RA-21-0027, Application to Revise Technical Specifications to Adopt TSTF-577, Revised Frequencies for Steam Generator Tube Inspections

Application to Revise Technical Specifications to Adopt TSTF-577, Revised Frequencies for Steam Generator Tube Inspections

ML21259A093
Person / Time
Site:	Mcguire, Catawba, Harris, McGuire
Issue date:	09/16/2021
From:	Gibby S Duke Energy Carolinas, Duke Energy Progress
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RA-21-0027
Download: ML21259A093 (42)

Text

Shawn K. Gibby Vice President Nuclear Engineering 526 South Church Street, EC-07H Charlotte, NC 28202 704-519-5138 Shawn.Gibby@duke-energy.com 10 CFR 50.90 Serial: RA-21-0027 September 16, 2021 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 CATAWBA NUCLEAR STATION, UNITS 1 AND 2 DOCKET NOS. 50-413 AND 50-414 / RENEWED LICENSE NOS. NPF-35 AND NPF-52 MCGUIRE NUCLEAR STATION, UNITS 1 AND 2 DOCKET NOS. 50-369 AND 50-370 / RENEWED LICENSE NOS. NPF-9 AND NPF-17 SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 DOCKET NO. 50-400 / RENEWED LICENSE NO. NPF-63

SUBJECT:

Application to Revise Technical Specifications to Adopt TSTF-577, Revised Frequencies for Steam Generator Tube Inspections Pursuant to 10 CFR 50.90, Duke Energy Carolinas, LLC, and Duke Energy Progress, LLC, collectively referred to henceforth as Duke Energy, is submitting a request for an amendment to the Technical Specifications (TS) for Catawba Nuclear Station, Units 1 and 2 (CNS), McGuire Nuclear Station, Units 1 and 2 (MNS), and Shearon Harris Nuclear Power Plant, Unit 1 (HNP).

Duke Energy requests adoption of TSTF-577, Revised Frequencies for Steam Generator Tube Inspections, which is an approved change to the Standard Technical Specifications (STS), into the CNS, MNS, and HNP TS. The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history.

The enclosure provides a description and assessment of the proposed changes. Attachment 1 provides the existing TS pages marked to show the proposed changes. Attachment 2 provides revised (clean) TS pages. The TS Bases are not affected by the proposed changes.

Duke Energy requests that the proposed amendment be reviewed under the Consolidated Line Item Improvement Process (CLIIP). Approval of the proposed amendment is requested within 6 months of completion of the NRCs acceptance review. Once approved, the amendment shall be implemented within 120 days.

There are no regulatory commitments made in this submittal.

In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated North Carolina and South Carolina Officials.

( ~ DUKE ENERGY

U.S. Nuclear Regulatory Commission RA-21-0027 Page 2 If you should have any questions regarding this submittal, or require additional information, please contact Art Zaremba, Manager - Nuclear Fleet Licensing, at 980-373-2062.

I declare under penalty of perjury that the foregoing is true and correct. Executed on September 16, 2021.

Sincerely, Shawn K. Gibby Vice President - Nuclear Engineering JLV

Enclosure:

Description and Assessment Attachments: 1. Proposed Technical Specification Changes (Mark-up)

2. Revised Technical Specification Pages cc (with enclosure/attachments):

L. Dudes, USNRC Region II - Regional Administrator V. Cusumano, USNRC - Chief, TS Branch J. D. Austin, USNRC Senior Resident Inspector - CNS G. A. Hutto, USNRC Senior Resident Inspector - MNS J. Zeiler, USNRC Senior Resident Inspector - HNP A. Hon, NRR Project Manager - Fleet S. Jenkins, Chief, Bureau of Radiological Health (S.C.)

W. L. Cox, III, Section Chief N.C. DHSR L. Garner, Manager, S.C. DHEC

U.S. Nuclear Regulatory Commission RA-21-0027 Page 1 ENCLOSURE DESCRIPTION AND ASSESSMENT

1.

DESCRIPTION Duke Energy Carolinas, LLC, and Duke Energy Progress, LLC, collectively referred to henceforth as Duke Energy, requests adoption of TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections," which is an approved change to the Standard Technical Specifications (STS), into the Catawba Nuclear Station, Units 1 and 2 (CNS), McGuire Nuclear Station, Units 1 and 2 (MNS), and Shearon Harris Nuclear Power Plant, Unit 1 (HNP) Technical Specifications (TS). The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history.

2.

ASSESSMENT 2.1 Applicability of Safety Evaluation Duke Energy has reviewed the safety evaluation for TSTF-577 provided to the Technical Specifications Task Force in a letter dated April 14, 2021. This review included a review of the NRC staffs evaluation, as well as the information provided in TSTF-577. As described herein, Duke Energy has concluded that the justifications presented in TSTF-577 and the safety evaluation prepared by the NRC staff are applicable to CNS, MNS, and HNP and justify this amendment for the incorporation of the changes to the CNS, MNS and HNP TS.

The current SG TS requirements for CNS, MNS and HNP are based on TSTF-510, "Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection." Both CNS and MNS have two units, while HNP is a single unit site. The SGs for CNS Unit 1, MNS Units 1 and 2, and HNP Unit 1 have Alloy 690 thermally treated (Alloy 690TT) tubes. The CNS Unit 2 SGs have Alloy 600 thermally treated (Alloy 600TT) tubes.

For CNS Unit 2, the initial inspection period described in the SG Program, paragraph d.3, began May 3, 2021. Duke Energy will submit a SG Tube Inspection Report for CNS Unit 2 meeting the revised TS 5.6.8 requirements within 30 days after implementation of the license amendment.

For HNP, the initial inspection period described in the SG Program, paragraph 4.b, began November 17, 2019. Duke Energy will submit a SG Tube Inspection Report for HNP meeting the revised TS 6.9.1.7 requirements within 30 days after implementation of the license amendment.

2.2 Variations Duke Energy is proposing the following variations from the TS changes described in TSTF-577 or the applicable parts of the NRC staffs safety evaluation:

1. The CNS, MNS, and HNP TS utilize different numbering than the STS on which TSTF-577 was based. Specifically, the numbering differences are:

U.S. Nuclear Regulatory Commission RA-21-0027 Page 2 TSTF-577, Rev. 1 Westinghouse Owner's Group (WOG) STS Corresponding CNS TS Corresponding MNS TS Corresponding HNP TS 5.5.9, "Steam Generator (SG)

Program" No difference No difference 6.8.4.l 5.6.7, "Steam Generator Tube Inspection Report" 5.6.8 5.6.8 6.9.1.7 These differences are administrative and do not affect the applicability of TSTF-577 to the CNS, MNS, and HNP TS.

2. The WOG STS markups in TSTF-577 apply to CNS. Note that CNS Unit 1 has a different SG design than CNS Unit 2. Therefore, the current CNS TS 5.5.9 includes requirements specific to Unit 1 and requirements specific to Unit 2. The proposed TS markups for CNS incorporate the intent of the TSTF-577 changes, while retaining the unit-specific formatting of the existing CNS TS. These are administrative changes.

The CNS SG Program TS currently contains a provision for an alternate tube plugging criteria.

The description of the alternate tube plugging criteria in the proposed change is equivalent to the descriptions in the current CNS TS.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Analysis Duke Energy Carolinas, LLC, and Duke Energy Progress, LLC, collectively referred to henceforth as Duke Energy, requests adoption of TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections," which is an approved change to the Standard Technical Specifications (STS), into the Catawba Nuclear Station, Units 1 and 2 (CNS), McGuire Nuclear Station, Units 1 and 2 (MNS), and Shearon Harris Nuclear Power Plant, Unit 1 (HNP) Technical Specifications (TS). The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history.

Duke Energy has evaluated if a significant hazards consideration is involved with the proposed amendment(s) 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 revises the inspection frequencies for SG tube inspections and associated reporting requirements. The SG inspections are conducted as part of the SG Program to ensure and demonstrate that performance criteria for tube structural integrity and accident leakage integrity are met. These performance criteria are consistent with the plant design and licensing basis. With the proposed changes to the inspection frequencies, the SG Program must still demonstrate that the performance criteria are met. As a result, the probability of any accident previously evaluated is not significantly increased and the consequences of any accident previously evaluated are not significantly increased.

U.S. Nuclear Regulatory Commission RA-21-0027 Page 3 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 revises the inspection frequencies for SG tube inspections and associated reporting requirements. The proposed change does not alter the design function or operation of the SGs or the ability of an SG to perform the design function.

The SG tubes continue to be required to meet the SG Program performance criteria.

The proposed change does not create the possibility of a new or different kind of accident due to credible new failure mechanisms, malfunctions, or accident initiators that are not considered in the design and licensing bases.

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

3.

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

Response: No The proposed change revises the inspection frequencies for SG tube inspections and associated reporting requirements. The proposed change does not change any of the controlling values of parameters used to avoid exceeding regulatory or licensing limits.

The proposed change does not affect a design basis or safety limit, or any controlling value for a parameter established in the UFSAR or the license.

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

Based on the above, Duke Energy concludes that the proposed change presents no 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.

3.2 Conclusion 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.

U.S. Nuclear Regulatory Commission RA-21-0027 Page 4

4.0 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 a 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.

RA-21-0027 ATTACHMENT 1 PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UP)

[1 pages follow this cover page]

9

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-6 Amendment Nos. 299/295 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Program (Deleted)

Note: See Section 1.1 for the definition of INSERVICE TESTING PROGRAM.

5.5.9 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following:

a.

Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the (continued)

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-7 Amendment Nos. 280/276 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

b.

Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1.

Structural integrity performance criterion: All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown), 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 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.

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 not to exceed 150 gallons per day through each SG for a total of 600 gallons per day through all SGs.

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.

(continued)

No proposed changes on this page. Provided for information only.

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-8 Amendment Nos. 280/276 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

The following SG tube alternate plugging criteria shall be applied as an alternative to the 40% depth based criteria:

1.

For Unit 2 only, tubes with service-induced flaws located greater than 14.01 inches below the top of the tubesheet do not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 14.01 inches below the top of the tubesheet shall be plugged upon detection.

d.

Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. For Unit 1, the number and portions of the tubes inspected and method of inspection shall be performed with the objective of detecting flaws of any type (for example, 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. For Unit 2, the number and portions of the tubes inspected and method of inspection shall be performed with the objective of detecting flaws of any type (for example, volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from 14.01 inches below the top of the tubesheet on the hot leg side to 14.01 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube plugging criteria. In addition to meeting requirements d.1, d.2, d.3, and d.4 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.

(continued)

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-9 Amendment Nos. 280/276 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 1.

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

2.

For Unit 1, after the first refueling outage following SG installation, inspect each SG at least every 72 effective full power months (EFPM) 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 of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a)

After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months. This constitutes the first inspection period; b)

During the next 120 effective full power months, inspect 100% of the tubes. This constitutes the second inspection period; c)

During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the third inspection period; and d)

During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the fourth and subsequent inspection periods.

(continued)

CNS INSERT2

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-10 Amendment Nos. 280/276 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 3.

For Unit 2, after the first refueling outage following SG installation, inspect each SG at least every 48 effective full power months or at least every other 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, and c 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 of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a)

After the first refueling outage following SG installation, inspect 100% of the tubes during the next 120 effective full power months. This constitutes the first inspection period; b)

During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the second inspection period; and c)

During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the third and subsequent inspection periods 4.

For Unit 1, if crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 EFPM or one refueling outage (whichever results in more frequent inspections). For Unit 2, if crack indications are found in any SG tube from 14.01 inches below the top of the (continued)

CNS INSERT 3 be at the next ICNS INSERT 4 I

Programs and Manuals 5.5 (continued)

Catawba Units 1 and 2 5.5-11 Amendment Nos. 280/276 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) tubesheet on the hot leg side to 14.01 inches below the top of the tubesheet on the cold leg side, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 EFPM or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

be at the next CNS INSERT 5

Reporting Requirements 5.6 Catawba Units 1 and 2 5.6-6 Amendment Nos. 280/276 5.6 Reporting Requirements (continued) 5.6.8 Steam Generator (SG) Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of the inspection. The report shall include:

a.

The scope of inspections performed on each SG, b.

Degradation mechanisms found, c.

Non-destructive examination techniques utilized for each degradation mechanism, d.

Location, orientation (if linear), and measured sizes (if available) of service induced indications, e.

Number of tubes plugged during the inspection outage for each degradation mechanism, f.

The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator, g.

The results of condition monitoring, including the results of tube pulls and in-situ testing, h.

For Unit 2, the primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report, i.

For Unit 2, the calculated accident leakage rate from the portion of the tubes below 14.01 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident leakage rate from the most limiting accident is less than 3.27 times the maximum primary to secondary LEAKAGE rate, the report shall describe how it was determined, and j.

For Unit 2, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

Replace all struck-through text with CNS INSERT 6

Technical Specifications INSERTS for Catawba Nuclear Station (CNS)

CNS INSERT 1 from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet except for any portions of the tube that are exempt from inspection by alternate repair criteria CNS INSERT 2 For Unit 1, after the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period.

CNS INSERT 3 For Unit 2, after the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 54 effective full power months, which defines the inspection period. If none of the SG tubes have ever experienced cracking other than in regions that are exempt from inspection by alternate repair criteria and the SG inspection was performed with enhanced probes, the inspection period may be extended to 72 effective full power months. Enhanced probes have a capability to detect flaws of any type equivalent to or better than array probe technology. The enhanced probes shall be used from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet except any portions of the tube that are exempt from inspection by alternate repair criteria. If there are regions where enhanced probes cannot be used, the tube inspection techniques shall be capable of detecting all forms of existing and potential degradation in that region.

CNS INSERT 4 excluding any region that is exempt from inspection by alternate repair criteria CNS INSERT 5

, but may be deferred to the following refueling outage if the 100% inspection of all SGs was performed with enhanced probes as described in paragraph d.3 CNS INSERT 6

a. The scope of inspections performed on each SG;

b. The nondestructive examination techniques utilized for tubes with increased degradation susceptibility;

c. For each degradation mechanism found:

1. The nondestructive examination techniques utilized;

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

3.

A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment; and

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

d. An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results;

e. The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG;

f.

The results of any SG secondary side inspections;

g. For Unit 2, the primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report;

h. For Unit 2, the calculated accident leakage rate from the portion of the tubes below 14.01 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident leakage rate from the most limiting accident is less than 3.27 times the maximum primary to secondary LEAKAGE rate, the report shall describe how it was determined; and

i.

For Unit 2, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

(continued)

McGuire Units 1 and 2 5.5-6 Amendment Nos. 309/288 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Program (Deleted)

Note: See Section 1.1 for the definition of INSERVICE TESTING PROGRAM.

5.5.9 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following:

a.

Provisions for condition monitoring assessments. Condition monitoring assessment performance criteria for structural integrity and acci condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

~

~----~----

means an evaluation of the "as found" condition of the tubing with respect to the dent induced leakage. The "as found"

(continued)

McGuire Units 1 and 2 5.5-7 Amendment No. 284/263 5.5 Programs and Manuals (continued) 5.5.9 Steam Generator (SG) Program (continued) b.

Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1.

Structural integrity performance criterion: 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 cool down), 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 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.

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 not to exceed 0.27 gallons per minute total.

3.

The operational LEAKAGE performance cri 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.

terion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

(continued)

McGuire Units 1 and 2 5.5-8 Amendment No. 284/263 5.5 Programs and Manuals (continued) 5.5.9 Steam Generator (SG) Program (continued) 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 of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a.

After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months. This constitutes the first inspection period; b.

During the next 120 effective full power months, inspect 100% of the tubes.

This constitutes the second inspections period; c.

During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the third inspection period; and d.

During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the fourth and subsequent inspection periods.

3.

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

MNS INSERT 1 lbe at the next ~

Reporting Requirements 5.6 (continued)

McGuire Units 1 and 2 5.6-5 Amendment Nos. 284/263 5.6 Reporting Requirements 5.6.8 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:

a.

The scope of inspections performed on each SG,

b.

Degradation mechanisms found,

c.

Nondestructive examination techniques utilized for each degradation mechanism,

d.

Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e.

Number of tubes plugged during the inspection outage for each degradation mechanism,

f.

The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator, and

g.

The results of condition monitoring, including the results of tube pulls and in-situ testing.

Replace all struck-through text with MNS INSERT 2

Technical Specifications INSERTS for McGuire Nuclear Station (MNS)

MNS INSERT 1 After the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period.

MNS INSERT 2

a. The scope of inspections performed on each SG;

b. The nondestructive examination techniques utilized for tubes with increased degradation susceptibility;

c. For each degradation mechanism found:

1. The nondestructive examination techniques utilized;

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

3. A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment; and

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

d. An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results;

e. The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG; and

f.

The results of any SG secondary side inspections.

SHEARON HARRIS - UNIT 1 6-19d Amendment No. 145 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

l.

Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that steam generator (SG) tube integrity is maintained. In addition, the Steam Generator Program shall include the following:

1.

Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

2.

Performance criteria for SG tube integrity. Steam generator tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational leakage.

a)

Structural integrity performance criterion. All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, HOT STANDBY, and cooldown), all anticipated transients included in the design specification, and design basis accidents. This includes retaining a safety factor of 3.0 (3deltaP) 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 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.

b)

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. Accident induced leakage is not to exceed 1 gpm total for all three SGs.

c)

The operation leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System Operational Leakage."

~--

SHEARON HARRIS - UNIT 1 6-19e Amendment No. 145 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

3.

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

4.

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 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 4a, 4b, and 4c 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.

a)

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

b)

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 1), 2), 3), and 4) 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 of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

1) After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months.

This constitutes the first inspection period;

2) During the next 120 effective full power months, inspect 100% of the tubes. This constitutes the second inspection period;

3) During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the third inspection period; and HNP INSERT 1

SHEARON HARRIS - UNIT 1 6-19f Amendment No. 145 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

4) During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the fourth and subsequent inspection periods.

c)

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

5.

Provisions for monitoring operational primary-to-secondary leakage.

be at the next

(PAGES 6-24b THROUGH 6-24d DELETED By Amendment No. 185)

(PAGE 6-25 DELETED By Amendment No.92)

SHEARON HARRIS - UNIT 1 6-24a Amendment No. 185 ADMINISTRATIVE CONTROLS 6.9.1.6 CORE OPERATING LIMITS REPORT (Continued) ved by NRC Safety Evaluation dated May 18, 2017.

by NRC Safety Evaluation dated May 18, 2017.

May 18, 2017.

approved by NRC Safety Evaluation dated April 10, 2018.

6.9.1.6.3 The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, nuclear limits such as shutdown margin, and transient and accident analysis limits) of the safety analysis are met.

6.9.1.6.4 The CORE OPERATING LIMITS REPORT, including any mid-cycle revisions or supplements, shall be provided, upon issuance for each reload cycle, to the NRC Document Control Desk, with copies to the Regional Administrator and Resident Inspector.

6.9.1.7 STEAM GENERATOR TUBE INSPECTION REPORT A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with Specification 6.8.4.l. The report shall include:

a.

The scope of inspections performed on each SG,

b.

Degradation mechanisms found,

c.

Nondestructive examination techniques utilized for each degradation mechanism,

d.

Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e.

Number of tubes plugged during the inspection outage for each degradation mechanism,

f.

The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator, and

g.

The results of condition monitoring, including the results of tube pulls and in-situ testing.

SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the NRC in accordance with 10 CFR 50.4 within the time period specified for each report.

6.10 DELETED Replace all struck-through text with HNP INSERT 2

h.

DPC-NE-1008-P-A, "Nuclear Design Methodology Using CASMO-5/SIMULATE-3 for Westinghouse Reactors," as appro

i.

DPC-NF-2010-A, "Nuclear Physics Methodology for Reload Design," as approved

j.

DPC-NE-2011-P-A, "Nuclear Design Methodology Report for Core Operating Limits of Westinghouse Reactors" as approved by NRC Safety Evaluation dated

k.

DPC-NE-3008-P-A, "Thermal-Hydraulic Models for Transient Analysis," as I.

DPC-NE-3009-P-A, "FSAR / UFSAR Chapter 15 Transient Analysis Methodology," as approved by NRC Safety Evaluation dated April 10, 2018.

m.

ANP-10341P-A, "The ORFEO-GAIA and ORFEO-NMGRID Critical Heat Flux Correlations," approved version as specified in the COLR.

Technical Specifications INSERTS for Shearon Harris Nuclear Power Plant (HNP)

HNP INSERT 1 After the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period.

HNP INSERT 2

a. The scope of inspections performed on each SG;

b. The nondestructive examination techniques utilized for tubes with increased degradation susceptibility;

c. For each degradation mechanism found:

1. The nondestructive examination techniques utilized;

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

3. A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment; and

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

d. An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results;

e. The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG; and

f.

The results of any SG secondary side inspections.

RA-21-0027 ATTACHMENT 2 REVISED TECHNICAL SPECIFICATION PAGES

[15 pages follow this cover page]

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-6 Amendment Nos. XXX/YYY 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Program (Deleted)

Note: See Section 1.1 for the definition of INSERVICE TESTING PROGRAM.

5.5.9 Steam Generator (SG) Program An SG Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the SG Program shall include the following:

a.

Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the (continued)

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-8 Amendment Nos. XXX/YYY 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

The following SG tube alternate plugging criteria shall be applied as an alternative to the 40% depth based criteria:

1.

For Unit 2 only, tubes with service-induced flaws located greater than 14.01 inches below the top of the tubesheet do not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 14.01 inches below the top of the tubesheet shall be plugged upon detection.

d.

Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. For Unit 1, the number and portions of the tubes inspected and method of inspection shall be performed with the objective of detecting flaws of any type (for example, 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. For Unit 2, the number and portions of the tubes inspected and method of inspection shall be performed with the objective of detecting flaws of any type (for example, 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 except for any portions of the tube that are exempt from inspection by alternate repair criteria, and that may satisfy the applicable tube plugging criteria.

In addition to meeting requirements d.1, d.2, d.3, and d.4 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.

(continued)

Programs and Manuals 5.5 (continued)

Catawba Units 1 and 2 5.5-9 Amendment Nos. XXX/YYY 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

1.

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

2.

For Unit 1, after the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period.

3.

For Unit 2, after the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 54 effective full power months, which defines the inspection period. If none of the SG tubes have ever experienced cracking other than in regions that are exempt from inspection by alternate repair criteria and the SG inspection was performed with enhanced probes, the inspection period may be extended to 72 effective full power months. Enhanced probes have a capability to detect flaws of any type equivalent to or better than array probe technology. The enhanced probes shall be used from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet except any portions of the tube that are exempt from inspection by alternate repair criteria. If there are regions where enhanced probes cannot be used, the tube inspection techniques shall be capable of detecting all forms of existing and potential degradation in that region.

4.

For Unit 1, if crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall be at the next refueling outage. For Unit 2, if crack indications are found in any SG tube excluding any region that is exempt from inspection by alternate repair criteria, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall be at the next refueling outage, but may be deferred to the following refueling outage if the 100% inspection of all SGs was performed with enhanced probes as described in paragraph d.3. If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-10 Amendment Nos. XXX/YYY Page 5.5-10 has been deleted by Amendment Nos. XXX/YYY

Programs and Manuals 5.5 Catawba Units 1 and 2 5.5-11 Amendment Nos. XXX/YYY Page 5.5-11 has been deleted by Amendment Nos. XXX/YYY

Reporting Requirements 5.6 (continued)

Catawba Units 1 and 2 5.6-6 Amendment Nos. XXX/YYY 5.6 Reporting Requirements (continued) 5.6.8 Steam Generator (SG) Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of the inspection. The report shall include:

a.

The scope of inspections performed on each SG;

b.

The nondestructive examination techniques utilized for tubes with increased degradation susceptibility;

c.

For each degradation mechanism found:

1. The nondestructive examination techniques utilized;

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

3. A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment; and

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

d.

An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results;

e.

The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG;

f.

The results of any SG secondary side inspections;

g.

For Unit 2, the primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report;

Reporting Requirements 5.6 Catawba Units 1 and 2 5.6-7 Amendment Nos. XXX/YYY 5.6 Reporting Requirements 5.6.8 Steam Generator (SG) Tube Inspection Report (continued)

h.

For Unit 2, the calculated accident leakage rate from the portion of the tubes below 14.01 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident leakage rate from the most limiting accident is less than 3.27 times the maximum primary to secondary LEAKAGE rate, the report shall describe how it was determined; and

i.

For Unit 2, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

(continued)

McGuire Units 1 and 2 5.5-6 Amendment No. XXX/YYY 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Program (Deleted)

Note: See Section 1.1 for the definition of INSERVICE TESTING PROGRAM.

5.5.9 Steam Generator (SG) Program An SG Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the SG Program shall include the following:

a.

Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the as found condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The as found condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

(continued)

McGuire Units 1 and 2 5.5-7 Amendment No. XXX/YYY 5.5 Programs and Manuals (continued) 5.5.9 Steam Generator (SG) Program (continued)

b.

Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1.

Structural integrity performance criterion: All in-service SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down), 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 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.

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 not to exceed 0.27 gallons per minute total.

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.

(continued)

McGuire Units 1 and 2 5.5-8 Amendment No. XXX/YYY 5.5 Programs and Manuals (continued) 5.5.9 Steam Generator (SG) Program (continued)

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 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period.

3.

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall be at the next refueling outage. If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

Reporting Requirements 5.6 (continued)

McGuire Units 1 and 2 5.6-5 Amendment Nos. XXX/YYY 5.6 Reporting Requirements 5.6.8 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:

a.

The scope of inspections performed on each SG;

b.

The nondestructive examination techniques utilized for tubes with increased degradation susceptibility;

c.

For each degradation mechanism found:

1. The nondestructive examination techniques utilized;

2. The location, orientation (if linear), measured size (if available),

and voltage response for each indication. For tube wear at support structures less than 20 percent through-wall, only the total number of indications needs to be reported;

3. A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment; and

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

d.

An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results;

e.

The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG; and

f.

The results of any SG secondary side inspections.

SHEARON HARRIS - UNIT 1 6-19d Amendment No.

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

l.

Steam Generator (SG) Program An SG Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the SG Program shall include the following:

1.

Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

2.

Performance criteria for SG tube integrity. Steam generator tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational leakage.

a)

Structural integrity performance criterion. All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, HOT STANDBY, and cooldown), all anticipated transients included in the design specification, and design basis accidents. This includes retaining a safety factor of 3.0 (3deltaP) 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 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.

b)

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. Accident induced leakage is not to exceed 1 gpm total for all three SGs.

c)

The operation leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System Operational Leakage."

(PAGE 6-19f DELETED By Amendment No. )

SHEARON HARRIS - UNIT 1 6-19e Amendment No.

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

3.

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

4.

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 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 4a, 4b, and 4c 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.

a)

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

b)

After the first refueling outage following SG installation, inspect 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period.

c)

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall be at the next refueling outage. If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

5.

Provisions for monitoring operational primary-to-secondary leakage.

SHEARON HARRIS - UNIT 1 6-24a Amendment No.

ADMINISTRATIVE CONTROLS 6.9.1.6 CORE OPERATING LIMITS REPORT (Continued)

h.

DPC-NE-1008-P-A, Nuclear Design Methodology Using CASMO-5/SIMULATE-3 for Westinghouse Reactors, as approved by NRC Safety Evaluation dated May 18, 2017.

i.

DPC-NF-2010-A, Nuclear Physics Methodology for Reload Design, as approved by NRC Safety Evaluation dated May 18, 2017.

j.

DPC-NE-2011-P-A, Nuclear Design Methodology Report for Core Operating Limits of Westinghouse Reactors as approved by NRC Safety Evaluation dated May 18, 2017.

k.

DPC-NE-3008-P-A, Thermal-Hydraulic Models for Transient Analysis, as approved by NRC Safety Evaluation dated April 10, 2018.

l.

DPC-NE-3009-P-A, FSAR / UFSAR Chapter 15 Transient Analysis Methodology, as approved by NRC Safety Evaluation dated April 10, 2018.

m.

ANP-10341P-A, The ORFEO-GAIA and ORFEO-NMGRID Critical Heat Flux Correlations, approved version as specified in the COLR.

6.9.1.6.3 The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, nuclear limits such as shutdown margin, and transient and accident analysis limits) of the safety analysis are met.

6.9.1.6.4 The CORE OPERATING LIMITS REPORT, including any mid-cycle revisions or supplements, shall be provided, upon issuance for each reload cycle, to the NRC Document Control Desk, with copies to the Regional Administrator and Resident Inspector.

6.9.1.7 STEAM GENERATOR TUBE INSPECTION REPORT A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with Specification 6.8.4.l. The report shall include:

a.

The scope of inspections performed on each SG;

b.

The nondestructive examination techniques utilized for tubes with increased degradation susceptibility;

c.

For each degradation mechanism found:

1.

The nondestructive examination techniques utilized;

2.

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

3.

A description of the condition monitoring assessment and results, including the margin to the tube integrity performance criteria and comparison with the margin predicted to exist at the inspection by the previous forward-looking tube integrity assessment; and

4.

The number of tubes plugged during the inspection outage.

(PAGES 6-24c THROUGH 6-24d DELETED By Amendment No. 185)

(PAGE 6-25 DELETED By Amendment No.92)

SHEARON HARRIS - UNIT 1 6-24b Amendment No.

ADMINISTRATIVE CONTROLS 6.9.1.7 STEAM GENERATOR TUBE INSPECTION REPORT (Continued)

d.

An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (the forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results;

e.

The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG; and

f.

The results of any SG secondary side inspections.

SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the NRC in accordance with 10 CFR 50.4 within the time period specified for each report.

6.10 DELETED