ML21027A228

License Amendment Request for One-time Deferral of Steam Generator Inspections

ML21027A228
Person / Time
Site:	Beaver Valley
Issue date:	01/27/2021
From:	Grabnar J Energy Harbor Nuclear Corp
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-21-001
Download: ML21027A228 (66)

Text

energy Energy Harbor Nuclear Corp.

~....-.. harbor Beaver Valley Power Station P. O. Box 4 Shippingport, PA 15077 John J. Grabnar 724-682-5234 Site Vice President, Beaver Valley Nuclear January 27, 2021 L-21-001 10 CFR 50.90 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Beaver Valley Power Station, Unit No. 1 Docket No. 50-334, License No. DPR-66 License Amendment Request for One-time Deferral of Steam Generator Inspections Pursuant to 10 CFR 50.90, Energy Harbor Nuclear Corp. hereby requests an amendment to the facility operating license for Beaver Valley Power Station, Unit No. 1.

The proposed change would revise Technical Specification (TS) 5.5.5.1, "Unit 1 SG

[Steam Generator] Program," paragraph d.2 to defer the spring of 2021 refueling outage (1R27) steam generator inspections to the fall of 2022 refueling outage (1R28).

The spring of 2021 refueling outage is scheduled to begin in April and would require approximately 140 people onsite working in close proximity for extended periods of time to perform steam generator inspections. On January 31, 2020, the U.S. Department of Health and Human Services declared a public health emergency for the United States to aid the nations healthcare community in responding to the Coronavirus Disease 2019 (COVID-19). Subsequently, the COVID-19 outbreak was characterized as a pandemic by the World Health Organization on March 11, 2020, and, on March 13, 2020, the President of the United States of America declared the COVID-19 pandemic a national emergency.

Consequently, in response to the pandemic declarations, in the interest of personnel safety and to preclude the potential for transmittal and spread of COVID-19, Energy Harbor Nuclear Corp. is requesting a one-time deferral of the SG inspections to the fall of 2022 refueling outage.

An evaluation of the proposed change is provided in Enclosure A. The supporting document referenced in the evaluation is listed below and provided in Enclosure B.

Westinghouse Electric Company LLC Document Number SG-CDMP-20-24, Revision 1, Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28, January 2021

Beaver Valley Power Station, Unit No. 1 L-21-001 Page 2 Approval of the proposed amendment is requested by March 19, 2021 to support the 1R27 refueling outage. The amendment shall be implemented within 30 days of approval.

There are no regulatory commitments contained in this submittal. If there are any questions, or if additional information is required, please contact Mr. Phil H. Lashley, Manager - Fleet Licensing, at (330) 696-7208.

I declare under penalty of perjury that the foregoing is true and correct. Executed on January ___, 27 2021.

Sincerely, Gmbnur.John 19072 Sitt, Vice !'resident, Beover V~\lcy l amappmviTig !hi, ,~,cumelll Gra.lmar,John 19072 J311 2J202 112:01l'M John J. Grabnar

Enclosures:

A. Evaluation of the Proposed Change B. Westinghouse Electric Company LLC Document Number SG-CDMP-20-24, Revision 1, Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28, January 2021 cc: NRC Region I Administrator NRC Resident Inspector NRC Project Manager Director BRP/DEP Site BRP/DEP Representative

Enclosure A L-21-001 Evaluation of the Proposed Change (14 pages follow)

Evaluation of the Proposed Change Page 1 of 12

Subject:

Proposed Revision of Technical Specification (TS) 5.5.5, "Steam Generator (SG) Program" for the Beaver Valley Power Station, Unit No. 1 Table of Contents 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 System Design and Operation 2.2 Current Technical Specification Requirements 2.3 Reason for the Proposed Change 2.4 Description of the Proposed Change

3.0 TECHNICAL EVALUATION

3.1 Condition Monitoring Assessment and Operational Assessment Summary 3.2 Additional Information Relevant to the Operational Assessment

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements I Criteria 4.2 No Significant Hazards Consideration Analysis 4.3 Conclusions

6.0 REFERENCES

ATTACHMENT: Technical Specification Page Markup

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 2 of 12 1.0

SUMMARY

DESCRIPTION This evaluation supports a request to amend Renewed Facility Operating License No.

DPR-66 for Beaver Valley Power Station, Unit No. 1 (BVPS-1). The proposed change would revise Technical Specification (TS) 5.5.5.1, "Unit 1 SG [Steam Generator]

Program," paragraph d.2 to allow a one-time deferral of the steam generator inspections.

2.0 DETAILED DESCRIPTION 2.1 System Design and Operation The BVPS-1 reactor coolant system consists of three similar heat transfer loops connected in parallel to the reactor vessel, with a steam generator (SG) in each loop.

The SGs are vertical shell and u-tube heat exchangers that remove heat from the reactor coolant system and produce steam to operate the main turbine generator and other balance-of-plant equipment.

The reactor coolant flows through the inverted u-tubes, entering and leaving through the nozzles located in the hemispherical bottom head of the SG. The bottom head is divided into inlet and outlet chambers by a vertical partition plate extending from the head to the tubesheet. Manways are provided for access to both sides of the divided head. Steam is generated on the shell side and flows upward through the moisture separators to the outlet nozzle at the top of the SG.

SG tubes constitute the heat transfer surface area between the primary (reactor coolant) and secondary (main steam) systems and, as such, are relied on to maintain the primary system's pressure and inventory. As an integral part of the reactor coolant pressure boundary, the SG tubes isolate the radioactive fission products in the primary coolant from the secondary system in the SGs. Maintaining tube integrity ensures that the tubes can perform their intended safety functions consistent with the plant licensing basis and applicable regulatory requirements.

The original BVPS-1 SGs were replaced in the spring of 2006 during the 1R17 refueling outage with Westinghouse Electric Company LLC (Westinghouse) Model 54F SGs. The replacement SGs are described in Section 4.2.2.4 of the Updated Final Safety Analysis Report, and each SG contains 3,592 u-tubes fabricated of Alloy 690 with an outer diameter of 0.875 inches and a nominal wall thickness of 0.050 inches. The tubes undergo thermal treatment following tube-forming and annealing operations and have been shown in laboratory tests and industry operating experience to be resistant to primary water stress corrosion cracking and outside diameter stress corrosion cracking.

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 3 of 12 2.2 Current Technical Specification Requirements Applicable SG TS requirements are as follows:

TS 3.4.13, RCS Operational LEAKAGE: The limiting condition for operation requires, in part, that reactor coolant system operational leakage be limited to 150 gallons per day (gpd) primary to secondary leakage through any one SG while operating in Modes 1 through 4.

TS 3.4.20, Steam Generator (SG) Tube Integrity: The limiting condition for operation that applies to BVPS-1 requires that SG tube integrity be maintained and that all SG tubes satisfying the tube plugging criteria be plugged in accordance with the Steam Generator Program while operating in Modes 1 through 4.

TS 5.5.5.1, Unit 1 SG Program: Paragraph d.2 requires, in part, after the first refueling outage following SG installation, the inspection of each SG at least every 72 effective full power months (EFPM) or at least every third refueling outage (whichever results in more frequent inspections). Paragraph d.2 stipulates further requirements for different SG inspection periods.

2.3 Reason for the Proposed Change The BVPS-1 SGs were last inspected during the fall of 2016 refueling outage (1R24),

and therefore require another inspection during 1R27 in accordance with TS 5.5.5.1.d.2.

The 1R27 refueling outage is currently scheduled to begin April of 2021. To support the 1R27 SG inspections, there would be an estimated 140 people onsite working in close proximity for extended periods of time, many of whom travel from other areas of the country.

On January 31, 2020, the U.S. Department of Health and Human Services declared a public health emergency for the United States to aid the nations healthcare community in responding to the Coronavirus Disease 2019 (COVID-19). Subsequently, the COVID-19 outbreak was characterized as a pandemic by the World Health Organization on March 11, 2020, and, on March 13, 2020, the President of the United States of America declared the COVID-19 pandemic a national emergency.

Consequently, in response to the pandemic declarations, in the interest of personnel safety and to preclude the potential for transmittal and spread of COVID-19, Energy Harbor Nuclear Corp. is requesting a one-time deferral of the SG inspections to the fall of 2022 refueling outage.

2.4 Description of the Proposed Change TS 5.5.5.1.d.2 would be annotated by an asterisk at the end of the first sentence and a footnote with an asterisk at the bottom of the page would state:

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 4 of 12

• The spring of 2021 (1R27) refueling outage SG inspections may be deferred to the fall of 2022 (1R28) refueling outage.

A markup of TS 5.5.5.1.d.2 is provided in the attachment with the proposed text changes underlined and denoted with a revision bar in the right-hand column. No changes are proposed for the technical specification bases because the affected technical specifications do not have associated bases.

3.0 TECHNICAL EVALUATION

As stated previously, the BVPS-1 replacement SGs were installed in the spring of 2006 during the 1R17 refueling outage. During the following refueling outage (1R18), 100 percent (%) of the tubes were inspected. During the spring of 2012 (1R21) refueling outage, 50% of the SG tubes were inspected, and the remaining tubes were inspected (plus an additional 8% based on industry operating experience) during the fall of 2016 (1R24) refueling outage. Therefore, the TS 5.5.5.1.d.2.a requirement for the first inspection period was satisfied. The BVPS-1 SGs are now in the second inspection period, where 100% of the tubes will be inspected during the next 120 EFPM in accordance with TS 5.5.5.1.d.2.b. The spring of 2021 refueling outage (1R27) will be the first outage of the second inspection period. The inspections performed since the SGs were replaced, as well as the inspection scope should the proposed change be approved, is provided in Table 1.

Reports documenting the results of the 1R18, 1R21, and 1R24 inspections have been previously submitted to the Nuclear Regulatory Commission (NRC) in references 1, 2, and 3, respectively. The existing SG tube degradation mechanisms identified in the reports are wear at anti-vibration bars (AVBs) and wear at tube support plates (TSPs).

These degradation mechanisms are detected with the full-length bobbin coil probe inspection. SG tube wear due to foreign object material is not a function of SG design, and degradation may be random and unpredictable. Historical inspection results have shown that this degradation mechanism has not challenged the condition monitoring limit, and it is detected by full-length bobbin coil probe inspections or Plus Point probe inspections around the tube bundle periphery.

A potential degradation mechanism that has not been identified in the BVPS-1 replacement SGs to date is volumetric outer-diameter indications that are non-corrosion related such as grinder strikes. This potential degradation mechanism would be detected by the full-length bobbin coil probe inspection. Finally, the operational assessment discussed later considers SG tube u-bends and tubesheet expansion transition stress corrosion cracking, as well as volumetric pitting in the sludge pile, as unexpected or non-relevant degradation mechanisms.

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 5 of 12 Table 1, BVPS-1 Replacement SG Inspections Refueling Date Inspection Scope Outage 1R17 Spring 2006 SG replacement 100% bobbin coil inspection, full length.

100% Plus Point inspection1, row 1 and 2 u-bends.

Plus Point inspection, tube bundle periphery.

1R18 Fall 2007 Plus Point inspection, bobbin I-code signals and special interest.

Performed sludge lancing and foreign object search and retrieval (FOSAR).

No primary side inspections.

1R19 Spring 2009 Performed sludge lancing and FOSAR.

No primary side inspections.

1R20 Fall 2010 Performed sludge lancing and FOSAR.

SG-B steam drum visual inspection.

50% bobbin coil inspection, full length.

50% Plus Point inspection, row 1 and 2 u-bends.

Plus Point inspection, tube bundle periphery2.

1R21 Spring 2012 Plus Point inspection, bobbin I-code signals and special interest.

Performed sludge lancing and FOSAR.

SG-C steam drum visual inspection.

No primary side inspections.

1R22 Fall 2013 Performed sludge lancing and FOSAR.

SG-A steam drum visual inspection.

1R23 Spring 2015 No primary or secondary side inspections.

58% bobbin coil inspection, full length.

50% Plus Point inspection, row 1 and 2 u-bends.

Plus Point inspection, tube bundle periphery2.

1R24 Fall 2016 Plus Point inspection, bobbin I-code signals and special interest.

Performed sludge lancing and FOSAR.

SG-B steam drum visual inspection.

1R25 Spring 2018 No primary or secondary side inspections.

1R26 Fall 2019 No primary or secondary side inspections.

1R27 Spring 2021 No primary or secondary side inspections.

(Proposed) 100% bobbin coil inspection, full length3.

100% Plus Point inspection1, row 1 and 2 u-bends.

1R28 Plus Point inspection, tube bundle periphery2.

Fall 2022 (Proposed) Plus Point inspection, bobbin I-code signals and special interest.

Perform sludge lancing and FOSAR.

SG-C steam drum visual inspection.

1 The Plus Point probe uses +POINTTM eddy current coil technology (+POINT is a trademark of Zetec, Inc.).

2 The Plus Point top of tubesheet inspection is 360 degrees around the tube bundle periphery and tube lane region (two to three tubes deep into the tube bundle). This inspection is for the detection of loose parts.

3 While only 50% of the tube population would be required, a 100% inspection is planned to support potential implementation of TSTF-577, Revision 1, Revised Frequencies for Steam Generator Tube Inspections.

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 6 of 12 3.1 Condition Monitoring Assessment and Operational Assessment Summary In accordance with Nuclear Energy Institute (NEI) 97-06, Revision 3, Steam Generator Program Guidelines, (Reference 4), a condition monitoring (CM) assessment is to be performed following each inspection. This evaluation is backward-looking, based on the two most recent BVPS-1 inspections during 1R21 and 1R24, and compares the 1R21 operational assessment (OA) projections with the actual 1R24 results. The CM conclusions from the last two inspections are summarized in Section 3 of Westinghouse document number SG-CDMP-20-24, Revision 1, Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28, (Reference 5), and demonstrate that the 1R21 OA projections were conservative.

The forward-looking OA is performed to ensure the SG tubing will continue to meet specific structural and leakage integrity performance criteria throughout the operating period preceding the next inspection. The performance criteria for SG tube structural integrity, accident-induced leakage, and operational leakage from TS 5.5.5.1.b is summarized as follows:

Structural Integrity: In-service SG tubes shall retain structural integrity over the full range of normal operating conditions, all anticipated transients included in the design specification, and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady-state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary to secondary pressure differentials. There are other considerations for loads contributing to burst or collapse.

Accident-Induced Leakage: The primary to secondary accident-induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is also not to exceed one gallon per minute per SG, except during a SG tube rupture.

Operational Leakage: This performance criterion is specified in the limiting condition for operation 3.4.13, Item d, as 150 gpd primary to secondary leakage through any one SG.

The OA in Reference 5 was performed in accordance with BVPS-1 TS 5.5.5.1, the Energy Harbor Nuclear Corp. SG Management Program, NEI 97-06, and the Electric Power Research Institute (EPRI) Steam Generator Integrity Assessment Guidelines (Reference 6). The OA provides an evaluation for the purpose of demonstrating the primary and secondary side examinations in refueling outage 1R27 may be safely deferred one additional operating cycle to the refueling outage in 1R28, and considered the existing SG tube degradation mechanisms of AVB wear, TSP wear, and foreign object wear. Conservative, bounding inputs (as described in Section 4 of Reference 5) were used including projected cycle operating time to ensure that predicted AVB or TSP wear meets the SG structural and leakage performance criteria. There is no mechanism for further foreign object wear flaw growth as no foreign objects remain within the vicinity of previously-affected tubes, and foreign objects that were not able to be

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 7 of 12 retrieved during the last 1R24 inspection were evaluated to ensure there is no threat to tube integrity before the proposed 1R28 inspections.

3.2 Additional Information Relevant to the Operational Assessment BVPS-1 SG Tube Plugging No SG tubes have required plugging other than one tube identified during the first inspection after the SGs were replaced. One tube in SG-C was plugged to address TSP wear. The wear indication was from a burr on the upper edge of the TSP and believed to be left from manufacturing.

Number of Degraded Tubes The number of degraded tubes and their degradation mechanism up to and including the latest 1R24 outage are provided in sections 2.1.3 (AVB wear), 2.1.4 and 2.1.5 (TSP wear), and 2.1.6 (foreign object wear) of Reference 5. There are a total of 8 AVB wear indications, 24 TSP wear indications, and 3 foreign object wear indications.

FOSAR Early in SG life, sludge lancing and FOSAR were performed each outage regardless of primary side activities. Since the amount of sludge being removed was minimal, both sludge lancing and FOSAR are now performed coincident with primary side inspections (nominally every third refueling outage).

The BVPS-1 SGs have experienced low numbers of foreign objects found on the secondary side and the size of the foreign objects has been small. Typical objects found on the secondary tubesheet are small bristle wires, gasket material pieces, machine remnants, sludge rocks, and hard scale. Table 2 lists the number of items of foreign material observed in the secondary side of the SGs and the number retrieved. Material that was left in the secondary side of the SGs was evaluated and found to be acceptable for continued component operation. None of these objects has caused any tube wear in recent outages. Only four small objects were found in the last FOSAR (performed during 1R24) that were not retrieved, and all were less than 1/4-inch in length.

Chemistry Transients Since 1R24 Cycle 27: There have been no chemistry transients during the current operating cycle.

No primary-to-secondary leakage has been reported during the current cycle.

Cycle 26: As discussed in Section 3.8.2 of Reference 5, BVPS-1 experienced a condenser tube leak in June of 2018. The responses and actions taken during the excursion met the time frames as required in EPRI Pressurized Water Reactor Secondary Water Chemistry Guidelines, Revision 8, (Reference 7) to return parameters to normal levels.

Cycle 25: As discussed in Section 3.8.1 of Reference 5, BVPS-1 experienced a condenser tube leak in January of 2018. The responses and actions taken during the

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 8 of 12 excursion met the time frames as required in EPRI Pressurized Water Reactor Secondary Water Chemistry Guidelines, Revision 7 (effective at that time), to return parameters to normal levels.

A forced outage in November of 2017 caused elevated SG sodium, chloride, and sulfate concentrations while the plant was shutdown; however, no EPRI action levels were exceeded.

Table 2, Number of Items of Foreign Material SG A SG B Outage FOUND RETRIEVED FOUND RETRIEVED 1R18 0 0 8 7 1R19 3 3 17 14 1R20 1 1 7 6 1R21 14 13 36 31 1R22 3 3 13 13 1R23*

1R24 6 4 3 1 1R25*

1R26*

SG C TOTAL Outage FOUND RETRIEVED FOUND RETRIEVED 1R18 4 4 12 11 1R19 0 0 20 17 1R20 4 1 12 8 1R21 17 15 67 59 1R22 2 2 18 18 1R23*

1R24 7 7 16 12 1R25*

1R26*

TOTAL 145 125

• FOSAR not performed during these outages Mitigation Strategy The TS limit on primary-to-secondary leakage is 150 gpd through any one SG, and there are several methods available to identify and quantify potential leakage. These methods include continuous radiation monitoring via main steam line nitrogen-16 (N-16) radiation monitors and the main condenser air ejector vent radiation monitor. The N-16 radiation monitors can provide evidence to identify the SG where the leak is originating as there are three monitors, one on each SG main steam supply line.

The N-16 monitors are augmented by the main condenser air ejector radiation monitor.

The N-16 and condenser air ejector radiation monitors have alarms to alert for primary-to-secondary leakage. Calculations indicate no detectible leakage has been identified in any SGs during the current cycle.

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 9 of 12 When total primary-to-secondary leakage is greater than or equal to 5 gpd, increased monitoring by the appropriate plant personnel is initiated in accordance with the Steam Generator Tube Leakage procedure. Should leakage increase to greater than or equal to 30 gpd (Action Level 1), actions are initiated to frequently monitor the leak rate, trend the leak rate and confirm the leakage source. If the leak rate reaches greater than or equal to 75 gpd and is sustained for one hour (Action Level 2), actions are initiated to place the unit in MODE 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of entering Action Level 2. If the leak rate reaches greater than or equal to 100 gpd (Action Level 3), the plant shall be at less than or equal to 50% power within one hour and be in MODE 3 within the next two hours (3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> total).

In support of this one-time request to extend the interval between the BVPS-1 SG inspections by one operating cycle, the 75 gpd threshold (Action Level 2) will be reduced to a leak rate of 50 gpd for Cycle 28. The 75 gpd threshold would be re-instated upon the completion of the SG inspections in 1R28.

The above monitors and actions will provide assurance that should a SG tube leak develop in the BVPS Unit 1 SGs, the condition will be identified and managed to ensure public safety is assured. The leakage limits imposed are consistent with EPRI recommendations and are conservatively below the TS prescribed shutdown criteria of 150 gpd.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements / Criteria 10 CFR 50.55a. Codes and Standards 10 CFR 50.55a, paragraph (c)(1), specifies that components that are part of the reactor coolant pressure boundary must meet the requirements for Class 1 components in Section Ill of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code) with certain exceptions. 10 CFR 50.55a further requires, in part, that throughout the service life of a pressurized water reactor facility, ASME Code Class 1 components must meet the requirements, except design and access provisions and pre-service examination requirements, in Section XI, "Rules for ln-service Inspection of Nuclear Power Plant Components," of the ASME Code, to the extent practical. This requirement includes the inspection and repair criteria of Section XI of the ASME Code.

10 CFR 50, Appendix A, General Design Criteria for Nuclear Power Plants General Design Criteria (GDC) 14, 15, 30, 31, and 32 of 10 CFR Part 50, Appendix A, define requirements for the reactor coolant pressure boundary with respect to structural and leakage integrity. SG tubing constitutes a major fraction of the reactor coolant pressure boundary surface area. The tubing must be capable of maintaining reactor coolant inventory and pressure. The Steam Generator Program required by the BVPS-1

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 10 of 12 Technical Specifications establishes performance criteria, inspection periods, and the methods necessary to meet them. These requirements provide reasonable assurance that tube integrity will be met in the interval between SG inspections.

The BVPS-1 construction permit was issued in June of 1970, before the GDC were published as Appendix A to 10 CFR 50 in February of 1971 and amended in July of 1971. Appendix 1A of the BVPS-1 Updated Final Safety Analysis Report (UFSAR) provides a discussion of the degree of conformance with the 1971 GDC. In Appendix 1A of the BVPS-1 UFSAR, it is noted that the BVPS-1 design conforms with the intent of GDC 14, 15, 30, 31, and 32.

10 CFR 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants.

10 CFR 50 Appendix B requires a quality assurance program for the design, fabrication, construction, and testing of structures, systems, and components in nuclear power plants. The requirements of Appendix B apply to all activities affecting the safety-related functions of those structures, systems, and components. The activities include designing, purchasing, fabricating, handling, shipping, storing, cleaning, erecting, installing, inspecting, testing, operating, maintaining, repairing, refueling, and modifying safety-related structures, systems and components. The SGs are considered safety-related components and, therefore, are required to meet the Appendix B requirements.

There are no proposed changes in this amendment request that impact these regulatory requirements.

4.2 No Significant Hazards Consideration Analysis Energy Harbor Nuclear Corp. is proposing to amend the Renewed Facility Operating License No. DPR-66 for Beaver Valley Power Station, Unit No. 1 (BVPS-1). The amendment would revise Technical Specification (TS) 5.5.5.1, "Unit 1 SG [Steam Generator] Program," paragraph d.2 to allow a one-time deferral of the steam generator inspections.

Energy Harbor Nuclear Corp. has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below.

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change adds a note to TS 5.5.5.1.d.2 to permit a one-time deferral of the SG inspections from the spring of 2021 (1R27) refueling outage to the fall of 2022 (1R28) refueling outage. An operational assessment has been performed that concludes the SGs will continue to meet the structural and leakage integrity

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 11 of 12 performance criteria throughout the proposed operating period, ensuring there is no significant increase in the probability of a previously-evaluated accident. The existing TS limit for addressing potential primary-to-secondary leakage is not altered, ensuring accident analysis initial assumptions are met and that there should be no significant increase in the consequences of a previously-evaluated accident.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously-evaluated.

2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed change adds a note to TS 5.5.5.1.d.2 to permit a one-time deferral of the SG inspections from the spring of 2021 (1R27) refueling outage to the fall of 2022 (1R28) refueling outage. An operational assessment has been performed that concludes the SGs will continue to meet the structural and leakage integrity performance criteria throughout the proposed operating period. Furthermore, there are no physical system, structure, or component changes that could create the possibility of a new or different kind of accident.

Therefore, the proposed amendment does not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No.

The proposed change adds a note to TS 5.5.5.1.d.2 to permit a one-time deferral of the SG inspections from the spring of 2021 (1R27) refueling outage to the fall of 2022 (1R28) refueling outage. An operational assessment has been performed that concludes the SGs will continue to meet the structural and leakage integrity performance criteria throughout the proposed operating period. Since the proposed inspection deferral does not exceed or alter a design basis or safety limit, it does not significantly reduce the margin of safety.

Therefore, the proposed amendment does not involve a significant reduction in a margin of safety.

Based on the above, Energy Harbor Nuclear Corp. concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

Evaluation of the Proposed Change Beaver Valley Power Station, Unit No 1 Page 12 of 12 4.3 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1) Letter from FirstEnergy Nuclear Operating Company to the NRC dated March 18, 2008, Technical Specification 5.6.6.1 - Steam Generator Inspection Report, Accession No. ML080800448.

2) Letter from FirstEnergy Nuclear Operating Company to the NRC dated October 24, 2012, Technical Specification 5.6.6.1 - Steam Generator Inspection Report, Accession No. ML12299A088.

3) Letter from FirstEnergy Nuclear Operating Company to the NRC dated February 13, 2017, 180 Day Steam Generator Inspection Report - Technical Specification 5.6.6.1, Accession No. ML17044A360.

4) Nuclear Energy Institute (NEI) 97-06, Revision 3, Steam Generator Program Guidelines, January 2011, Accession No. ML111310708.

5) Westinghouse Document Number SG-CDMP-20-24, Revision 1, Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28, January 2021.

6) Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 4 (EPRI, Palo Alto, CA: 2016).

7) Pressurized Water Reactor Secondary Water Chemistry Guidelines, Revision 8 (EPRI, Palo Alto, CA: 2017).

Evaluation of the Proposed Change Attachment Technical Specification Page Markup (1 page follows)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.5.1 Unit 1 SG Program (continued)

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is also not to exceed 1 gpm per SG, except during a SG tube rupture.

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

c. Provisions for SG Tube Plugging Criteria Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

d. Provisions for SG Tube Inspections Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube plugging criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1. Inspect 100% of the tubes in each SG during the first refueling outage following SG installation.

2. After the first refueling outage following SG installation, inspect each SG at least every 72 effective full power months or at least every third refueling outage (whichever results in more frequent inspections).* In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a, b, c and d below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type

• The spring of 2021 (1R27) refueling outage SG inspections may be deferred to the fall of 2022 (1R28) refueling outage.

Beaver Valley Units 1 and 2 5.5 - 5 Amendments / 186

Enclosure B L-21-001 Westinghouse Electric Company LLC Document Number SG-CDMP-20-24, Revision 1, Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28, January 2021 (48 pages follow)

Westinghouse Non-Proprietary Class 3 SG-CDMP-20-24 January 2021 Revision 1 Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28

@ Westinghouse SG-CDMP-20-24 Revision 1 Page 1 of 48

• • • This record was final approved on 1/15/2021 4:13:49 PM. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 SG-CDMP-20-24 Revision 1 Beaver Valley Unit 1 Operational Assessment to Support Deferral of Planned Inspections from 1R27 to 1R28 January 2021 Authors Name: Signature / Date For Pages Logan T. Clark *Electronically Approved All Component Design and Management Programs Mitchell D. Krinock *Electronically Approved All Component Design and Management Programs Reviewers Name: Signature / Date For Pages Jay R. Smith *Electronically Approved All RSG/OSG Engineering and Chemistry Verifiers Name: Signature / Date For Pages David A. Suddaby *Electronically Approved All Component Design and Management Programs Managers Name: Signature / Date For Pages Michael E. Bradley, Manager *Electronically Approved All Component Design and Management Programs

© 2020 Westinghouse Electric Company LLC All Rights Reserved

• Electronically Approved Records Are Authenticated in the Electronic Document Management System SG-CDMP-20-24 Revision 1 Page 2 of 48

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Westinghouse Non-Proprietary Class 3 RECORD OF REVISIONS Date Entered Revision Revision Description in EDMS 0 1/5/2021 Original Issue Page 41: Addressed a chemistry transient that occurred during Cycle 26 1 See EDMS Page 43: Changed the summary of Cycle 26 to capture the chemistry transient that occurred SG-CDMP-20-24 Revision 1 Page 3 of 48

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Westinghouse Non-Proprietary Class 3 TABLE OF CONTENTS Page TABLE OF CONTENTS ................................................................................................................4 LIST OF TABLES ..........................................................................................................................6 LIST OF FIGURES .........................................................................................................................7 LIST OF TRADEMARKS ..............................................................................................................7

1.0 INTRODUCTION

...............................................................................................................8 1.1 Steam Generator Design..................................................................................................8 1.2 Steam Generator Operation Summary ............................................................................9 1.3 Steam Generator Performance Criteria ...........................................................................9 1.3.1 Structural Integrity Performance Criteria (SIPC)....................................................9 1.3.2 Operational Primary-to-Secondary Leakage Performance Criteria ......................11 1.3.3 Accident Induced Leakage Performance Criteria (AILPC) ..................................11 2.0 Steam Generator Outage Summary ...................................................................................12 2.1 1R24 Inspection Plan ....................................................................................................12 2.1.1 Inspection Expansion ............................................................................................13 2.1.2 Inspection Results .................................................................................................13 2.1.3 Anti-vibration Bar (AVB) Wear ...........................................................................13 2.1.4 TSP Wear (TSP Burrs) ..........................................................................................14 2.1.5 TSP Wear (TSP Lands) .........................................................................................14 2.1.6 Foreign Object Wear .............................................................................................16 2.1.7 Secondary Side Inspection and Maintenance ........................................................16 2.1.8 Tube Repair Summary ..........................................................................................16 2.1.9 Channel Head Indications .....................................................................................17 2.1.10 Tube Plug Visual Examinations ............................................................................17 2.1.11 Secondary Side Cleaning and Inspection Summary .............................................17 2.2 1R21 Inspection Plan and Results .................................................................................18 2.2.1 Base Scope Inspection ...........................................................................................18 2.2.2 Inspection Expansion ............................................................................................19 2.2.3 Inspection Results .................................................................................................19 2.2.4 AVB Wear .............................................................................................................19 2.2.5 TSP Wear ..............................................................................................................19 2.2.6 Foreign Object Wear .............................................................................................20 2.2.7 Secondary Side Inspection and Maintenance ........................................................20 2.2.8 Tube Repair Summary ..........................................................................................20 2.2.9 Channel Head Indications .....................................................................................20 2.2.10 Tube Plug Visual Examinations ............................................................................20 2.2.11 Tube Plugging Summary .......................................................................................21 3.0 CONDITION MONITORING ..........................................................................................22 3.1 Existing Degradation Mechanisms................................................................................22 3.2 Wear at Tube Support Plates .........................................................................................22 3.2.1 TSP Burr Wear ......................................................................................................22 3.2.2 TSP Land Wear .....................................................................................................22 3.3 Wear at AVB Supports ..................................................................................................23 SG-CDMP-20-24 Revision 1 Page 4 of 48

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Westinghouse Non-Proprietary Class 3 TABLE OF CONTENTS Page 3.4 Foreign Object Wear and Foreign Material ..................................................................23 3.5 Noise Monitoring ..........................................................................................................23 3.5.1 1R21 Noise Monitoring .........................................................................................24 3.5.2 1R24 Noise Monitoring .........................................................................................27 3.6 In Situ Pressure Test Screening .....................................................................................27 3.7 Primary-to-Secondary Leakage .....................................................................................28 3.8 Chemistry Transients.....................................................................................................28 3.8.1 1R25 Chemistry Transient ....................................................................................28 3.8.2 1R26 Chemistry Transient ....................................................................................28 3.8.3 1R27 Chemistry Transient ....................................................................................29 3.9 CM Comparison to Prior OA ........................................................................................29 3.10 Condition Monitoring Conclusions ...............................................................................29 4.0 OPERATIONAL ASSESSMENT ....................................................................................30 4.1 Degradation Mechanisms Subject to OA ......................................................................30 4.2 Assessment of Wear at TSP Locations .........................................................................30 4.3 Assessment of Wear at AVB Supports .........................................................................33 4.4 Foreign Object Wear .....................................................................................................35 4.5 FOSAR Inspection Interval Consideration ...................................................................35 4.6 Stress Corrosion Cracking Assessment .........................................................................36 4.7 Volumetric Pitting in the Sludge Pile............................................................................36 4.8 Operational Assessment Conclusions ...........................................................................36 5.0 Industry Communications Review ....................................................................................37 5.1 Industry Inspection Experience Review ........................................................................40 5.2 BVPS Unit 1 Operating Experience Review.................................................................40 6.0 BVPS Unit 1 1R24 Tube Integrity Document Review .....................................................42 6.1.1 BVPS UNIT 1 1R24 DEGRADATION ASSESSMENT REVIEW ....................42 6.1.2 BVPS UNIT 1 1R26 DEGRADATION REVIEW

SUMMARY

.........................42 6.1.3 BVPS 1R24 CM AND CYCLES 25/26/27 OA REVIEW ...................................43

7.0 REFERENCES

..................................................................................................................48 SG-CDMP-20-24 Revision 1 Page 5 of 48

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Westinghouse Non-Proprietary Class 3 LIST OF TABLES Table Description Page Table 1-1: Structural and Condition Monitoring Limits for Volumetric Flaws ............................... 10 Table 2-1: 1R24 Inspection Scope ................................................................................................... 12 Table 2-2: BVPS Unit 1 Inspection Period Planning....................................................................... 13 Table 2-3: Sludge Lance & FOSAR Performance at BVPS Unit 1................................................. 13 Table 2-4: Summary of AVB Wear Indications .............................................................................. 14 Table 2-5: Summary of TSP Burr Wear Indications ....................................................................... 14 Table 2-6: Summary of 1R24 TSP Wear Indications ...................................................................... 15 Table 2-7: TSP Indication Summary From 1R24 ............................................................................ 15 Table 2-8: Foreign Object Wear Summary From 1R24 .................................................................. 16 Table 2-9: BVPS Unit 1 Tube Plugging Summary.......................................................................... 17 Table 2-10: Upper Internals Inspection Performance at BVPS Unit 1 ............................................ 18 Table 2-11: 1R21 Inspection Scope ................................................................................................. 19 Table 2-12: Summary of 1R21 AVB Wear Indications................................................................... 19 Table 2-13: Summary of 1R21 TSP Wear Indications .................................................................... 20 Table 3-1: Beaver Valley 1R21 SG 95th Percentile Bobbin Noise Measurements .......................... 24 Table 3-2: Beaver Valley 1R24 SG 95th Percentile Bobbin Noise Measurements .......................... 27 Table 5-1: Relevant Industry SG Communications Since 1R24 ..................................................... 38 Table 5-2: BVPS Unit 1 Downpowers............................................................................................. 41 Table 6-1: Summary of ETSS Changes Since 1R24 ....................................................................... 46 Table 6-2: Tube Integrity Input Parameter Review ......................................................................... 47 SG-CDMP-20-24 Revision 1 Page 6 of 48

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Westinghouse Non-Proprietary Class 3 LIST OF FIGURES Figure Description Page Figure 3-1: 1R21 TSP Wear MAPOD Plots .................................................................................... 25 Figure 3-2: 1R21 AVB Wear MAPOD Plots .................................................................................. 26 LIST OF TRADEMARKS

+POINT is a trademark or registered trademark of Zetec, Inc. Other names may be trademarks of their respective owners.

Microsoft EXCEL is a trademark or registered trademark of Microsoft Corporation. Other names may be trademarks of their respective owners.

FLEXITALLIC is a trademark or registered trademark of the Flexitallic Group, Inc. Other names may be trademarks of their respective owners.

RTAA is a registered trademark of Westinghouse Electric Company LLC, its affiliates and/or its subsidiaries in the United States of America and may be registered in other countries throughout the world. All rights reserved. Unauthorized use is strictly prohibited. Other names may be trademarks of their respective owners.

SG-CDMP-20-24 Revision 1 Page 7 of 48

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Westinghouse Non-Proprietary Class 3

1.0 INTRODUCTION

Steam generator (SG) inspections were most recently performed at Beaver Valley Power Station (BVPS) Unit 1 during Refueling Outage 24 (1R24) in October 2016 and prior to that during 1R21 in May 2012. The next planned SG inspections were scheduled to be performed during 1R27 in Spring 2021. However, in response to the government mandates associated with the COVID-19 virus pandemic to the population exposure by physical separation and limiting large gatherings of personnel, Energy Harbor is pursuing regulatory approval of a deferral of the 1R27 planned inspection scope by one operating cycle. This report documents the technical viability of deferring SG inspections by one cycle to 1R28 currently planned for Fall 2022.

Per NEI 97-06 (Reference 1), a Condition Monitoring (CM) assessment, which evaluates structural and leakage integrity characteristics of each SG at the end of the last operating period, is to be performed following each inspection. This evaluation is backward-looking and compares the observed SG tube eddy current indication parameters against leakage and structural integrity criteria of Reference 2. Condition Monitoring evaluations were completed for the 1R21 and 1R24 outages and are summarized within this report. Inspection results are summarized in the publicly available 180-day SG inspection reports (Reference 14) that are issued by the utility following the completion of each SG inspection. This report does not change any Condition Monitoring conclusions from the 1R21 and 1R24 outages and merely summarizes them to succinctly provide the background that CM has been met by standard methods for all indications detected during recent inspections for BVPS Unit 1.

Additionally, an Operational Assessment (OA), or forward-looking evaluation is used to project the inspection results and trends to confirm that the SG performance criteria will be met during the operating period until the next inspection. Operational Assessments were previously completed to justify SG tube integrity up to 1R27. This report investigates the addition of one cycle to the Operational Assessment in order to conclude that SG tube integrity is maintained at least up to 1R28 at which point the next SG inspections would occur.

Evaluations performed within this document would become the SG OA evaluations of record, should the 1R28 inspection deferral be approved by the NRC.

1.1 Steam Generator Design The BVPS Unit 1 is a three-loop plant and utilizes Westinghouse Model 54F Replacement Steam Generators (RSGs); the original Model 51 SGs were replaced at the 1R17 outage (Spring 2006).

Each Model 54F RSG includes 3592 original active tubes located on a 1.225-inch square pitch pattern. The SG tubes are thermally treated Alloy 690 (A690TT), full depth hydraulically expanded through the tubesheet thickness. The first eight rows of tubes received a full length supplemental thermal treatment following bending. The Row 1 tube bend radius is increased to 3.14 inches. Tube vibration support is provided by seven, 1.125-inch thick 405 stainless steel tube support plates (TSPs) with quatrefoil broached tube holes. The quatrefoil broached hole design includes 4 flat land contact points; the width of the contact is 0.106 inch. The Model 54F design also includes a 0.75-inch thick 405 stainless steel flow distribution baffle (FDB) located between the top of tubesheet and the first TSP. The holes of the FDB are an octofoil broach design. The FDB includes a cutout region at the center. The cutout pattern is such that all octofoil broached SG-CDMP-20-24 Revision 1 Page 8 of 48

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Westinghouse Non-Proprietary Class 3 holes are complete; the cutout does not intersect the broached hole. The tube support naming convention is FBH/FBC for the FDB, and 01H/01C through 07H/07C for the tube supports and AV1 through AV6 for anti-vibration bar (AVB) supports.

1.2 Steam Generator Operation Summary The Beaver Valley Power Station, Unit 1 plant was started in commercial service in October 1976.

The original steam generators were replaced with RSGs in 2006. At the end of Cycle 27, the plant is projected to accumulate 33.5 effective full power years (EFPY) of operating experience and 13.9 EFPY for the replacement SGs. The projected operating duration of Cycle 27 and Cycle 28 is expected to be 1.41 EFPY and 1.44 EFPY, respectively, as provided by Energy Harbor Engineering.

The nominal primary side pressure was 2235 psig for Cycle 27. The Cycle 27 average steam pressure of all loops was 805.2 psig at the main steam instrument taps downstream of the SGs. The average (99%) steam pressure for Cycle 27 is 802 psig. Per 1R24 DA, the line losses from the pressure tap to the SG are 8.9 to 10.7 psi. Using the more conservative line loss of 8.9 psig, the average pressure would be approximately 810.9 psig. The bounding differential pressure across the tubes during Cycle 27 is then 1424 psid.

The primary hot leg temperature for Cycle 27 did not exceed 618°F for any SG, which is the design basis Thot temperature for BVPS Unit 1.

There was no primary-to-secondary side leakage observed during cycles 25, 26, and 27 at BVPS Unit 1.

1.3 Steam Generator Performance Criteria NEI 97-06, Revision 3 (Reference 1) specifies the performance criteria for structural integrity and leakage integrity that must be met for CM and OA.

1.3.1 Structural Integrity Performance Criteria (SIPC)

The structural criteria were based on demonstrating capability to meet the pressure loading of 3 times the normal operating condition pressure differential (3PNO) or 1.4 times the limiting accident condition (steam line break - SLB) pressure differential (1.4PSLB). Reference 2 includes the structural integrity performance criteria (SIPC) and is defined as follows:

All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall SG-CDMP-20-24 Revision 1 Page 9 of 48

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Westinghouse Non-Proprietary Class 3 also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

The bounding differential pressure across the tubes during Cycle 27 was 1424 psid. A differential pressure of 1433.3 psi was used to establish the tube structural limits for 1R24 and used for the Cycle 25/26/27 OA. Therefore, the current steam pressure trend is bounded by the previous evaluations. The three-times normal operating tube differential pressure (3PNO) of 4300 psi is used as the minimum burst pressure requirement for satisfaction of the structural integrity performance criteria. There are no non-pressure loads conditions applicable to BVPS Unit 1 for the expected existing and potential degradation mechanisms. This performance criteria differential pressure is consistent with the value from 1R24 and bounds the values measured during Cycle 27.

The applied steam pressure values are considered to be conservative since they do not account for steam line losses between the SGs and the steam pressure measurement point nor does it consider pressure drops within the SGs that result from steam flow through components such as the primary and secondary moisture separators.

Degradation specific structural limits (SL) and condition monitoring (CM) limits were determined in accordance with recommended industry guidance provided in References 2 and 3. The structural limits are derived from the burst pressure equations provided in Reference 2 for the applicable degradation mechanism and includes the burst relation and material strength uncertainties at 0.95 probability and 50% confidence (95/50). The condition monitoring limit is also derived from the Reference 3 burst pressure equations and includes the 95/50 uncertainties for burst relation, material strength and non-destructive examination (NDE) flaw sizing.

Therefore, the NDE measured flaw size can be compared directly to the condition monitoring limit.

Table 1-1 provides the structural and condition monitoring limits for volumetric degradation mechanisms.

Table 1-1: Structural and Condition Monitoring Limits for Volumetric Flaws Axial SL Burst Equation Extent CM Depth Degradation Mechanism Depth(1)

Model (inch) (% TW)

(% TW)

AVB Wear Axial Thinning(2) 0.52 60 52.1 TSP Wear (flat) Axial Thinning(2) 1.12 55 48.7 TSP Wear (tapered 1.0 degree) Axial Thinning(2) 1.12 74 59.5 Foreign Object Wear Axial Thinning(2) 0.4 68 48.5 (1) Structural Limit includes burst relation and material strength uncertainties at 0.95 probability and 50% confidence.

(2) Axial thinning model applies to flaws of limited axial extent and circumferential extents less than 135 degrees.

SG-CDMP-20-24 Revision 1 Page 10 of 48

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Westinghouse Non-Proprietary Class 3 1.3.2 Operational Primary-to-Secondary Leakage Performance Criteria The operational leakage performance criterion from plant Technical Specifications is as follows:

The RCS operational primary-to-secondary leakage through any one steam generator shall be limited to 150 gallons per day (gpd).

1.3.3 Accident Induced Leakage Performance Criteria (AILPC)

For volumetric wear flaws with pressure-only loading condition, as is the condition for support wear and foreign object wear, tube burst and ligament tearing (i.e., pop-through) are coincident; therefore, satisfaction of the tube burst criteria at 3PNO also satisfies the accident induced leakage performance criteria (AILPC) at steam line break (SLB) differential pressure.

SG-CDMP-20-24 Revision 1 Page 11 of 48

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Westinghouse Non-Proprietary Class 3 2.0 STEAM GENERATOR OUTAGE

SUMMARY

2.1 1R24 Inspection Plan The 1R24 inspection plan satisfied the requirements of both the Technical Specifications and the Electric Power Research Institute (EPRI) Nondestructive Examination (NDE) Guidelines (Reference 2). The inspections followed the standard inspection strategy implemented at Beaver Valley Unit 1 which include 50% full length bobbin and 50% inspection of the top of tubesheet.

In 1R24, an additional eight percent of the tube population was added to the base inspection scope of fifty percent in each SG. This was based on industry operating experience and to provide additional wear indication sizing data in the event that TSP or AVB wear was reported. The eddy current inspection criteria performed in each steam generator as defined in the 1R24 Degradation Assessment is summarized in Table 2-1. The secondary side inspection scope is summarized in Table 2-3.

Table 2-1: 1R24 Inspection Scope Exam Probe Extent 58% Full-length Bobbin Coil Tube end to tube end, Except Row 1 and 2 U-bends 50% +POINT' Row 1 and 2 U-bends TTS Peripheral and Hot and cold leg TTS inspections

+POINT Tubelane (+3/-3 inch about TTS)

Hot leg BLG and OXP bobbin reports from 20% +POINT

+3/-11.4-inch TTS New AVB wear indications PLP indications and surrounding tubes Surrounding confirmed foreign objects Special Interest +POINT Freespan bobbin I-Codes (DNI, NQI, etc.)

(Diagnostic)

New proximity indications (PRO)

New dents and dings >= 1 volt 20% OXP and BLG indications in tubesheet Plug Visual per Leg Camera 1 plug inspected Secondary side in-bundle, annulus, tubelane as well as PLP FOSAR Camera reports Primary Channel Head Camera Hot leg and cold leg exam per Reference 5 Visual SG-CDMP-20-24 Revision 1 Page 12 of 48

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Westinghouse Non-Proprietary Class 3 Table 2-2: BVPS Unit 1 Inspection Period Planning EFPY Post Inspection Bobbin RSG EFPY, Accumulated EFPY Outage Replacement Period Scope Accumulated Since Commissioning 1R17 0 N/A N/A 19.613 (RSG) 1R18 1.384 N/A 100% 0 20.997 1R19 2.857 First 1.473 22.47 1R20 4.209 First 2.825 23.822 1R21 5.615 First 50% 4.231 25.228 1R22 6.988 First 5.604 26.601 1R23 8.342 First 6.958 27.955 1R24 9.660 First 58% 8.276 29.273 1R25 11.105 First 9.721 30.718 1R26 12.502 First 11.118 32.098 1R27 13.914 est. Second 12.530 est. 33.510 est.

1R28 15.352 est. Second 100% 13.968 est. 34.947 est.

Table 2-3: Sludge Lance & FOSAR Performance at BVPS Unit 1 1R27 1R28 1R18 1R19 1R20 1R21 1R22 1R23 1R24 1R25 1R26 Operation Planned Planned FOSAR X X X X X NP X NP NP NP Y Sludge Lance X X X X X NP X NP NP NP Y Eddy Current X NP NP X NP NP X NP NP NP Y X: Activity Performed, Y: Activity Recommended, NP: Not Performed 2.1.1 Inspection Expansion There was no inspection expansion during the 1R24 inspection.

2.1.2 Inspection Results During the 1R24 inspection the only degradation mechanisms reported were associated with tube wear from support structures and foreign objects. A total of 8 AVB wear indications, 24 TSP wear indications and 3 FO wear indications were reported. None of the indications exceeded the Technical Specification repair limit of 40% TW and no tubes were plugged.

2.1.3 Anti-vibration Bar (AVB) Wear There were 8 AVB wear indications detected. The largest of these flaws returned to service was 11% through-wall (TW). Seven (7) of the indications were new in 1R24 and 1 was a repeat indication from 1R21. No tubes were plugged because of AVB wear. These indications are SG-CDMP-20-24 Revision 1 Page 13 of 48

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Westinghouse Non-Proprietary Class 3 summarized in Table 2-4. AVB wear was detected and sized at 1R24 with Examination Technique Specification Sheet (ETSS) 96041.1 Revision 4.

Table 2-4: Summary of AVB Wear Indications SG Row Col Volts Ind 1R21 1R24 Chn Locn Inch1

% TW  % TW A 38 47 0.07 PCT NDD 6 P3 AV3 -0.09 A 38 47 0.1 PCT NDD 8 P3 AV4 0 A 39 59 0.13 PCT 9 9 P3 AV3 -0.15 A 40 53 0.09 PCT NDD 7 P3 AV3 -0.11 A 41 46 0.08 PCT NDD 7 P3 AV2 -0.1 A 43 51 0.13 PCT NDD 10 P3 AV4 0.07 A 43 52 0.07 PCT NDD 7 P3 AV4 0.02 B 39 52 0.23 PCT NDD 11 P3 AV3 -0.02 2.1.4 TSP Wear (TSP Burrs)

There were 3 TSP burr wear indications detected (the wear was identified coincident with a burr or section of raised metal at the edge of the TSP). The largest of these flaws returned to service was 23% TW. No tubes were plugged because of TSP burr wear. These indications are summarized in Table 2-5. TSP burr wear was sized with ETSS 21998.1, Revision 4.

Table 2-5: Summary of TSP Burr Wear Indications SG Row Col Volts Deg % TW % TW Chn Locn Inch1 % TW  % TW 1R21 1R24 Cycle Growth/EFPY Growth A 6 98 0.17 326 18 23 P4 01C 0.41 5 1.23 B 38 78 0.16 143 19 23 P4 02H 0.49 4 0.989 C 1 20 0.11 89 15 17 P4 03C 0.44 2 0.494 2.1.5 TSP Wear (TSP Lands)

There were 21 TSP land wear indications detected. The largest of these flaws returned to service was 15% TW. No tubes were plugged because of TSP wear. These indications are summarized in Table 2-6. TSP wear was detected and sized at 1R24 with ETSS I96043.1 Revision 2.

SG-CDMP-20-24 Revision 1 Page 14 of 48

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Westinghouse Non-Proprietary Class 3 Table 2-6: Summary of 1R24 TSP Wear Indications SG Row Col Volts Deg Ind  % TW Chn Locn Inch1 A 4 93 0.15 145 PCT 6 P3 06C 0.35 A 9 5 0.11 132 PCT 4 P3 06C 0.38 A 38 55 0.2 155 PCT 8 P3 06C 0.3 A 41 52 0.3 320 PCT 11 (1)

P3 02H -0.63 A 46 50 0.12 120 PCT 5 P3 05H -0.66 A 46 52 0.15 135 PCT 6 P3 05H -0.71 A 47 43 0.21 142 PCT 8 P3 06C 0.3 A 47 47 0.09 83 PCT 4 P3 04H 0.39 B 3 82 0.12 90 PCT 5 P3 05C 0.42 B 5 4 0.14 131 PCT 6 P3 05C -0.56 B 8 12 0.1 132 PCT 4 P3 05C -0.59 B 11 3 0.15 144 PCT 6 P3 05H -0.66 B 46 57 0.22 139 PCT 8 P3 06C 0.38 B 46 61 0.17 134 PCT 6 P3 06C 0.38 B 47 52 0.2 147 PCT 8 P3 06H -0.71 C 1 2 0.15 115 PCT 6 P3 06C -0.76 C 16 4 0.14 140 PCT 5 P3 05C -0.61 C 23 9 0.13 137 PCT 5 P3 05C -0.64 C 24 12 0.13 156 PCT 5 P3 05C -0.66 C 29 63 0.1 89 PCT 4 P3 06C 0.4 C 37 21 0.1 127 PCT 4 P3 05H -0.72 (1) 15% TW when sized by EXCEL fitted curve (1R24 CMOA)

Table 2-7 provides a summary of the 1R24 TSP inspection results. Of the 24 TSP wear indications, 21 were new indications of typical TSP wear and 3 are repeat indications of TSP burr wear.

Table 2-7: TSP Indication Summary From 1R24 BVPS Unit 1 1R24 TSP Summary SG-A SG-B SG-C Total Total TSP Indications 9 8 7 24 New TSP Wear 8 7 6 21 TSP Wear Tubes Affected 9 8 7 24 Tubes Plugged 0 0 0 0 SG-CDMP-20-24 Revision 1 Page 15 of 48

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Westinghouse Non-Proprietary Class 3 2.1.6 Foreign Object Wear There were three (3) foreign object wear indications detected at 1R24. SG A, R41 C52 at 02H, contained both TSP land wear and foreign object wear at the same TSP. The foreign object wear was sized at 12% TW. In SG B, two volumetric indications were noted at R47 C42 FBH measuring 14% TW and 22% TW, respectively. The presence of a foreign object was not reported at these locations by eddy current inspection. These indications are summarized in Table 2-8.

Table 2-8: Foreign Object Wear Summary From 1R24 SGID Row Col Ind  % TW Locn Inch1 Length A 41 52 PCT 12 02H -0.63 0.29-inch B 47 42 PCT 14 FBH 0.29 0.34-inch B 47 42 PCT 22 FBH 0.03 0.31-inch 2.1.7 Secondary Side Inspection and Maintenance SG secondary side maintenance activities were performed during 1R24 that included tubesheet sludge lancing, tubesheet and upper tube bundle visual inspections, and FOSAR. The secondary side inspections were performed in SG B.

Taking into account the amount of deposits removed in the 1R24 processes, the amount is reasonable and is consistent with the prior history of sludge removal from BVPS Unit 1. The next planned sludge lancing is 1R28. Sludge deposits are not expected to have an impact on SG integrity and the only impact could be degraded thermal performance.

During 1R24, all PLPs reported from eddy current inspection were reviewed by FOSAR, if possible. The video inspection also resulted in the identification of parts located on the tubesheet.

The parts judged to have possibly caused tube wear (based on size and location) and eddy current inspection of the surrounding affected tubes was conducted. A total of five objects were located during FOSAR. One object was judged to have a potential to wear on a tube. This object was identified in SG A as a 2-inch long piece of gasket material and was removed. None of the objects had any visible signs of wear. The four other objects, a machine curl, a weld bead, and two wire bristles were all less than 1/4 of an inch in size. It was determined that the presence of these objects would not challenge SG tube structural or leakage integrity up to the next scheduled eddy current inspection.

2.1.8 Tube Repair Summary No tubes were plugged in 1R21 or 1R24. One tube has been plugged in SG C during 1R18.

Table 2-9 summarizes the list of tubes plugged in each SG. As shown in the table, the cumulative total number of tubes plugged in all SGs is 1, which is equal to 0.0093% of the total number of tubes.

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Westinghouse Non-Proprietary Class 3 Table 2-9: BVPS Unit 1 Tube Plugging Summary Total Tubes Plugged SG Tubes Plugged  % Tubes Plugged A 0 0%

B 0 0%

C 1 0.028%

Total 1 0.0093%

2.1.9 Channel Head Indications Visual inspections of the hot leg and cold leg channel head internal surfaces in each SG were performed during 1R21 and 1R24 in accordance with Nuclear Safety Advisory Letter (NSAL)

NSAL-12-1 (Reference 5). During the SG channel head bowl video scan in 1R24, an anomaly was observed on the SG A divider plate-to-channel head weld. This anomaly was located on the hot leg manway side, about 2/3 of the distance to the bottom. Based on look-back of 1R21 video, there was no apparent changes in condition from 1R21 to 1R24.

2.1.10 Tube Plug Visual Examinations During 1R24 SG inspections, visual examinations were performed on previously installed tube plugs in accordance with the requirements in Section 6.10 of the EPRI SG Examinations Guidelines (Reference 8). No anomalous conditions, such as plug degradation, excessive boron deposits, or leakage were reported from the examinations.

2.1.11 Secondary Side Cleaning and Inspection Summary Table 2-10 shows the secondary side inspection history and planned inspections at BVPS Unit 1.

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Westinghouse Non-Proprietary Class 3 Table 2-10: Upper Internals Inspection Performance at BVPS Unit 1 1R27 1R28 Inspection 1R18 1R19 1R20 1R21 1R22 1R23 1R24 1R25 1R26 Planned Planned Upper Y N/A N/A X (SG B) X (SG C) X (SG A) N/A X (SG B) N/A N/A N/A Internals (SG C)

Sludge Y N/A N/A X (SG B) X (SG C) X (SG A) N/A X (SG B) N/A N/A N/A Collector (SG C)

Outlet Y

Nozzle N/A N/A N/A N/A N/A N/A X (SG B) N/A N/A N/A (SG C)

Venturi Upper Y N/A N/A X (SG B) X (SG C) X (SG A) N/A X (SG B) N/A N/A N/A Taps (SG C)

Feedring ID at Y

Spray N/A N/A NA N/A N/A N/A X (SG B) N/A N/A N/A (SG C)

Can Entrance Replace Secondary Y N/A N/A X (SG B) X (SG C) X (SG A) N/A X (SG B) N/A N/A N/A Manway (SG C)

Gasket X: Activity Performed, Y: Activity Recommended, N/A: Not Applicable 2.2 1R21 Inspection Plan and Results 2.2.1 Base Scope Inspection The 1R21 inspection plan satisfied the requirements of both the Technical Specifications and the Electric Power Research Institute (EPRI) Nondestructive Examination (NDE) Guidelines (Reference 1). The inspections followed the standard inspection strategy implemented at Beaver Valley Unit 1 which include 50% full length bobbin and 50% inspection of the top of tubesheet.

Further details on the primary inspection plans by outage can be seen above in Table 2-2. The secondary side inspection scope is summarized above in Table 2-3.

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Westinghouse Non-Proprietary Class 3 Table 2-11: 1R21 Inspection Scope Exam Probe Extent Bobbin 50% Full-length Tube end to tube end, Except Row 1 and 2 U-bends Coil 50% +POINT Row 1 and 2 U-bends TTS Peripheral and

+POINT Hot and cold leg TTS inspections (+3/-3 inch about TTS)

Tubelane PLP indications and surrounding tubes Surrounding confirmed foreign objects Special Interest +POINT 100% I-Codes (DNI, NQI, etc.)

(Diagnostic) New proximity indications (PRO)

New dents and dings >= 1 volt 100% OXP and BLG indications in tubesheet Plug Visual per Leg Camera 1 plug inspected Secondary side in-bundle, annulus, tubelane as well as PLP FOSAR Camera reports Primary Channel Head Camera Hot leg and cold leg exam per Reference 5 Visual 2.2.2 Inspection Expansion There was no inspection expansion during the 1R21 inspection.

2.2.3 Inspection Results During the 1R21 inspection the only degradation mechanisms reported were associated with tube wear from support structures and foreign objects. One (1) AVB wear indication and 3 TSP wear indications were reported. None of the indications exceeded the Technical Specification repair limit of 40% TW and no tubes were plugged.

2.2.4 AVB Wear There was one (1) AVB wear indication detected. This flaw was returned to service and was sized at 9 % TW. No tubes were plugged because of AVB wear. This indication is summarized in Table 2-12. AVB wear was detected and sized at 1R21 with ETSS 96004.1, Revision 11.

Table 2-12: Summary of 1R21 AVB Wear Indications SG Row Col Volts Deg Ind  % TW Chn Locn Inch1 A 39 59 0.21 0 PCT 9 P3 AV3 -0.04 2.2.5 TSP Wear There were 4 TSP burr wear indications detected (the wear was identified coincident with a burr or section of raised metal at the edge of the TSP). There was 1 duplicate call, leaving only 3 new SG-CDMP-20-24 Revision 1 Page 19 of 48

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Westinghouse Non-Proprietary Class 3 TSP burr wear indications. The largest of these flaws returned to service was 19% TW. No tubes were plugged because of TSP burr wear. These indications are summarized in Table 2-13. TSP burr wear was sized with ETSS 21998.1. There were no indications of traditional TSP wear detected during 1R21.

Table 2-13: Summary of 1R21 TSP Wear Indications SG Row Col Volts Deg Ind  % TW Chn Locn Inch1 A 6 98 0.09 84 PCT 18 P4 01C 0.48 B 38 78 0.11 135 PCT 19 P4 02H 0.47 C 1 20 0.09 90 PCT 16 P4 03C 0.48 2.2.6 Foreign Object Wear There were zero (0) foreign object wear indications detected.

2.2.7 Secondary Side Inspection and Maintenance SG secondary side maintenance activities were performed during 1R21 that included tubesheet sludge lancing, tubesheet and upper tube bundle visual inspections, and FOSAR. The secondary side inspections were performed in SG C.

All of the observed foreign objects were considered too small to cause significant tube damage.

These objects included a sludge rock, FLEXITALLIC gasket, and a wire bristle. In 1R21, Energy Harbor records indicate 67 object visually observed & 59 object retrieved. The largest of the unretrieved objects measured 1.0 inch, by 0.3 inch by 0.3 inch. All objects which still resided in the BVPS Unit 1 SGs after 1R21 were evaluated and the presence of these objects would not challenge SG tube structural or leakage integrity up to the next scheduled eddy current inspection at 1R24.

2.2.8 Tube Repair Summary No tubes were plugged in 1R21.

2.2.9 Channel Head Indications No abnormalities were reported during the 1R21 channel head inspections.

2.2.10 Tube Plug Visual Examinations During 1R21 SG inspections, visual examinations were performed on previously installed tube plugs in accordance with the requirements in Section 6.10 of the EPRI SG Examinations Guidelines (Reference 8). No anomalous conditions, such as plug degradation, excessive boron deposits, or leakage were reported from the examinations.

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Westinghouse Non-Proprietary Class 3 2.2.11 Tube Plugging Summary Through 1R21, BVPS Unit 1 had plugged one (1) tube in all three SGs, which constitutes a total plugging level of 0.0093%. Table 2-9 provides a summary of tubes plugged and the plugging percentage on a SG basis.

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Westinghouse Non-Proprietary Class 3 3.0 CONDITION MONITORING Condition monitoring is the assessment performed on observed tube degradation to confirm that the SG integrity performance criteria embodied in the CM limits have not been violated. Condition monitoring and structural limits for all applicable degradation morphologies are included in the 1R24 DA, summarized in Table 1-1. The condition monitoring limit is evaluated at 95%

probability and includes the effects of burst relational error, material property variance, and non-destructive examination (NDE) sizing uncertainty. As such, as-reported indication depths can be directly compared against the condition monitoring limit for evaluation of compliance with the performance criterion. This is a summary of the previous CM assessment and does not change any conclusions from prior CM reports. This section is provided to summarize the prior CM evaluations and to demonstrate that CM has been met by standard methods for all indications detected during recent inspections. It was demonstrated at 1R24 that the prior OA methodology provided conservative results with respect to the detected degradation.

3.1 Existing Degradation Mechanisms The existing tube degradation mechanisms identified at BVPS Unit 1 through 1R24 are:

• Wear at TSP intersections

• Wear at AVB intersections

• Foreign object wear The subsections below provide additional information pertaining to the above existing tube degradation mechanisms.

3.2 Wear at Tube Support Plates 3.2.1 TSP Burr Wear At 1R21 three tubes were reported to contain indications at TSP locations; the wear was identified coincident with a burr or section of raised metal at the edge of the TSP. The maximum depth of all TSP burr wear indications reported during 1R24 was 23% TW. The burr indications are characterized as having a flat depth profile with short (approximately 0.25 inch) axial lengths. The condition monitoring limit for a length of 0.23 inch is 59% TW using the ETSS 21998.1 depth uncertainties and no length uncertainty. Prior evaluations have shown the +POINT coil will overestimate the axial length of volumetric indications by approximately 0.12 to 0.16 inch thus use of the indicated length of 0.23 inch is conservative. The maximum flaw depth of 23% TW is also less than the CM limit for a length of 0.4 inch, which is 48.5% TW. Therefore, the SG performance criteria for structural and leakage integrity were demonstrated.

3.2.2 TSP Land Wear Tube wear at TSPs located on the quatrefoil land was reported at 21 locations during 1R24. One of the tubes in SG A, R41 C52, contained both TSP land wear and foreign object wear at the same TSP. One of the tubes in SG B, R47 C52, contained wear on two of the four quatrefoil lands.

Testing with the +POINT coil indicated that all TSP land wear indications were tapered.

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Westinghouse Non-Proprietary Class 3 The sizing of TSP wear at 1R24 was performed using two methods, as a specific TSP wear calibration standard was not available for BVPS Unit 1. The deepest depth estimated from the more conservative of the two methods was 15% TW at R41 C52 in SG A. This method estimated depth as a function of P1 vertical maximum signal amplitude and included the tapered broach wear flaws of ETSS 96043.1 combined with a laboratory specimen using a piece of BVPS Unit 1 archive tubing into which flaws mimicking the BVPS Unit 1 TSP geometry were produced.

Table 1-1 provides a condition monitoring limit depth of 59.5% TW for tapered TSP wear. The condition monitoring limit depth includes NDE, burst relation, and material property variances and is evaluated at a lower 95% probability level. The maximum depth of 15% TW is less than the condition monitoring limit. Therefore, the SG performance criteria for structural and leakage integrity were demonstrated.

3.3 Wear at AVB Supports There were 8 AVB wear indications detected at 1R24. The largest of these flaws returned to service was 11% TW at R39 C52 at AV3 in SG B. A review of the 1R21 data indicates that a precursor signal is present. For the next largest indication (10% TW), a review of the history data from 1R21 could not identify a precursor signal. Table 1-1 provides a condition monitoring limit depth of 52.1% TW for flat AVB wear. +POINT probe testing indicated the AVB wear indications were tapered thus comparison with the flat AVB condition monitoring limit is conservative. The CM limit depth includes NDE, burst relation, and material property variances and is evaluated at a lower 95% probability level. The maximum depth of 11% TW is less than the condition monitoring limit. Therefore, the SG performance criteria for structural and leakage integrity were demonstrated.

3.4 Foreign Object Wear and Foreign Material There were three (3) foreign object wear indications detected at 1R24 (Table 2-8). The largest flaw depth of 22% TW is less than the condition monitoring limit of 48.5% TW for volumetric indications with 0.4 inch axial extents. All foreign object wear indications were less than 0.4-inch length assumed in the calculation of the CM limit. The CM limit contains all uncertainties, including NDE flaw measurement, at 0.95 probability and 50% confidence so that NDE measured flaw depth can be compared directly to this limit. Therefore, the SG performance criteria for structural and leakage integrity were demonstrated.

3.5 Noise Monitoring Noise measurements were collected throughout the Beaver Valley 1R21 and 1R24 bobbin coil and

+POINT probe inspections of all three SGs. The automated eddy current data analysis software Real Time Automated Analysis (RTAA') was used to perform bobbin coil noise measurements as recommended in Appendix N of Reference 1 and manual noise measurements were recorded.

The noise measurements were collected within the regions of interest (ROI) where existing and potential degradation could occur in the Beaver Valley Unit 1 SGs.

Noise monitoring can be used to support the development of site-specific probability of detection (POD) relations for use in the operational assessment.

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Westinghouse Non-Proprietary Class 3 3.5.1 1R21 Noise Monitoring The summarized 95th percentile noise levels for each ROI during the 1R21 inspection are shown in Table 3-1.

Table 3-1: Beaver Valley 1R21 SG 95th Percentile Bobbin Noise Measurements Measured Noise at 95th Percentile, Region of Vvm ROI Noise Extent Interest SG A SG B SG C Support Edge Cold TSP CL 0.08 0.06 0.07 Edge Support Edge Hot TSP HL 0.06 0.06 0.07 Support Center Cold TSP CL 0.05 0.04 0.05 Center Support Center Hot TSP HL 0.05 0.04 0.05 Full Width Baffle TSP HL/CL Full Width 0.07 0.06 0.07 Vertical Strap Center AVB Full Width 0.09 0.06 0.06 A site-specific POD function for maximum flaw depth for both TSP and AVB wear was developed using the EPRI Model Assisted Probability of Detection (MAPOD) code (Reference 6). The MAPOD model combines the bobbin probe detection voltage amplitude to true depth distribution correlation (AHAT) with the site-specific noise distributions to generate a site-specific noise-based POD curve for maximum flaw depth. The AVB noise distribution is based on the full width of the structure and the TSP noise distribution is based on both the support edge and center. The ETSS AHAT technique used for the TSP and AVB wear was 96043.4 (tapered flaws only) and 96041.1, respectively. Figure 3-1 and Figure 3-2 provide the results of the Beaver Valley 1R21 specific MAPOD simulation for TSP and AVB wear. The simulation provided a result of a 95th percentile maximum depth value of 8% TW for TSP wear and 7% for AVB wear.

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Westinghouse Non-Proprietary Class 3 Figure 3-1: 1R21 TSP Wear MAPOD Plots SG-CDMP-20-24 Revision 1 Page 25 of 48

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Westinghouse Non-Proprietary Class 3 Figure 3-2: 1R21 AVB Wear MAPOD Plots SG-CDMP-20-24 Revision 1 Page 26 of 48

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Westinghouse Non-Proprietary Class 3 3.5.2 1R24 Noise Monitoring The summarized 95th percentile noise levels for each ROI during the 1R24 inspection are shown in Table 3-2.

Table 3-2: Beaver Valley 1R24 SG 95th Percentile Bobbin Noise Measurements Measured Noise at 95th Percentile, Region of Noise Vvm ROI Interest Extent SG A SG B SG C Support Edge Cold TSP CL 0.07 0.07 0.07 Edge Support Edge Hot TSP HL 0.06 0.07 0.06 Support Center Cold TSP CL 0.05 0.05 0.05 Center Support Center Hot TSP HL 0.05 0.05 0.05 Full Width Baffle TSP HL/CL Full Width 0.07 0.07 0.06 Vertical Strap Center AVB Full Width 0.08 0.07 0.07 A site-specific POD function for maximum flaw depth for both TSP and AVB wear was developed using the EPRI Model Assisted Probability of Detection (MAPOD) code (Reference 6). The MAPOD model combines the bobbin probe detection voltage amplitude to true depth distribution correlation (AHAT) with the site-specific noise distributions to generate a site-specific noise-based POD curve for maximum flaw depth. The AVB noise distribution is based on the full width of the structure and the TSP noise distribution is based on both the support edge and center. The ETSS AHAT technique used for the TSP and AVB wear was 96043.4 (tapered flaws only) and 96041.1, respectively. The simulation provided a result of a 95th percentile maximum depth value of 7%

TW for TSP wear and 7% for AVB wear for 1R24. The simulation was evaluated for the 1R21 inputs, providing a 95th percentile maximum depth value of 8% TW for TSP wear and 7% for AVB wear. The more conservative values from 1R21 were then applied and used for the operational assessment due to this being the longest interval between inspections for any undetected flaw.

3.6 In Situ Pressure Test Screening All indications of degradation were screened for in situ pressure test applicability in accordance with Reference 4. Reference 4 provides the screening methodology to determine when proof (burst) testing and leakage testing is necessary to demonstrate compliance with the SG structural integrity and accident induced leakage performance criteria for condition monitoring. The initial screening criteria is based on eddy current voltage. Volumetric wear at TSP and AVB intersections are the degradation mechanisms identified during the 1R24 SG inspection.

All existing wear met condition monitoring structural limits and, therefore, did not require in situ proof testing. Furthermore, all existing wear and volumetric degradation mechanism indication voltages were less than the Reference 4 initial voltage screening requirement of 3.0 volts for proof and leakage testing. Therefore, in situ proof and leak testing was not required for any wear degradation mechanisms.

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Westinghouse Non-Proprietary Class 3 3.7 Primary-to-Secondary Leakage No operating primary-to-secondary leakage has been reported in BVPS Unit 1 as stated in the Degradation Assessment.

3.8 Chemistry Transients A review of the past chemistry transients dating back to refueling cycle 25 was performed (Reference 15).

3.8.1 1R25 Chemistry Transient There was a condenser leak in January 2018 of a smaller magnitude compared to the June 28, 2018 event that was the result of FME striking a condenser tube in the top row of the B waterbox in the condenser. Steam generator sodium reached a maximum value of 5.87 ppb, which is above the Action Level 1 limit of 5 ppb. Sulfate and chloride did not enter action level during this excursion. The excursion above 5 ppb for sodium lasted approximately 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. All responses and actions taken during the excursion met the time frames as required in the EPRI PWR Secondary Water Chemistry Guidelines, Rev 7 (which was effective at the time) to return parameters to normal levels. This Action Level response has been developed to protect corrosion of A600MA and A600TT tubing SGs. Since BVPS Unit 1 SGs are designed with A690TT tubing and their designed increased resistance to corrosion, this chemistry transient are expected not to have an adverse impact on SG integrity. Also, there has been no primary-to-secondary leakage reported during the current cycle.

There was a forced outage in November 2017, that caused elevated steam generator sodium, chloride and sulfate concentrations while the plant was shutdown. No EPRI Action levels were exceeded. All responses and actions taken during the outage met the time frames as required in the EPRI PWR Secondary Water Chemistry Guidelines, Rev 7 (which was effective at the time) and when the plant resumed power operation, all parameters returned to normal levels. This Action Level response has been developed to protect corrosion of A600MA and A600TT tubing SGs.

Since BVPS Unit 1 SGs are designed with A690TT tubing and their designed increased resistance to corrosion, this chemistry transient are expected not to have an adverse impact on SG integrity.

Also, there has been no primary-to-secondary leakage reported during the current cycle.

3.8.2 1R26 Chemistry Transient BVPS Unit 1 experienced an EPRI Action Level 2 event for elevated sodium, chloride and sulfate in 2018. The INPO Chemistry Effectiveness Index was ~ 19.52, primarily due to a significant condenser leak in June 2018. The maximum concentration of steam generator contaminants reached during the excursion were: 87 ppb sodium, 108 ppb chloride, 221 ppb sulfate. The plant initially decreased power to 82% for leak search and subsequently lowered power further to 47%. One leaking tube was identified and plugged in the top row of the C waterbox in the condenser. Fifty additional tubes were plugged in the top of the East Bank of the C waterbox at this time. Foreign material (condenser drip shield plate) caused the condenser tube leak. All responses and actions taken during the excursion met the time frames as required in the EPRI PWR Secondary Water Chemistry Guidelines, Rev 8 to return parameters to normal levels. Power escalation began when steam generator sulfate was less than 10 ppb. This Action Level response SG-CDMP-20-24 Revision 1 Page 28 of 48

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Westinghouse Non-Proprietary Class 3 has been developed to protect corrosion of A600MA and A600TT tubing SGs. Since BVPS Unit 1 SGs are designed with A690TT tubing and their designed increased resistance to corrosion, this chemistry transient are expected not to have an adverse impact on SG integrity. Also, there has been no primary-to-secondary leakage reported during the current cycle.

3.8.3 1R27 Chemistry Transient There have been no chemistry transients during the current operating cycle. Also, there has been no primary-to-secondary leakage reported during the current cycle.

3.9 CM Comparison to Prior OA Reference 2 recommends that the condition monitoring results from the current inspection be compared to the Operational Assessment from the previous inspection. This comparison identifies whether the underlying assumptions, input parameters, or methodology for performing Operational Assessments are conservative or require alteration prior to performing the next Operational Assessment. Even when CM requirements are met, this comparative review may identify adjustments to the OA inputs or assumptions.

For the existing degradation mechanisms at BVPS Unit 1, AVB and TSP wear, a comparison of the previous OA projections performed at 1R21 were compared to the 1R24 inspection results.

For each OA performed, the 1R21-1R24 inspection period length was assumed to be 4.20 EFPY.

The actual duration from 1R21-1R24 was 4.04 EFPY; therefore, the 1R21 OA inspection period length was conservative.

The 1R21 OA provided numerous projections for maximum TSP burr wear depth at 1R24. The most conservative projection was 39% TW based on the bobbin probe sizing. The projection using the rotating pancake coil (RPC) sizing (applicable for 1R24) was 37% TW and based on a volume growth approach. The maximum TSP burr wear indication was sized at 23% TW by RPC at 1R24.

Therefore, the 1R21 OA projection was conservative.

For AVB and TSP land wear, the 1R21 OA did not have indications available and projected that any new wear would be less than the CM limits. This was found to be true at 1R24, with all AVB and TSP land wear depths below the CM limits.

3.10 Condition Monitoring Conclusions All wear indications are well below the condition monitoring limit considering material property and NDE measurement and analyst uncertainty, as specified in the Degradation Assessment. The primary side visual inspections of the channel head internal surfaces and tube plugs showed no conditions affecting tube or SG integrity. Therefore, the condition monitoring criteria of NEI 97-06 are satisfied.

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Westinghouse Non-Proprietary Class 3 4.0 OPERATIONAL ASSESSMENT An Operational Assessment (OA) involves projecting the condition of the SG tubes to the time of the next scheduled inspection outage and determining their acceptability relative to the tube integrity performance criteria of NEI 97-06 (Reference 1). All degradation mechanisms detected at prior and the current SG inspection shall be evaluated. Results of secondary side inspections are evaluated if tube integrity can be impacted. The fundamental objective of an OA is to ensure that the structural integrity and accident induced leakage performance criteria will be met over the length of the upcoming operating interval. The OA methodology considers detection sensitivity on detected and potentially undetected degradation, NDE sizing uncertainty, and degradation growth rates when performing degradation projections over the next operational period. In terms of structural integrity, the fundamental OA requirement is that the projected worst-case degraded tube for each existing degradation mechanism meets the limiting structural performance parameter with a 0.95 probability at 50% confidence (95/50).

This OA for existing degradation mechanisms is performed to justify four cycles of operation. The prior OA provided a three cycle estimate of 4.258 EFPY as an upper bound best estimate of the operating cycle lengths from 1R24 to 1R27. The projected duration from 1R24-1R28 is estimated to be 5.691 EFPY. A conservative value of 6.00 EFPY is used in all the OA projection calculations, to account for any changes from the estimated to actual cycle lengths of Cycle 27 and Cycle 28.

For all OA calculations, mean material strength (Su+Sy) was 119.1 ksi with a standard deviation 1.85 ksi, 3PNOP was 4300 psi, tube outside diameter (OD) was 0.875 inch, and tube thickness was 0.050 inch.

4.1 Degradation Mechanisms Subject to OA The existing degradation mechanisms subject to the operational assessment through Cycle 28 are:

• TSP land wear

• AVB wear

• Foreign object wear 4.2 Assessment of Wear at TSP Locations During 1R24, 24 TSP wear indications were reported. There were 3 TSP burr wear indications detected (the wear was identified coincident with a burr or section of raised metal at the edge of the TSP) and 21 newly discovered TSP land wear indications.

The three TSP burr wear indications were historical indications from 1R21 and exhibited negligible growth rates. Therefore, these TSP burr indications are not expected to show further increase in wear over time because the wear reached the limits of the burr. The TSP land wear indications measured during 1R24 are typical of TSP wear observed in other Model 54F SGs and are expected to experience typical wear growth; therefore, are considered in this Operational Assessment.

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Westinghouse Non-Proprietary Class 3 The largest TSP land wear flaw left in service at 1R24 was 15% TW and will be used for OA projections. The largest indication left in service is assumed to be flat and 1.125 inches long, based on the full width of the TSPs. This assumption is conservative because the measured TSP wear indications were tapered and did not cover the entire TSP width. To predict the maximum wear depth at 1R28 the following parameters were considered:

• The estimated durations for inspection intervals are based on cycle durations from Table 2-2.

• The projected EFPY from 1R21-1R28 is estimated to be 9.737. A conservative number of 10.00 EFPY was used in all the OA projection calculations, to account for any changes from the estimated to actual cycle lengths of Cycle 27 and Cycle 28.

• The projected EFPY from 1R24-1R28 is estimated to be 5.691 A conservative number of 6.00 EFPY was used in all the OA projection calculations, to account for any changes from the estimated to actual cycle lengths of Cycle 27 and Cycle 28.

• BVPS Unit 1 tubing material properties from the EPRI Flaw Handbook (Reference 3) and NDE uncertainties from ETSS I96043.1, which were also calculated in the 1R24 OA.

• A growth rate of 4.33% TW/EFPY is used. The 1R24 OA calculated various growth rates for TSP wear and the most conservative value of 4.33% TW/EFPY was based on the deepest indication at SG A-R41C52. The growth rate considered initiation at beginning of Cycle 22 and depth sizing uncertainty.

Deterministic Worst-Case Degraded Tube OA for Existing TSP Wear The largest TSP wear flaw returned to service was SG A-R41C52 at 02H and was conservatively sized as 15%. The projected 1R28 flaw depth can be calculated arithmetically by applying a growth rate of 4.33% TW/EFPY and using a 6.00 EFPY from 1R24 until the next inspection at 1R28:

128 =

15% + 4.33 % 6.00 = 41 %

This result is less than 48.7% TW 95/50 Condition Monitoring limit; therefore, structural performance criteria are satisfied for operational assessment through 1R28. Additional margin exists when considering the tapered TSP wear condition monitoring limit of 59.5% TW, which would be appropriate since the TSP land wear at 1R24 was found to be tapered (59.5%-48.7% =

10.8% TW additional margin for 1 degree tapered wear).

Deterministic Worst-Case Degraded Tube OA for Undetected TSP Wear The largest undetected TSP wear flaw that could be returned to service is conservatively assumed from the MAPOD POD curve as 8%, per the calculations performed in Section 3.5.1. Tapered only Ahat data was used since the only indications of TSP wear at Beaver Valley are tapered. For conservativism, noise at the edge and center of the supports was evaluated in MAPOD to get the SG-CDMP-20-24 Revision 1 Page 31 of 48

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Westinghouse Non-Proprietary Class 3 95/50 POD of 8% TW. Using only the edge noise, where these indications are likely to start, the 95/50 POD was 7% TW. The projected 1R28 flaw depth can be calculated arithmetically by applying a growth rate of 4.33% TW/EFPY and using a 10.00 EFPY from 1R21 until the next inspection at 1R28:

128 =

8.00% + 4.33 % 10.00 = 51%

This result is less than 55% TW 95/50 EOC structural limit; therefore, structural performance criteria are satisfied for operational assessment through 1R28. Additional margin exists when considering the tapered TSP wear structural limit of 74% TW, which would be appropriate since the existing TSP land wear was found to be tapered (74%-55% = 19% TW additional margin for 1 degree tapered wear). Since the flaw is not measured, there is no need to adjust the depth for NDE sizing uncertainty.

Monte Carlo Worst-Case Degraded Tube OA for Undetected TSP Wear The worst-case degraded tube Monte Carlo OA method projects the worst-case beginning of cycle (BOC) flaw over the next operating period through application of a constant flaw growth and all relevant uncertainties applied through probabilistic Monte Carlo simulations. For each simulation, each uncertainty term, the standard normal deviate, Z, is randomly sampled from a normal distribution with a mean of 0 and a standard deviation of 1. A minimum of 100,000 simulations were performed for this OA. The relevant uncertainties sampled for each simulation using the Monte Carlo technique are tube material strength, burst relation, and NDE sizing uncertainties.

Also, for this OA, a constant depth growth value distribution was conservatively used instead of the actual growth distribution. The worst-case degraded tube Monte Carlo calculations are performed using the Westinghouse Single Flaw Model (SFM) software code (Reference 7). The SFM model calculates the 95/50 burst pressure at the end of the OA operating period for a given BOC flaw depth and BOC flaw length. This result is compared to the minimum required burst pressure necessary to maintain the structural integrity performance criterion of 3PNOP, (4300 psi).

All inputs to this evaluation are the same as the deterministic evaluation described above, with the exception that the standard normal deviate, Z, is sampled, instead of using a constant upper 95th percentile value of 1.645. A discussion of the simulation results is provided below.

The result of a worst-case projected undetected TSP wear flaw from 1R21 at 8% TW has a burst pressure of 4530 psi at 95% probability and 50% confidence levels for a projected 10.0 EFPY.

These results compare favorably to the bounding 3PNO loading limit of 4300 psi for structural burst and the structural limit of 55% TW. The 8% TW is the 95 percentile from the MAPOD curve and would bound all undetected flaws smaller than 8% TW, as well as any undetected flaws from 1R24.

For volumetric wear flaws with pressure-only loading condition, as is the condition for TSP wear, tube burst and ligament tearing (i.e., pop-through) are coincident, therefore, satisfaction of the tube burst criteria at 3PNO also satisfies the AILPC at steam line break differential pressure. Therefore, SG-CDMP-20-24 Revision 1 Page 32 of 48

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Westinghouse Non-Proprietary Class 3 for assumed existing and undetected TSP wear the SG structural and leakage performance criteria are satisfied for operational assessment through 1R28.

4.3 Assessment of Wear at AVB Supports The largest AVB wear flaw left in service during 1R24 was 11% TW. The length of the largest indication left in service is assumed to be 0.5 inch based on the size of the AVBs. This assumption is conservative, assuming that the AVB wear scar is the complete length of the AVB support touching the tube. To predict the maximum wear depth at 1R28 the following parameters were considered:

• The estimated durations for inspection intervals are based on cycle durations from Table 2-2.

• The projected EFPY from 1R21-1R28 is estimated to be 9.737. A conservative number of 10.00 EFPY was used in all the OA projection calculations, to account for any changes from the estimated to actual cycle lengths of Cycle 27 and Cycle 28.

• The projected EFPY from 1R24-1R28 is estimated to be 5.691 A conservative number of 6.00 EFPY was used in all the OA projection calculations, to account for any changes from the estimated to actual cycle lengths of Cycle 27 and Cycle 28.

• BVPS Unit 1 tubing material properties from the EPRI Flaw Handbook (Reference 3) and NDE uncertainties from Examination Technique Specification Sheet (ETSS) I96041.1.

• A growth rate of 5.00%/EFPY will be used in all OA calculations for AVB wear. A Beaver Valley Unit 1 AVB growth rate could not be determined because of the limited wear indications. Growth rates of other Model 54F and Delta 54 SGs were considered. The average growth rate for these SGs is approximately 3% TW/EFPY. A growth rate of 5% TW/EFPY is considered bounding and conservative based on similar SGs with enough data for growth determinations.

Deterministic Worst-Case Degraded Tube OA for Existing AVB Wear The largest AVB wear flaw returned to service was SG B-R39C52 at AV3 and was sized as 11%

using ETSS I96041.1. The projected 1R28 flaw depth can be calculated arithmetically by applying a growth rate of 5% TW/EFPY and using a 6.00 EFPY from 1R24 until the next inspection at 1R28:

128 =

11% + 5.00% 6.0 = 41%

This result is less than 52.1 % TW 95/50 Condition Monitoring limit; therefore, structural performance criteria are satisfied for operational assessment through 1R28.

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Westinghouse Non-Proprietary Class 3 Deterministic Worst-Case Degraded Tube OA for Undetected AVB Wear The largest undetected AVB wear flaw that could be returned to service is conservatively assumed from the MAPOD POD curve as 7% with calculations from Section 3.5.1. The projected 1R28 flaw depth can be calculated arithmetically by applying a standardized growth rate of 5% TW/EFPY and using a 10.00 EFPY from 1R21 until the next inspection at 1R28:

128 =

7.00% + 5.00% 10.00 = 57%

This result is less than 60% TW end of cycle (EOC) SL; therefore, structural performance criteria are satisfied for operational assessment through 1R28. Since the flaw is not measured, there is no need to adjust the depth for NDE sizing uncertainty.

Monte Carlo Worst-Case Degraded Tube OA for Undetected AVB Wear The worst-case degraded tube Monte Carlo OA method projects the worst-case BOC flaw over the next operating period through application of a constant flaw growth and all relevant uncertainties applied through probabilistic Monte Carlo simulations. For each simulation, each uncertainty term, the standard normal deviate, Z, is randomly sampled from a normal distribution with a mean of 0 and a standard deviation of 1. A minimum of 100,000 simulations were performed for this OA. The relevant uncertainties sampled for each simulation using the Monte Carlo technique are tube material strength, burst relation, and NDE sizing uncertainties. Also, for this OA, a constant depth growth value distribution was conservatively used instead of the actual growth distribution.

The worst-case degraded tube Monte Carlo calculations are performed using the WEC Single Flaw Model (SFM) software code (Reference 7). The SFM model calculates the 95/50 burst pressure at the end of the OA operating period for a given BOC flaw depth and BOC flaw length. This result is compared to the minimum required burst pressure necessary to maintain the structural integrity performance criterion of 3PNOP, (4300 psi).

All inputs to this evaluation are the same as the deterministic evaluation described above, with the exception that the standard normal deviate, Z, is sampled, instead of using a constant upper 95th percentile value of 1.645. A discussion of the simulation results is provided below.

The result of a worst-case projected undetected AVB wear flaw from 1R21 at 8% TW has a burst pressure of 4465 psi at 95% probability and 50% confidence levels for a projected 10.0 EFPY.

These results compare favorably to the bounding 3PNO loading limit of 4300 psi for structural burst and the structural limit of 60% TW. For pressure-only loading of volumetric flaws, satisfaction of structural integrity implies satisfaction of leakage integrity at accident conditions since steam line break accident condition pressure differential for pop-through is much smaller than 3PNO.

For volumetric wear flaws with pressure-only loading condition, as is the condition for AVB wear, tube burst and ligament tearing (i.e., pop-through) are coincident, therefore, satisfaction of the tube burst criteria at 3PNO also satisfies the AILPC at steam line break differential pressure. Therefore, SG-CDMP-20-24 Revision 1 Page 34 of 48

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Westinghouse Non-Proprietary Class 3 for assumed existing and undetected TSP wear the SG structural and leakage performance criteria are satisfied for operational assessment through 1R28 using simplistic deterministic methods.

4.4 Foreign Object Wear There were three (3) foreign object wear indications detected at 1R24 (Table 2-8). The largest flaw depth of 22% TW satisfies the condition monitoring limit of 48.5% TW for volumetric indications with 0.4 inch axial extents. All foreign object wear indications were less than 0.4-inch length assumed in the calculation of the CM limit. The CM limit contains all uncertainties, including NDE flaw measurement, at 0.95 probability and 50% confidence so that NDE measured flaw depth can be compared directly to this limit. The presence of a foreign object was not reported at these locations by eddy current inspection. Therefore, no mechanism to produced further flaw progression is expected during future operations. With no mechanism expected for further flaw growth and all wear flaws satisfying condition monitoring limits, all SG performance criteria for structural and leakage integrity will be satisfied until the end of Cycle 28.

4.5 FOSAR Inspection Interval Consideration Foreign object wear has been detected within the BVPS Unit 1 SGs through the 1R24 inspection; therefore, foreign object wear is categorized as an existing degradation mechanism.

Section 10 of Reference 2 requires determination of an appropriate FOSAR inspection interval.

The Reference 2 guidance states that FOSAR should be performed each time sludge lancing is performed and/or when there is reason to expect that foreign material has been introduced in the SG secondary side. The FOSAR interval is determined based on the plants historical foreign objects, foreign object wear indications, maintenance activities, and planned primary side inspection intervals. The evaluation should consider the following elements when considering the appropriate FOSAR interval:

• Location and description of historical foreign objects

• Description of foreign objects with associated wear indications

• High secondary side fluid flow, or other susceptible areas

• Secondary side inspection limitations

• The type of material entering the SGs and potential for tube degradation

• Plant-specific and industry trends for foreign object wear

• Foreign material collection or trapping system The most recent sludge lancing and FOSAR was performed in 1R24.

All of the foreign objects that were not able to be retrieved during 1R24 have been evaluated in Reference 12 and the analysis concludes that there is no threat to tube integrity before the 1R28 inspections. It is recommended that all foreign objects which were previously evaluated should be reviewed during FOSAR operations at 1R28.

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Westinghouse Non-Proprietary Class 3 4.6 Stress Corrosion Cracking Assessment Stress corrosion degradation at the top of tubesheet expansion transition and U-bends was not expected or detected at the 1R24 inspection and is not expected at the 1R28 inspection. The hydraulic expansion process results in the lowest residual stress level of all tube in tubesheet expansion processes. The first industry reports of stress corrosion degradation in Alloy 600 thermally treated units occurred at approximately 15 EFPY. Considering the inherent improvement afforded by Alloy 690 thermally treated tube material and reduced operating temperature of BVPS Unit 1 compared to these other units, stress corrosion degradation is not expected at the 1R28 inspection. The first 8 rows of tubes received a full length supplemental thermal treatment following bending. This process is expected to result in residual stresses for the U-bends of near straight leg levels. Thus, primary water stress corrosion degradation is not expected in Row 1 through 8 U-bends at 1R28.

4.7 Volumetric Pitting in the Sludge Pile In fall of 2015, a possible volumetric indication was located in the sludge pile at another A690TT plant. With this being a first of a kind indication, the degradation was conservatively classified by the plant as pitting. There have been no other indications of this kind noted in any other A690TT plant and these indications were not found to grow in size or quantity since first identified. There is no evidence this is a widespread concern for the A690TT fleet. There has been no degradation like this found at BVPS Unit 1. Therefore, this event is not applicable to BVPS Unit 1 and pitting is a non-relevant mechanism.

4.8 Operational Assessment Conclusions For the existing degradation mechanisms for the BVPS Unit 1 SGs, OA evaluations were performed that demonstrate that all structural and leakage integrity performance criteria are expected to be maintained through to the EOC 28. An OA evaluation was also performed for AVB and TSP wear potentially not detected during the 1R24 inspection. This OA also demonstrated that all structural and leakage integrity performance criteria are expected to be maintained through to the end of Cycle 28.

The were no degraded or anomalous conditions identified during the primary side channel head and tube plug visual inspections and the integrity and function of these components are expected to be maintained until the EOC 28.

The BVPS Unit 1 1R24 ECT, FOSAR inspection findings, and foreign object evaluations conclude that secondary side integrity of the SG will be maintained operating through Cycle 28.

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Westinghouse Non-Proprietary Class 3 5.0 INDUSTRY COMMUNICATIONS REVIEW Relevant industry communications are considered for the BVPS Unit 1 Degradation Review. This includes information from Nuclear Energy Institute (NEI), Westinghouse, EPRI Steam Generator Management Programs (SGMP), the Nuclear Regulatory Commission (NRC) and Institute of Nuclear Power Operations (INPO). The 1R24 DA provided tabulations of the communications considered relevant to BVPS Unit 1 and were available prior to the BVPS Unit 1 1R24 SG inspection.

Table 5-1 provides a listing of the relevant SG related industry communications published since the completion of the RF24 DA that was completed in August 2016. There had been no NEI and NRC generic communications since the RF24 DA was completed. A review of the INPO operating experience (OE) reports was performed (inpo.org) and relevant OE are listed in Table 5-1. The OE listings in Table 5-1 do not change or alter the conclusions of the prior OA for an inspection interval from 1R24 to 1R27.

EPRI SGMP has published a number of technical reports since the RF24 DA and OA have been completed as listed in Table 5-1. These reports are academic in nature and do not affect the conclusions of the RF24 DA and OA. EPRI SGMP has issued interim guidance that modified the content of the SG Examination Guidelines (Reference 11). The industry transmittal of the interim guidance is contained in EPRI letter SGMP-19-1, dated March 14, 2019. The interim guidance provides clarifications, wording changes, and allows alternate approaches to established practices.

These changes have no effect on the conduct or results of the 1R24 SG inspections and, therefore, have no effect on the conclusions of the 1R24 DA and OA.

Westinghouse issued Revision 1 to NSAL 05-2 (Reference 5). The original NSAL described an error in the original SG stress calculations related to 2.5-inch and less un-reinforced SG secondary side penetration cover plate bearing stress. The 2005 resolution for this error was performance of an elastic-plastic analysis to demonstrate compliance with ASME stress limits. BVPS Unit 1 was not identified as an affected plant, as the Model 54 F RSGs have 6-inch OD hand holes and 4-inch OD inspection ports, larger than the 2.5-inch OD un-reinforced ports evaluated by the NSAL.

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Westinghouse Non-Proprietary Class 3 Table 5-1: Relevant Industry SG Communications Since 1R24 Document Date Title NRC Communications: None NEI Communications: None INPO Communications Condenser Tube Leak Results in a Unit Unplanned Down Power ICES 430599 1/9/2018

- Beaver Valley Unit 1 Unplanned Shutdown to Address Steam Generator Sulfates and ICES 430967 1/13/2018 Chlorides Ingress - Harris Unit Downpower to Repair Condenser Tube Leak - Palo Verde ICES 435370 4/5/2018 Unit 1 Leaking Condenser Tube Causes Out of Specification Steam ICES 440399 6/28/2018 Generator Chemistry - Beaver Valley Unit 1 Unit Power Reduced to Detect and Repair Condenser Tube Leak ICES 441118 7/2/2018

- Palo Verde Unit 1 Steam Generator Sodium Exceeds Action Level Due to ICES 446106 9/15/2018 Condenser Tube Leak - ANO Unit 2 Condenser Tube Leak Results in Exceeding Action Levels for ICES 450950 2/3/2019 Secondary Chemistry and Unit Down-Power ICES 457620 4/22/2019 Reactor Shutdown Due to Boiler Tube Leak (SG tube leak)

Steam Generator Feed Pump Vibrations Result in Unit ICES 457963 5/28/2019 Downpower - Point Beach Unit 2 Unscheduled Power Reduction Due to Feedwater Heater Tube ICES 456078 5/28/2019 Leak - River Bend Unit 1 Unplanned Trip of Feedwater Heaters Causes Forced ICES 459343 7/7/2019 Downpower - Columbia Unit 2 Unscheduled Power Reduction Due to Condenser Tube Leak -

ICES 467423 10/15/2019 River Bend Unit 1 Unit Downpower To Repair Condenser Tube Leak - Palo Verde ICES 467289 10/17/2019 Unit 2 Power Reduction Due to Buildup of Marine Debris in Main ICES 470071 12/8/2019 Condenser Waterbox - Diablo Canyon Unit 1 Reactor Downpowered to 48% to Repair a Condenser Tube Leak ICES 477480 1/3/2020

- Browns Ferry Unit 1 Feedwater Heater Oscillations Results in Unplanned Power ICES 473590 1/11/2020 Increase - Fermi Unit 2 Steam Generator Tube Leak Results in Manual Plant Shutdown -

ICES 475087 2/25/2020 Salem Unit 1 SG-CDMP-20-24 Revision 1 Page 38 of 48

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Westinghouse Non-Proprietary Class 3 Document Date Title Unit Downpower To Inspect Water Boxes Due to An Increase in ICES 475571 3/12/2020 Secondary Sodium Levels - North Anna Unit 1 Unit Power Reduced to Repair Steam Generator Feedpump Heat ICES 479207 4/15/2020 Exchanger - Farley Unit 2 Downpower Required to Replace Feedwater Flow Controller -

ICES 482302 5/15/2020 Beaver Valley Unit 1 Increasing Steam Generator Sodium Levels Due to Condenser ICES 480808 6/2/2020 In-Leakage - North Anna Unit 1 Power Reduction to Address Main Condenser Inleakage - Harris ICES 482395 6/5/2020 Unit 1 Main Condenser Vacuum Leak Causing Downpower - Salem ICES 484933 8/5/2020 Unit 2 Feedwater Heater Hi-level Switch Actuation Forces Unit ICES 485202 8/7/2020 Downpower - South Texas Unit 1 Power Reduction Due to Main Condenser Vacuum Degradation ICES 486384 9/3/2020

- Hatch Unit 1 Plant Shutdown to Repair Feedwater Isolation Valve Actuator ICES 486480 9/7/2020 Air Intensifier Air Leak - Summer 1 Extraction Steam Isolation Event Results in 40% Power ICES 486819 10/6/2020 Reduction - Susquehanna Unit 2 Shutdown Due to Stator Core Cooling Water Head Tank ICES 486807 10/15/2020 Hydrogen Gas Leak - Diablo Canyon Unit 2 EPRI Communications Investigation of Onset of In Plane Fluid-Elastic Instability in 30020112939 12/1/18 Two-Phase Freon Flow Approach to Assigning a Confidence Measure to SG Auto Data 3002013009 12/1/18 Analysis Results Microstructure Characterization of Alloy 600TT Steam 3002012931 12/1/18 Generator Tubing Effect of Titanium Dioxide Inhibitor for the Initiation of Lead 3002012933 10/1/18 Stress Corrosion Cracking Using Data Validation Techniques to Evaluation the impact of 3002013194 7/1/18 Chemical Addition: Effects of Polyacrylic Acid Update on Hydrazine Alternatives for PWR Secondary 3002010652 3/1/18 Chemistry Control Interim guidance Regarding Guidance Contained in the PWR SGMP-19-1 3/1/19 Steam Generator Examination Guidelines, Revision 8 2020 New Guidance SG-CDMP-20-24 Revision 1 Page 39 of 48

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Westinghouse Non-Proprietary Class 3 Document Date Title Westinghouse Communications NSAL 12-1 R1 10/1/17 Steam Generator Channel Head Degradation (Reference 5)

Steam Generator Secondary Side 2.5 Inch or Less Diameter NSAL 05-2 R1 12/1/18 Un-Reinforced Penetration Cover Plate Stress Report Error (Reference 9) 5.1 Industry Inspection Experience Review A review was performed of the SG inspection results and experiences since the completion of the 1R26 Degradation Review (Fall 2019). The focus of this review is to assess if any new or noteworthy experiences would impact the conclusions of the 1R24 DA or the OA for Cycles 25, 26, and 27. The review also focused on the experiences of plants with A690TT tubing; however, other the experiences of plants with tubing materials were considered for applicability to BVPS Unit 1.

The results of this industry experience review concluded:

• No new degradation mechanisms were reported

• The extent and sizes of existing degradation mechanisms were consistent with historical results

• All degradation reported satisfied all condition monitoring performance criteria

• Some plants with existing tube cracking mechanisms in prior outages did not report any in the current outage

• Re-inspection of historical primary channel head anomalies showed no changes or growth from prior inspections

• All experiences were consistent with the BVPS Unit 1 1R24 DA and Cycles 25/26/27 OA assumptions and conclusions The following discussions provide additional details for the more noteworthy industry SG inspection experiences since August 2016.

5.2 BVPS Unit 1 Operating Experience Review A review of the BVPS Unit 1 plant and SG operating experience was performed. This review focused on Cycle 27 plant operating and chemistry parameters and any associated transients that may have impacted SG integrity and the Cycles 25/26/27 OA conclusions.

Table 5-2 (Reference 15) describes the recent downpower events at BVPS Unit 1. These are not expected to effect SG integrity.

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Westinghouse Non-Proprietary Class 3 Table 5-2: BVPS Unit 1 Downpowers Date Description Unplanned power reduction to approximately 98% to repair a failed airline to the 11/27/19 1st Point Feedwater Heater Normal Level Control Valve.

BVPS-1 performed a small downpower to approximately 98% to repair Level 12/23/19 Control Valve [LCV-1SD-100D] on 12/23/19.

03/20/20 BVPS-1 performed an unplanned reduction to approximately 96.5% power due to high hotwell temperatures with one Cooling Tower Pump out of service for repair.

BVPS-1 reduced output to approximately 97% power for planned Turbine Valve 03/28/20 Testing.

03/29/20 BVPS-1 performed an unplanned reduction to approximately 97.5% power due to high hotwell temperatures with one Cooling Tower Pump out of service for repair.

BVPS-1 reduced output to approximately 27% power on 5/16/20 to repair the C 05/15/20 Steam Generator Feedwater Flow Control Valve.

On 7/5/20, BVPS-1 performed an unplanned power reduction from 100% power due to failure of the "A" Cooling Tower Pump and did not return to full power 07/05/20 until 7/30/20. During this period, output fluctuated between approximately 80.5%

and 91% power while maintaining maximum output based on hotwell temperature limits with one Cooling Tower pump out of service for repair.

Seasonal derate due to high hotwell temperature. Also on 8/13/20, 8/25/20 and 08/11/20 8/26/20.

10/03/20 Reduced power for planned Turbine Valve Testing.

A review of the main steam pressure trend, temperature trend, and power output trend for Cycle 27 to date was completed (Reference 10). Typical fluctuations and trends associated with reactor core burn-up tendencies over Cycle 27 were observed. Pressure, temperature, and power output trends for Cycle 27 were consistent with those reviewed in the 1R26 DR and 1R24 DA. Both the main steam pressure and SG temperature trends of Cycle 27 shows good SG operating performance, within the expected ranges assumed in the 1R24 DA and Cycles 25/26/27 OA. Further discussion on the impact to the Cycles 25/26/27 OA calculations are provided in the next section.

During Cycle 26, a condenser leak led to an EPRI Action Level 2 event. All responses and actions taken during the excursion met the time frames as required in the EPRI PWR Secondary Water Chemistry Guidelines, Revision 8, to return parameters to normal levels. In addition, there have been no other anomalies associated with the steam generators.

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Westinghouse Non-Proprietary Class 3 6.0 BVPS UNIT 1 1R24 TUBE INTEGRITY DOCUMENT REVIEW 6.1 BVPS Unit 1 1R24 Degradation Assessment Review A review of the previous BVPS Unit 1 1R24 DA was performed. The DA evaluated the SGs with respect to existing and potential degradation mechanisms to determine the inspection methods and analysis techniques necessary for the inspection. The 1R24 inspection addressed all three (3) steam generators. Based on results from the 1R24 and previous inspections at BVPS Unit 1, the existing degradation mechanisms were:

1) Wear at TSP intersections

2) Wear at AVB intersections The following were considered potential degradation mechanisms for BVPS Unit 1 as determine in the 1R24 DA:

1) Tube wear at loose parts / foreign object interaction

2) Volumetric OD indications (non-corrosion related, i.e. laps, grinder strikes, etc.)

The 1R24 DA provided for inspection programs that addressed each of the existing and potential degradation mechanisms identified above. The specific planned inspection scope for 1R24 is provided in Table 2-1. During 1R24, the SG inspections described above were completed and the only degradation mechanism reported was wear at TSP and AVB supports. No outside diameter stress corrosion cracking (ODSCC) or primary water stress corrosion cracking (PWSCC) indications were detected. Details of the 1R24 inspection are contained in Section 2.1.

As discussed in Section 5.1 and Section 5.2, there were no industry communications or industry inspection experiences that impacted the 1R24 DA or the 1R24 inspections performed.

6.2 BVPS Unit 1 1R26 Degradation Review Summary No SG inspections were conducted during the prior refueling outage and subsequently a degradation review (DR) was completed prior to 1R26. The DR evaluated the 1R24 DA, the Cycle 25 through 27 OA, and applicable industry experiences since 1R24. The degradation review was conducted to determine if there have been any significant industry events since the last BVPS 1R24 SG inspection that could invalidate the assumptions of the 1R24 DA and to confirm the applicability of the planned inspection interval until 1R27.

The major assumptions inherent to the development of the 1R24 DA and Cycle 25 through Cycle 27 OA regarding degradation performance of the SG tubing are:

• Stress corrosion cracking (SCC) mechanisms are not relevant to the BVPS Unit 1 Replacement Steam Generators (RSGs) through at least to 1R27 (Spring 2021).

• SG tube wear at anti-vibration bar intersections is not expected to exceed the Technical Specification repair limits based on these steam generators historical results and those of similar steam generators.

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Westinghouse Non-Proprietary Class 3

• SG tube wear at tube support plate (TSP) intersections are not expected to exceed the Technical Specification repair limit based on these steam generators historical results and those of similar steam generators.

• SG tube wear due to foreign object intrusion is not a systemic issue (i.e., not a function of SG design); thus, the appearance of such degradation is random and unpredictable.

Historical inspection results at BVPS Unit 1 have shown that tube degradation from foreign objects has not challenged the Technical Specification repair limit and has not limited the intended inspection interval.

The BVPS 1R24 inspection results and the Cycle 25 through Cycle 27 OA confirmed the validity of the above assumptions. Further, a number of industry experiences were reviewed with the conclusion that these industry experiences did not invalidate the assumptions of the 1R24 DA or the analyses contained with the Cycle 25 through Cycle 27 OA.

The DR also reviewed the BVPS Unit 1 Cycle 25 through 27 OA and Cycle 26 plant operations.

BVPS Unit 1 steady state steam pressure during Cycle 26 was consistent and bound by the OA assumptions for differential tube pressure. The cycle length projections for the remainder of Cycle 26 through Cycle 27 were also bound by the OA assumptions. Further, BVPS Unit 1 had not experienced any plant operating events during Cycle 26 that could have impacted the prior OA conclusions, as summarized by the following:

• No detectable primary-to-secondary leakage

• No primary side chemistry excursions (EPRI Action Level 2 or 3)

• One secondary side chemistry excursions (EPRI Action Level 2 or 3)

• EPRI Action Level 2 event occurred during Cycle 26. Correct responses and actions were taken as required.

• No known foreign material events leading to SG intrusion

• No changes in plant operating parameters affecting SG integrity

• No plant operating transients or upset conditions affecting SG integrity Therefore, the 1R26 DR concluded that the prior OA assumptions and conclusions for the planned inspection interval remained valid, and also are valid for the additional cycle until the planned 1R28 inspections.

6.3 BVPS 1R24 CM and Cycles 25/26/27 OA Review A review of the 1R24 Condition Monitoring and Cycle 25/26/27 Operational Assessment report was performed. The focus of the review is to assess the current state of the key input parameters and current plant operating conditions with regard to their impacts to the assumptions and conclusions of the Operational Assessment.

The report provided evaluations that projects the condition of all existing degradation mechanisms identified at BVPS Unit 1 in the current and previous SG inspections through to the next SG inspection at 1R27 (Spring 2021). The projected 1R27 condition for each degradation mechanism is compared to the degradation specific structural and leakage integrity performance criteria. The degradation projections used simplistic methods for the tube wear mechanisms and fully SG-CDMP-20-24 Revision 1 Page 43 of 48

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Westinghouse Non-Proprietary Class 3 probabilistic methods for the ODSCC/PWSCC mechanisms. The essential inputs and assumptions that affect the flaw projection and the calculation of the structural limits are as follows:

• Operating cycle length

• Differential pressure across the tube

• SG temperature

• Rated reactor power level

• Primary and secondary chemistry conditions

• Flaw eddy current measurement uncertainty

• OA process requirements effecting SG integrity Operating Cycle Length:

The assumed operating cycle length is a key parameter in the OA process to determine the projected flaw size at the end of the inspection interval given a flaw growth rate. Longer operating cycle lengths results in larger flaws at the end of the cycle by providing addition time for the flaw to grow. The OA assumed a combined operating duration of 4.238 EFPY for Cycles 25 through 27.

The prior OA was performed for three cycles at a length of 4.238 EFPY. The new revaluated conditions are for four cycles and an expected 5.691 EFPY. A conservative value of 6.00 EPFY will be used for all the calculations. This new cycle length is bounded by the re-evaluated operational assessment documented in this report.

Tube Differential Pressure:

The differential pressure across the tubes is a key parameter for calculating the degradation mechanism structural limits and flaw burst pressures when performing fully probabilistic methods for OA projections. Higher differential pressure across a flaw reduces the burst pressure of the tube and lowers the flaw structural limit. The tube differential pressure assumed in the OA and used to establish the degradation mechanism structural limits was 1433.3 psi. This is the conservative design differential pressure up to the maximum 10% tube plugging level. As discussed in Section 1.2, the actual SG tube differential pressure during Cycle 27 is bound by 1424 psi, which is less than the 1433.3 psi assumed in the original OA. Therefore, the original assumption of 1433.3 psi remains conservative and bounds the actual tube differential pressure.

SG Hot Leg Temperature:

SG hot leg temperature (Thot) is used in the OA process to adjust the flaw growth rates for stress corrosion cracking and other temperature related degradation mechanisms to a reference growth rate at a specific temperature. The industry default growth rate distributions contained in Reference 2 are typically used and is based on a reference temperature of 611oF. Growth rate adjustments when applied for other temperatures are performed using the Arrhenius temperature correlation. Higher temperatures result in higher crack growth rates. For BVPS Unit 1 with A690TT tubing material, there are no existing or potential degradation mechanisms that are temperature dependent that would use the Arrhenius temperature correlation. The OA for Cycles 25 through 27 was not based on temperature as an input.

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Westinghouse Non-Proprietary Class 3 Changes in SG temperature, however, can be an indicator of changing conditions within the SG that could affect the initiation or growth progression of other degradation mechanisms, such as wear from support structures. As discussed in Section 1.2, the primary hot leg temperature for Cycle 27 did not exceed 618°F for any SG and is consistent with prior cycle data. Temperature variations of each loop within a cycle are normal and related to fuel burn-up throughout the cycle.

The temperature trend does not suggest any changes in SG performance that would affect the existing and potential degradation mechanisms evaluated in the OA for Cycles 25 through 27.

Adding the additional cycle, Cycle 28, would have no bearing on this OA since there are no temperature dependent degradation mechanisms.

Rated Reactor Power:

Rated reactor power establishes key plant operating parameters such as flows, temperatures, pressures, and other system/component thermal hydraulic data. Changes in rated reactor power may result in operational changes within the SGs. As an example, when a plant undergoes a power uprate modification the changes in SG thermal hydraulic parameters can be quantified to determine the effect on tube wear at support structures. This typically results in a scaling factor to be applied to the wear growth rates. The BVPS Unit 1 rated reactor power has not changed since 2006 when the related reactor power was raised to 2900 MWt (8% uprating) and there are no plans for future plant re-ratings through to 1R28. Since there have been no changes in rated reactor power, wear growth rates are expected to be consistent from cycle to cycle. The current conditions remain within the 1R24 OA assumptions.

Operating Chemistry Programs:

The operating chemistry programs for the secondary side and primary side coolant systems can influence the SG tube susceptibility to stress corrosion cracking. The make-up and concentration of chemical additives as directed by the chemistry program can affect the electro-chemical potential (ECP) environment. Studies have shown correlations of ECP to the initiation of stress corrosion cracking in SGs with A600 tube material. Chemistry programs can also influence deposit loading and other conditions within the SGs that can influence stress corrosion cracking initiation and growth. There have been no changes or planned changes in the secondary coolant chemistry program over the evaluated OA duration. Westinghouse had performed corrosion testing of reverse U-bend samples (RUB) and concluded that pH has a relatively small effect on crack initiation times compared to other factors such as temperature, stress state, and material susceptibility. Therefore, current conditions for primary side chemistry remain with the original OA assumptions.

Flaw Eddy Current Measurement Uncertainty:

The OA process as defined in Reference 2 requires consideration of flaw measurement uncertainties The EPRI ETSSs provide the flaw measurement uncertainties in terms of a mean regression equation for systematic flaw sizing errors and a standard error to establish the uncertainty at 0.95 probability and 50% confidence. The mean regression equation and standard error are used when establishing structural limits and when establishing the starting flaw size for flaw projections for repair on sizing mechanisms. Reference 11 recommends utilizing ETSSs in effect six months prior to an inspection and implementation of new or revised ETSSs within that period is optional. A review of the ETSSs used in the BVPS 1R24 DA, the Cycle 25/26/27 OA, SG-CDMP-20-24 Revision 1 Page 45 of 48

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Westinghouse Non-Proprietary Class 3 and the calculation of the structural limits was compared to the current ETSS revision levels. A review of the ETSS revisions provides insights to future impacts when these are required to be implemented.

A review of the ETSSs referenced and used in the 1R24 DA and the Cycle 25 through 27 OA to their current revision levels showed that six ETSSs had been revised. Table 6-1 provides a summary of the ETSS revisions and their impact to the 1R24 DA and Cycle 25 through 27 OA.

All revisions to these ETSSs had either no impact or the change was conservative.

Table 6-1: Summary of ETSS Changes Since 1R24 Degradation 1R24 DA Current ETSS Mechanism Revision Revision Change Summary Change Conclusion 96910.1 AVB Wear 7 11 Updated Data Set. Tube Conservative Change.

Sizing by Integrity uncertainties Tube integrity

+POINT Probe changed. uncertainties are now smaller. Not used in CMOA.

27091.1 FO Wear 0 2 Administrative changes No Impact. Sizing Detection and changes to Data Set. uncertainties were not Impact to sizing used in DA/CMOA.

uncertainties.

I28413 Axial ODSCC 3 5 Removed graphic figure No Impact. No change to Bobbin and changed Data Set POD curve parameters.

Detection voltages.

I28425 Axial ODSCC- 3 4 Updated voltage and No Impact. No change to MRPC phase in Data Set for detection parameters.

Detection one plant.

I28431 Axial ODSCC 2 3 Updated voltage and No Impact. No change to MRPC Sizing phase in Data Set for detection or sizing one plant. parameters.

I96041.1 AVB Wear 4 6 Updated Data Set and Conservative Change.

Sizing Probe Length. Tube Tube integrity Integrity uncertainties uncertainties are now changed. smaller and bounded by prior DA/CMOA.

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Westinghouse Non-Proprietary Class 3 OA Process Requirements:

The EPRI SG Tube Integrity Guidelines (Reference 2) provides the process and methodology requirements for performing Operational Assessments. The BVPS Unit 1 Cycle 25/26/27 OA complied with all aspects of Reference 2 for the performance of the Operational Assessment. To date, there have been no revisions to Reference 2 and no interim guidance published that alters the OA methodology.

Table 6-2 compares the essential inputs and parameters that were used in the original Cycle25/26/27 OA to current conditions. The last column provides the conclusion of this comparison. These comparisons resulted in two conclusion types: bounded and no change.

A bounded conclusion means that the current parameter is bounded by the original OA assumption and the current parameter provides additional margin to the original OA results. A no change conclusions means that the current condition is the same as the original OA assumption and there is no impact from that parameter.

Table 6-2: Tube Integrity Input Parameter Review Assumed in 1R24 Cycle 25/26/27/28 Current Parameter/Assumption DA/CMOA Condition Conclusion 1.445 EFPY - Cycle 25 act.

1.397 EFPY - Cycle 26 act. Conditions 1.412 EFPY - Cycle 27 est. changed and OA Operating Duration 4.238 EFPY 1.437 EFPY - Cycle 28 est. bounded by Section 4 re-(5.691 EFPY total) analysis Tube Differential Pressure PNOP 1433.3 psi 1424 psi Bounded 3x PNOP 4300 psi 4272 psi Bounded PSLB 2560 psi 2560 psi No Change SG Hot Leg Temperature None Assumed 618o F Bounded Rated Reactor Power 2900 MWt 2900 MWt No Change 6 ETSSs have been revised No Change ETSS Versions Per 1R24 CMOA See Table 6-1 or Bounded OA Process Reference 2 Reference 2 No Change SG-CDMP-20-24 Revision 1 Page 47 of 48

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Westinghouse Non-Proprietary Class 3

7.0 REFERENCES

1. Steam Generator Program Guidelines, NEI 97-06, Revision 3, January 2011.

2. Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 4. EPRI, Palo Alto, CA: 2016. 3002007571.

3. Steam Generator Management Program: Steam Generator Degradation Specific Management Flaw Handbook, Revision 2. EPRI, Palo Alto, CA: 2016. 3002005426.

4. Steam Generator Management Program: Steam Generator in Situ Pressure Test Guidelines, Revision 5. EPRI, Palo Alto, CA: 2016. 3002007856.

5. Westinghouse Nuclear Safety Advisory Letter NSAL-12-1, Revision 1, Steam Generator Channel Head Degradation, October 2017.

6. EPRI Computer Software 3002010334, Steam Generator Management Program: Model Assisted Probability of Detection Using R (MAPOD-R), Version 2.1, 2017.

7. Westinghouse Letter LTR-CDMP-19-38, Revision 0, Software Release Letter for Single Flaw Model Version 2.4, September 2019.

8. Steam Generator Management Program: Assessment of Steam Generator Tube Plugs, Revision 0. EPRI, Palo Alto, CA: August 2013. Product ID 3002000636.

9. Westinghouse Bulletin NSAL-05-2, Revision 1, Steam Generator Secondary Side 2.5 Inch or Less Diameter Un-Reinforced Penetration Cover Plate Stress Report Error, December 2018.

10. E-mail from Timothy L. Saibena to John Carlson, RE: [External] Input Request for Beaver Valley Unit 1 Deferral OA, November 9, 2020. (Attached in EDMS)

11. Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 8. EPRI, Palo Alto, CA: 2016. 3002007572.

12. Westinghouse Document LTR-CECO-20-103, Revision 0, Evaluation of Foreign Objects in the Secondary Side of the Beaver Valley Unit 1 Steam Generators, December 2020.

13. Westinghouse Document LTR-SGMP-16-72, Revision 0, Divider Plate-to-Channelhead Weld Anomaly in Steam Generator A at Beaver Valley Power Station Unit 1, October 2016.

14. NRC Document ML12299A088, Beaver Valley Power Station, Unit No. 1 Docket No.

50334, License No. DPR-66, Technical Specification 5.6.6.1 - Steam Generator Inspection Report, October 2012.

15. E-mail from Gary D. Alberti to Logan T. Clark, RE: [External] Beaver Valley Deferral Operational Assessment, December 16, 2020. (Attached in EDMS)

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