be 26%TW; therefore, this value is assumed to be the limiting BOC27 AVB wear depth for OA purposes. Note that this POD was derived assuming ECT data noise characteristics that are significantly more limiting than those observed during the EOC 26 inspection.

Bobbin probe technique ETSS 96004.1 was relied upon during this outage for the detection ofTSP/FDB wear and, for ETSS 96004.1, the depth at 95% POD is estimated to be 32%TW. This is quite conservative because the POD was derived assuming ECT data noise characteristics that are significantly more1imiting than those observed during the EOC 26 inspection. Because the depth at 95% POD (32%TW) is more limiting than the upper bound retum~d-to-service depth (29 .8% TW), this value is used as the limiting beginning-of-cycle 27 (BOC27} TSP/FDB wear _depth for OA purposes.

T able 2 : Summaryo fC urrentOAPre d"ICt*Ions Maximum depth Assumed BOC Depth (%)

Structural Predicted at Next Limit Assumed Growth Rate Inspection AVB 26% Growth rate for five Wear (None Detected) cycles going forward: 51% 61%

5%TW/cycle TSP 32% Growth rate for five Wear (Based on a cycles going forward: 52% 57%

conservative Bobbin 4%TW/cycle Probe POD)

e. The nu;mber and percentage of tubes plugged to date, and the affective plugging percentage in each steam generator,
  • T able 3 : Numb er ofT ubes Plu2:2:ed t 0 D ae t SGA SGB SGC Prior to 1R26 0 0 2 During 1R26 0 0 0 Total After 1R26 0 0 2 Percentage 0 0 0.06 Ov.erall Percentage 0.02 Since no sleeving has been performed in the NAPS 1 SGs, the effective plugging percentage is the*same as the actual plugging percentage.
f. The results of any SG secondary side inspections.

Secondary-side visual examinations were performed in all three steam generators. These examinations included:

  • Post-sludge lancing visual examination oftop-of-tubesheet annulus and no-tube lane to assess as-left material condition and cleanliness, and to identify and remove any retrievable foreign objects (FOSAR).
  • FOSAR identified and removed one metallic foreign object from the secondary side of SG-B (see Table 4).
  • Sludge lancing removed a total of 75 pounds of deposit material, (22 pounds from SG-A, 26 pounds from SG-B, and 27 pounds from SG-C).
  • Steam drum visual inspections to evaluate the material condition and cleanliness of key components such as moisture separators, drain systems, and interior surfaces.
  • Ultrasonic thickness readings of selected feedring locations.
  • Visual examination of the upper tube bundles and A VB supports.

The results of all secondary-side visual examinations performed were satisfactory, with no degradation detected.

Ta ble 4: Fore12n Ob"1.1ectS ummar.r SG Description 1R26 SSI 1R26ECT 1R26 Final Result Adjacent tube Absence of wear confirmed.

B Small wire ~7/8" long Initially detected examined. No Object removed. No integrity x 3/32" diameter by SSL Removed.

wear. threat going forward.

Figure 1 - General Arrangement Figure 3 - Disk Stack Location in Feedwater Regulating Valve 0-Ring 0-:Ring Disk Stack

\

O-Ring O-Ring

Attachment 1 Acronyms BLG Bulge BOC Beginning of Cycle CM Condition Monitoring CMOA Condition Monitoring and Operational Assessment DNG Ding DNT Dent ECT Eddy Current Testing EFPY Effective Full Power Years FDB Flow Distribution Baffle FOSAR Foreign Object Search and Retrieval NAPS North Anna Power Station NDE Non-Destructive Examination NOH Non-Quantifiable Historical Indication NQI Non-Quantifiable Indication OXP Over Expansion A

OVR Over Rolled PLP '- Possible Loose Part 3/4TW Percent Throuw Wall SG Steam Generator SI Special Interest SLG Sludge SSI Secondary Side Inspection TSC Tube Sheet Cold TSH Tube Sheet Hot TSP Tube Support Plate

Attachment 2 North Anna Power Station Unit 2 End of Cycle 26 Revised Steam Generator Tube Inspection Report VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION ENERGY VIRGINIA)

End of *Cycle 26 Revised Steam Generator Tube Inspection Report In accordance with North Atrila Power Station Unit 2 (NAPS2) Technical Specification (TS) 5.6.7, Virginia Electric And Power Company (Dominion) is submitting this Steam_

Generator Tube Inspection Report which describes the results of the previously completed

  • NAPS2 steam g~nerator (SG) examinations. Based upon entry into Mode 4 on April 7, -

2019, a report was required to be submitted by October 4, 2019. Due to adopting a revised Technical Specification, TSTF-577 Rev. 1, a revised Steam Generator Tube Inspection Report is required to be submitted within 30 days after implementation of the license amendment.

The three North Anna Unit 2 steam generators are replacement Westinghouse Model 54F lower assemblies (i.e., tube bundle, lower shell, and channel head). They were-replaced in 1995. The standard Series 51 design primary moisture separators (three separators per SG,

~51" ID each) performed well and no modifications were deemed necessary; hence they remain in-place in their original configuration. The feedrings in SG-B and SG-C were replaced when the lower assemblies were replaced. ,----

The feedring of SG-A is original equipment.

Each of the three SGs were fabricated with 3,592 Alloy 690TT tubing, with nominal 0.875" OD x 0.050" wall thickness. The seven broached quatrefoil support plates are fabricated from 405 Stainless Steel. Figure 1 contains a schematic depicting the general arrangement of the steam generators without dimensions.

Figures 2 and 3 contain a photo of the Disk Stack and an illustration of its position in the Feedwater Regulating Valve respectively. The Disk Stack provides an effective barrier against foreign objects in the feedwater entering the steam generators. The North Anna Unit 2 Steam Generators had accrued approximately 21.1 Effective Full Power Years (EFPY) of operation as of the End of Cycle 26 (March 2019) and approximately 2.75 *EFPY since BOC 27. Since the first sequential period begins after the first in-service inspection, programmatically the North Anna Unit 1 Steam Generators have accrued approximately 22.55 EFPY. These steam generators operate with a nominal hot-leg temperature of 612°F, with no measurable leakage, and no deviations from the Mandatory and/or Needed (Shall) requirements from the EPRI Guidelines referenced by NEI 97-06.

See Attachment 1, "Acronyms," for explanation of acronyms.

Report:

TS 5.6.7 reporting requirements (in bold text) are provided below, followed by Dominion Energy's response:

  • A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with TS 5.5.8, Steam Generator (SG) Program. The report shall include:
a. The scope of inspections performed on each SG, All operational tubes in all three steam generators (a total of 10,768 tubes), were inspected full length with bobbin probes. An augmented sample of 5,368 tube locations was inspected ,

with rotating coil probes.

The rotating probe examination in each SG included a 50% sample of the outer five rows of the hot and cold leg periphery and open tube lane at the top of tubesheet. The primary purpose of this examination was the detection of foreign objects or foreign object wear in the most susceptible regions of the SGs. In addition, the rotating +Point probe examinations included both a pre-planned scope, and EOC26 special interest emergent. scope. The pre-planned scope included a 50% sample of tubes in the sludge pile region, historical locations of interest, dents or dings (DNT or DNG), overexpansions or bulges (OXP or BLG), percent through wall indications (3/4TW), and a sample of non-quantifiable historical indications (NQH). The emergent scope included EOC26 bobbin coil Special Interest (SI) locations such as non-quantifiable indications (NQI) and various hot leg and cold leg bounding locations.

During EOC26 each hot and cold leg primary channel head in all three SGs was visually examined prior to the installation of eddy current probe manipulators and in an as left condition following the eddy current examination. This examination consisted of the divider plate, divider plate to tubesheet interface, previously plugged tubes, and the entire cladded*

surface in accordance with NSAL 12-1. The examination revealed no evidence of degradation and no evidence of plug leakage. The proper tube number and plug position were verified for all eight previously installed plugs (one tube in SG-A and seven tubes in SG-C).

It should be noted that both terms Dent and Ding refer to a plastic deformation of the tube that results in a reduction in the tube diameter. The two different terms were used to differentiate between the location of the signals. Historically (early generation designs) the term dent referred to local tube diameter reductions.due to .corrosion products from carbon steel (typically, drilled carbon steel tube support plates). The term ding referred to local tube diameter reductions due to mechanical means (manufacturing, vibration, incidents during maintenance activities, or impact from foreign objects). Since the eddy current signals from both dents and dings are similar, the location of the indication was used to differentiate which term was used (dent for indications at supports and cling for all free span indications\

  • At NAPS, the referenced dent signals do not represent the same phenomena as classical denting on older generation units caused by drilled carbon.steel support plate*corrosion

damage. Since the NAPS units are not similar in design (i.e., quatrefoil stainless steel tube support plate design vs. drilled hole carbon steel tube support plate design) the*se same "denting" issues do not directly apply to the NAPS uriits. Tube support plate areas are not susceptible to denting caused by corrosion of the tube support plates. However, the historical nomenclature assigned to these signals has*existed in the database since the steam generators were_ installed and has remained unchanged since that time.

b. The nondestructive examination techniques utilized for tubes with increased degradation susceptibility; Rotating +Point probe examinations were performed on a 50% sample of the outer five rows of the hot and cold leg periphery and open tube lane at the top of tubesheet in each SG for the detection of foreign objects or foreign object wear in the most susceptible regions of the SGs.
c. For each degradation mechanism found:
1. The nondestructive examination technique utilized; The only degradation mechanism found during the EOC26 tube examinations was Tube Support Plate (TSP) wear. The examination technique used for the detection of TSP wear was the bobbin probe. The examination technique used for sizing was the +Point probe.
2. 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; All of the TSP wear indications detected, (12 indications of TSP wear in 9 tubes) measured less than 20% through-wall.
3. 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; and An arithmetic methodology was used for condition monitoring. The maximum depth of TSP wear identified during the EOC26 inspection and returned to service was 12%TW; sized with +Point technique ETSS 96910.1.
  • Conservatively accounting for NDE depth sizing uncertainty, the upper bound returned-to-service depth is 26.9% TW, which does not exceed the conservative structural limit of 57%TW and compares favorably with the previous Operational Assessment predictions (below).

T able 1 Summaryo f Pnor . OA V a1 I'd ation Assumed or Calculated in the EOC23 and EOC24 Operational Assessments Observed during EOC26 AVBWear Growth rate for three cycles going forward: No AVB wear identified.

7%TW/cycle AVBWear Minimum projected margin between end- No AVB wear identified.

of-three-cycle depth and the structural limit:

13%TW and 20%TW TSP Wear Growth rate for three cycles going forward: Maximum growth rate observed, 12%TW 10%TW/cycle and 4%TW/cycle from 2010 to 2019 (6 cycles): 2%TW/cycle TSP Wear Minimum projected margin between end- Minimum observed margin between max of-three-cycle depth and the structural limit: EOC26 depth and structural limit:

0.3%TWand 17.6%TW 30.1 %TW Operational Projected: 0 Actual, cycles 24, 25 and 26: 0 Leakage

4. The number of tubes plugged during the inspection outage.

No tubes were plugged during this examination.

d. An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results; An arithmetic methodology was used in the forward-looking integrity assessment for structure wear as summarized below.

The maximum depth of TSP wear identified during 2R26 and returned to service was 12%TW; sized with +Point technique ETSS 96910.1. Conservatively accounting for NDE depth sizing uncertainty, the upper bound returned-to-service depth is 26.9%TW.

Bobbin probe technique ETSS 96004.1 was relied upon during this outage for the detection of TSP wear and, for ETSS 96004.1, the depth at 95% POD is estimated to be 15%TW; Note that this was derived using EPRI's MAPOD methodology based on TSP ECT data noise characteristics observed during the 2R26 inspection.

Because the upper bound returned-to-service depth (26.9%TW) is more limiting than the depth at 95% POD (15%TW), this value is used as the limiting beginning-of-cycle 27 (BOC27) TSP wear depth for OA purposes.

The reported TSP wear flaws have experienced minimal discernible. growth and since relatively few TSP wear indications have been identified to date, it is not possible to derive

a 95%/50% growth rate. Consistent with previous OAs, these results continue to justify a conservative growth rate assumption of 4%TW/cycle going forward.

Adjusting the BOC27 depth upward to reflect three fuel cycles of growth yields the end-of-cycle upper bound depth (EOCUBD):

BOC27 = 26.9% TW maximum throughwall depth of undetected TSP wear at the beginning of Cycle 27 EOCUBD = BOC27 +(5 cycles)(4%TW/cycle) end of cycle upper bound depth after five operating cycles EOCUBD:;::: 46.9%TW << 57%TW Since this value is below the structural limit of 57.0 3/4TW (for full TSP thickness), there is reasonable assurance that TSP wear will not exceed the structural performance criteria prior to the next inspection of any of the North Anna Unit 2 SGs. As such, no accident leakage or operational leakage concerns exist relative to TSP wear for any of the SGs. The stated structural limit is based on Regulatory Guide 1.121 requirements which include the effects of non-pressure loads which occur under evaluated accident conditions.

Even though no AVB wear indications have been identified in the North Anna SGs to date, it could reasonably be expected to develop eventually because similar design steam generators (Fs and F-Types) have reported AVB wear. The performance of the North Anna steam generators is expected to at least equal that of Surry since close-gap AVB tolerance techniques were used during the manufacture of the North Anna SGs: In fact, well before Surry had operated for the amount of time that the North Anna units have operated, Surry had already experienced AVB wear. Therefore, the Surry AVB wear experience was used to perform a bounding evaluation of potential North Anna A VB wear.

Bobbin probe technique ETSS 96041.1 was relied upon during this outage for the detection of AVB wear and, for ETSS 96041.1, the depth at 95% POD is estimated to be 15%TW.

Note that this was derived using EPRI's MAPOD methodology based on AVB ECT *data noise characteristics observed during the 2R26 inspection.

  • An assumed AVB wear growth rate of7%TW per operating cycle was used to project the depth of future AVB wear for comparison with the applicable structural limit (61 % TW).

This growth rate is a conservative and is assumed, based on the absence of any detectable AVB wear to date, to be bounding for A VB wear at NAPS2.

Adjusting the BOC27 depth upward to reflect three fuel cycles of growth yields the end-of-cycle upper bound depth (EOCUBD):

BOC27 = 15%TW maximum throughwall depth of undete-cted A VB wear at the beginning of Cycle 27 EOCUBD = BOC27 + (5 cycles)(7%TW/cycle)

  • end of cycle upper bound depth after five operating cycles EOCUBD = 50%TW << 61 3/4TW Structural limit ~asily met in five cycles Since this value is less than the structural limit, it is concluded that A VB wear will not violate the structural integrity performance criteria in any of the Unit 2 SGs during the next planned inspection interval. As such, AVB wear will not violate the operational leakage and accident induced leakage performance criteria during the same period. The stated structural limit is based on Regulatory Guide 1.121 requirements which include the effects of non-pressure loads which occur l!llder evaluated accident conditions.

T abl e 2 : Summaryo fC urrentOAP-red"ICt"ions Maximum depth Assumed BOC Depth (%)

Structural Predicted at Next Limit Assumed Growth Rate Inspection AVB 15% Growth rate for five Wear (None Detected) cycles going forward: 50% 61%

7%TW/cycle TSP 26.9% Growth rate for five Wear (Based on a cycles going forward: 46.9% 57%

conservative Bobbin 4%TW/cycle Probe POD)

e. The number and percentage of tubes plugged to date, and the affective plugging percentage in each steam generator, T able 3 : N umb er ofT ub es Plu22:e d t 0 D ae t SGA SGB SGC Prior to 2R26 1 0 7 During 2R26 0 0 0 Total After 2R26 1 0 7 Percentage 0.03 0 0.19 Overall Percentage 0.07 Since no sleeving has been performed in the NAPS2 SGs, the effective plugging_ -

percentage is the same as the actual plugging percentage.

f. The results of any SG secondary side inspections.

Secondary-side visual examinations were performed in all three steam generators. These examinations included: * - *

  • Post-sludge lancing visual examination of top-of-tubesheet annulus and no-tube lane to assess as-left material condition and cleanliness, and to identify and remove any retrievable foreign objects (F:OSAR).
  • FOSAR identified and removed two metallic foreign objects from the secondary side of SG-B (see Table 4).
  • Sludge lancing removed a total of 51 pounds of deposit material, (15 pounds from SG-A, 18 pounds from SG-B, and 18 pounds from SG:-C).
  • Steam drum visual inspections to evaluate the material condition and cleanliness of key components such as moisture separators, drain systems, and interior surfaces. *
  • Ultrasonic thickness readings of selected feedring locations.
  • Visual examination of the upper tube bundles and AVB supports.

The results of all secondary-side visual examinations performed were satisfactory, with no degradation detected.

T abl e 4 : F ore1~n Ob"1.1ectS ummary SG Description 2R26 SSI 2R26ECT 2R26 Final Result Affected and Absence of wear confirmed Initially Bounding tubes Weld wire ~8" long by ECT. Object remoyed. No detected by SSI.

x 1/8" diameter examined. integrity threat going Removed.

No wear. forward.

B Thin, metallic scale- Affected and Initially Bounding tubes Absence of wear confirmed.

like object, detected by Object removed. No integrity Curvature~ 1.75" examined.

ECT. Removed. threat going forward.

diameter No wear.

Figure 1 - General Arrangement Figure 3 - Disk Stack Location in Feedwater Regulating Valve Q..Ring

,,,,~.--, - O.:Ring

._ Disk Stack

. Q..Ring

. O~Rlng

Attachment 1 Acronyms BLG Bulge BOC Beginning of Cycle CM Condition Monitoring CMOA Condition Monitoring and Operational Assessment '

DNG Ding DNT Dent ECT Eddy Current Testing EFPY Effective Full Power Years FDB Flow Distribution Baffle FOSAR Foreign Object Search and Retrieval NAPS North Anna Power Station NDE Non-Destructive Examination NOH Non-Quantifiable Historical Indication NQI Non-Quantifiable Indication OXP Over Expansion OVR Over Rolled PLP Possible Loose Part 3/4TW Percent Through Wall SG Steam Generator SI Special Interest SLG Sludge SSI Secondary Side Inspection TSC Tube Sheet Cold TSH Tube Sheet Hot TSP Tube Support Plate

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