RS-22-086, R. E. Ginna Nuclear Power Plant - Application to Revise Technical Specifications to Adopt TSTF-577, Revised Frequencies for Steam.

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R. E. Ginna Nuclear Power Plant - Application to Revise Technical Specifications to Adopt TSTF-577, Revised Frequencies for Steam.
ML22222A068
Person / Time
Site: Calvert Cliffs, Byron, Braidwood, Ginna  Constellation icon.png
Issue date: 08/10/2022
From: Lueshen K
Constellation Energy Generation
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-22-086
Download: ML22222A068 (117)
v • d • e


Text

4300 Winfield Road Warrenville, IL 60555 630 657 2000 Office RS-22-086 10 CFR 50.90 August 10, 2022 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Braidwood Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455 Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Renewed Facility Operating License Nos. DPR-53 and DPR-69 NRC Docket Nos. 50-317 and 50-318 R.E. Ginna Nuclear Power Plant Renewed Facility Operating License No. DPR-18 NRC Docket No. 50-244

Subject:

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Constellation Energy Generation, LLC (CEG) is submitting a request for amendments to the Technical Specifications (TS) for Braidwood Station, Units 1 and 2 (Braidwood); Byron Station, Units 1 and 2 (Byron); Calvert Cliffs Nuclear Power Plant, Units 1 and 2 (Calvert Cliffs); and R.E. Ginna Nuclear Power Plant (Ginna).

CEG 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 Braidwood, Byron, Calvert Cliffs, and Ginna 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. Attachments 1a through 1d provide the existing TS pages marked to show the proposed changes.

Attachments 2a through 2d provide revised (clean) TS pages. Attachment 3 provides the existing TS Bases pages for Ginna marked to show revised text associated with the proposed TS changes and is provided for information only. The TS Bases for Braidwood, Byron, and Calvert Cliffs are not affected by the proposed changes.

August 10, 2022 U.S. Nuclear Regulatory Commission Page 2 CEG 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 NRC's acceptance review. Once approved, the amendment shall be implemented within 120 days.

The proposed changes have been reviewed by the Plant Operations Review Committees at Braidwood, Byron, Calvert Cliffs, and Ginna in accordance with the requirements of the CEG Quality Assurance Program.

There are no regulatory commitments made in this submittal. New license conditions for Braidwood, Units 1 and 2, Calvert Cliffs, Units 1 and 2, and Ginna are provided in Attachments 4a through 4c.

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation," paragraph (b),

a copy of this application, with attachments, is being provided to the designated Illinois, Maryland, and New York Officials.

If you should have any questions regarding this letter, please contact Ms. Lisa Simpson at (630) 657-2815.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 10th day of August 2022.

Respectfully, Lueshen, Digitally signed by Lueshen, Kevin Kevin Date: 2022.08.10 08:39:18 -05'00' Kevin Lueshen Sr. Manager - Licensing Constellation Energy Generation, LLC

Enclosure:

Description and Assessment

August 10, 2022 U.S. Nuclear Regulatory Commission Page 2 Attachments:

1a) Braidwood Station, Units 1 and 2, Proposed Technical Specifications Changes (Mark-up) 1b) Byron Station, Units 1 and 2, Proposed Technical Specifications Changes (Mark-up) 1c) Calvert Cliffs Nuclear Power Plant, Units 1 and 2, Proposed Technical Specifications Changes (Mark-Up) 1d) R.E. Ginna Nuclear Power Plant Proposed Technical Specifications Changes (Mark-Up) 2a) Braidwood Station, Units 1 and 2, Revised Technical Specifications Changes 2b) Byron Station, Units 1 and 2, Revised Technical Specifications Changes 2c) Calvert Cliffs Nuclear Power Plant, Units 1 and 2, Revised Technical Specifications Changes 2d) R.E. Ginna Nuclear Power Plant Revised Technical Specifications Changes

3) R.E. Ginna Nuclear Power Plant Proposed Technical Specifications Bases Changes (Mark-up) - (Provided for Information Only) 4a) Braidwood Station, Units 1 and 2, Proposed Renewed Facility Operating License Changes (Mark-up) 4b) Calvert Cliffs Nuclear Power Plant, Units 1 and 2, Proposed Renewed Facility Operating License Changes (Mark-up) 4c) R.E. Ginna Nuclear Power Plant Proposed Renewed Facility Operating License Changes (Mark-up) cc: NRC Project Manager - NRR - Braidwood / Byron NRC Project Manager - NRR - Calvert Cliffs NRC Project Manager - NRR - Ginna NRC Regional Administrator, Region I NRC Regional Administrator, Region III NRC Senior Resident Inspector, Braidwood Station NRC Senior Resident Inspector, Byron Station NRC Senior Resident Inspector, Calvert Cliffs NRC Senior Resident Inspector, Ginna Illinois Emergency Management Agency - Division of Nuclear Safety A. L. Peterson, NYSERDA S. Seaman, State of Maryland

Enclosure Description and Assessment

1.0 DESCRIPTION

Constellation Energy Generation, LLC (CEG) 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 Technical Specifications (TS) for Braidwood Station, Units 1 and 2 (Braidwood); Byron Station, Units 1 and 2 (Byron); Calvert Cliffs Nuclear Power Plant, Units 1 and 2 (Calvert Cliffs); and R.E. Ginna Nuclear Power Plant (Ginna). The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history.

2.0 ASSESSMENT 2.1 Applicability of Safety Evaluation CEG 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 staff's evaluation, as well as the information provided in TSTF-577. CEG has concluded that the justifications presented in TSTF-577 and the safety evaluation prepared by the NRC staff are applicable to Braidwood, Byron, Calvert Cliffs, and Ginna and justify this amendment for the incorporation of the changes to the Braidwood, Byron, Calvert Cliffs, and Ginna TS.

The current SG TS requirements for Braidwood, Byron, and Calvert Cliffs are based on TSTF-510, "Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection." The current SG TS requirements for Ginna are based on TSTF-449, "Steam Generator Tube Integrity." Braidwood, Byron, and Calvert Cliffs all have two units, while Ginna is a single unit site. The SGs for Braidwood Unit 1, Byron Unit 1, Ginna, and Calvert Cliffs, Units 1 and 2, have Alloy 690 thermally treated (Alloy 690TT) tubes. The SGs for Braidwood Unit 2 and Byron Unit 2 have Alloy 600 thermally treated (Alloy 600TT) tubes.

The initial inspection period described in the SG Program, paragraph d.2, began March 11, 2020, for Byron, Unit 1, and the initial inspection period described in the SG Program, paragraph d.3, began April 18, 2022, for Byron, Unit 2. CEG will submit SG Tube Inspection Reports meeting the revised TS 5.6.9 requirements within 30 days after implementation of the license amendment at Byron.

Once the amendments for Braidwood, Units 1 and 2, Calvert Cliffs, Units 1 and 2, and Ginna are approved, the TS will be implemented within 120 days. As use of the revised inspection period in TSTF-577 is contingent on the performance of a 100% inspection of all steam generator tubes in a single outage, new license conditions for Braidwood, Units 1 and 2, Calvert Cliffs, Units 1 and 2, and Ginna are provided in Attachments 4a through 4c, which will not permit the extended inspection interval of the TS Steam Generator Program following implementation until after performance of 100% inspection of all tubes in a single outage. CEG will submit SG Tube Inspection Reports within 180 days of performance of a 100% inspection of all steam generator tubes in a single outage for Braidwood, Units 1 and 2, Calvert Cliffs, Units 1 and 2, and Ginna in accordance with the requirements of TS 5.6.9, "Steam Generator Tube Inspection Report" [TS 5.6.7 for Ginna].

Page 1 of 6

Enclosure Description and Assessment CEG plans to inspect 100% of the SG tubes in Braidwood, Unit 1, during the fall 2022 refueling outage (A1R23) and 100% of the SG tubes in Braidwood, Unit 2, during the spring 2023 refueling outage (A2R23). CEG plans to inspect 100% of the SG tubes in Calvert Cliffs, Unit 1, during the spring 2026 refueling outage (CC1R28) and 100% of the SG tubes in Calvert Cliffs, Unit 2, during the spring 2025 refueling outage (CC2R26). CEG plans to inspect 100% of the SG tubes at Ginna during the spring 2023 refueling outage (G1R44). These inspections are required by current TS and will start the TSTF-577 period. At this time, CEG has no plans to defer these inspections.

2.2 Variations CEG is proposing the following variations from the TS changes described in TSTF-577 or the applicable parts of the NRC staff's safety evaluation dated April 14, 2021:

1) The CEG TS utilize different numbering than the Standard Technical Specifications on which TSTF-577 was based. Specifically, the numbering differences are as follows:
  • The "Steam Generator (SG) Tube Integrity" in the Ginna TS and Bases (Westinghouse STS) is numbered 3.4.17 rather than 3.4.20.
  • The "Steam Generator Tube Inspection Report" in the Braidwood and Byron (WOG TS) and Calvert Cliffs TS (CEOG TS) are numbered 5.6.9 rather than 5.6.7.
  • Due to Braidwood and Byron having common TS for Units 1 and 2 but two different tubing alloys, there are two "Item 2" items applicable from TSTF-577 under TS 5.5.9.d. Therefore, for the existing paragraph d.4 in the Braidwood and Byron TS 5.5.9 regarding crack indications, the newly added text for Braidwood Unit 2 and Byron Unit 2 is numbered "paragraph d.3" rather than "paragraph d.2."

These differences are administrative and do not affect the applicability of TSTF-577 to the Braidwood, Byron, Calvert Cliffs, and Ginna TS.

2) The Braidwood Unit 2 and Byron Unit 2 SG Program TS currently contains a provision for an alternate tube plugging criteria (TS 5.5.9.c). The descriptions of the alternate tube plugging criteria in the proposed change are equivalent to the descriptions in the current TS. Therefore, TSTF-577 is still applicable.
3) The Braidwood and Byron TS contain requirements that differ from the Standard Technical Specifications on which TSTF-577 was based but are encompassed in the TSTF-577 justification. Specifically, Braidwood TS 5.5.9.c and Byron TS 5.5.9.c currently state, in part: "The following alternate tube plugging criteria shall be applied as an alternative to the 40% depth based criteria:", where TSTF-577-A states: "The following alternate tube plugging [or repair] criteria may be applied as an alternative to the 40% depth based criteria:" (emphasis added).

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Enclosure Description and Assessment The alternate tube repair criteria sentence including the word "may" was added to TS 5.5.9.c of the WOG STS with TSTF-449-A, Revision 4, "Steam Generator Tube Integrity" (ADAMS Accession No. ML051090200). When Braidwood and Byron implemented TSTF-449-A with Amendment Nos. 144 and 150, respectively, issued March 30, 2007, the formatting of TSTF-449-A and the word "may" were not adopted.

The sentence, "The following alternate tube plugging criteria shall be applied as an alternative to the 40% depth based criteria:" (emphasis added) was added to Braidwood TS 5.5.9.c and Byron TS 5.5.9.c with Amendment Nos. 161 and 166, respectively, issued October 16, 2009 (ADAMS Accession No. ML09250512). The wording was not changed with later amendments.

The sentence for alternate tube plugging criteria (i.e., The following alternate tube plugging [or repair] criteria may be applied as an alternative to the 40% depth based criteria) remained in TS 5.5.9.c of the WOG STS with TSTF-510-A, Revision 0, "Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection" (ADAMS Accession No. ML090890367). Braidwood and Byron implemented TSTF-510-A with Amendment Nos. 172 and 179, respectively, issued March 21, 2013 (ADAMS Accession No. ML13009A182); however, the difference from the Standard Technical Specifications ("may" versus "shall") was not identified and updated at that time.

The word "shall" will be changed to "may" in Braidwood TS 5.5.9.c and Byron TS 5.5.9.c with this letter, which aligns with the wording in TSTF-577. Therefore, TSTF-577 is still applicable.

4) The Ginna TS contain requirements that differ from the Standard Technical Specifications on which TSTF-577 was based but are encompassed in prior Amendments. Specifically, Ginna TS 5.5.8.b.2 provides the following accident induced leakage 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 each SG" (emphasis added). This difference from TSTF-449, approved with Amendment No. 100 dated March 1, 2007 (ADAMS Accession No. ML070370623), is based on the plant-specific analysis. The Ginna TS will not be changed with the TSTF-577 proposed changes; therefore, TSTF-577 is still applicable.
5) The Braidwood and Byron TS contain requirements that differ from the Standard Technical Specifications on which TSTF-577 was based but are encompassed in prior Amendments. Specifically, for TS 5.5.9.b.2, the accident induced leakage performance criterion is more conservative for Braidwood and Byron (e.g., leakage is not to exceed a total of 1 gpm for all SGs), as approved with Amendment Nos. 144 and 150 dated March 30, 2007 (ADAMS Accession No. ML070810354). The current TS leakage values for Braidwood and Byron will not be changed with the TSTF-577 proposed changes; therefore, TSTF-577 is still applicable.

Page 3 of 6

Enclosure Description and Assessment

6) The Braidwood, Byron, Calvert Cliffs, and Ginna TS contain requirements that differ from the Standard Technical Specifications on which TSTF-577 was based but are encompassed in the TSTF-577 justification. Specifically:
  • Braidwood and Byron TS 5.5.9.d currently reference d.1, d.2, and d.3. As referenced in item 1 above, Braidwood and Byron TS 5.5.9.d contain paragraph d.4 regarding crack indications. The markups for Braidwood and Byron TS 5.5.9.d have been modified to include paragraph d.4.
  • Calvert Cliffs TS 5.5.9.b currently reference "Steam generator" instead of "SG," and TS 5.6.9 currently does not include quotation marks around the program title, "Steam Generator (SG) Program." The markups for the Calvert Cliffs TS have been modified to correct these differences.
  • Ginna TS 5.5.8.b.1 currently states: "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." The markups for the Ginna TS have been modified to correct the placement of hyphens as shown in TSTF-577 as follows: "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." (emphasis added).
  • Ginna TS 5.5.8.d.2 currently states: ", with the exception that each SG is to be inspected during the fourth refueling outage in G1R44 following inspections completed in refueling outage G1R40." CEG plans to inspect 100% of the SG tubes during the spring 2023 refueling outage (G1R44) in support of the amendment implementation activities.

These differences from the Standard Technical Specifications are administrative and do not affect the applicability of TSTF-577 to the Braidwood, Byron, Calvert Cliffs, and Ginna TS.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Analysis Constellation Energy Generation, LLC (CEG) 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 Technical Specifications (TS) for Braidwood Station, Units 1 and 2 (Braidwood); Byron Station, Units 1 and 2 (Byron); Calvert Cliffs Nuclear Power Plant, Units 1 and 2 (Calvert Cliffs); and R.E. Ginna Nuclear Power Plant (Ginna). The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history.

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Enclosure Description and Assessment CEG has evaluated if a significant hazards consideration is involved with the proposed amendments 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.

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 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 accident from any accident previously evaluated.

3. Does the proposed change 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.

Page 5 of 6

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

Based on the above evaluation, CEG 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 Commission's 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.

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 statements or environmental assessment need be prepared in connection with the proposed amendment.

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Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 1a Braidwood Station, Units 1 and 2, Proposed Technical Specifications Changes (Mark-up)

NRC Docket Nos. STN 50-456 and STN 50-457 TS Page 5.5-7 TS Page 5.5-8 TS Page 5.5-9 TS Page 5.5-10 TS Page 5.5-11 TS Page 5.6-6 TS Page 5.6-7 Braidwood TS Inserts

Programs and Manuals 5.5 5.5 Programs and Manuals SG 5.5.9 Steam Generator (SG) Program n

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" SG 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.
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.

SG

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.

BRAIDWOOD UNITS 1 & 2 5.5 7 Amendment 172

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (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 not to exceed a total of 1 gpm for all SGs.

3. The operational LEAKAGE performance criteria 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 wall thickness shall be plugged. The following alternate tube plugging criteria shall be applied as an alternative to the 40% depth based may criteria:

For Unit 2, 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. 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. For Unit 2, portions of the tube below 14.01 inches from the top of the tubesheet are excluded from this requirement.

BRAIDWOOD UNITS 1 & 2 5.5 8 Amendment 172/209

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

, and d.4 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. 100% of the tubes in

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

96

2. For Unit 1, 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

, which defines the inspections), with the exception that each SG is to be inspection period. inspected during the fourth refueling outage in A1R23 following inspections completed in refueling outage A1R19. 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.

BRAIDWOOD UNITS 1 & 2 5.5 9 Amendment 220

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 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.

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 INSERT: inspections), with the exception that each SG is to be inspected during the third refueling outage in A2R22 Braidwood TS 5.5.9.d.3 following inspections completed in refueling outage A2R19. 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 BRAIDWOOD UNITS 1 & 2 5.5 10 Amendment 172/209

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 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.

be at the next

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 effective full power months 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 tubesheet on the hot leg side to 14.01 inches below the top of the be at the next 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 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.

, 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 BRAIDWOOD UNITS 1 & 2 5.5 11 Amendment 172/209

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report When a report is required by Condition C or G of LCO 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be reported in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI.

5.6.9 Steam Generator (SG) 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 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, INSERT:

Braidwood f. The number and percentage of tubes plugged to date, and the TS 5.6.9 effective plugging percentage in each steam generator,

g. The results of condition monitoring, including the results of tube pulls and in-situ testing, BRAIDWOOD UNITS 1 & 2 5.6 6 Amendment 217

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Steam Generator (SG) Tube Inspection Report (continued)

h. For Unit 2, the operational primary to secondary leakage rate g observed (greater than three gallons per day) in each steam generator (if it is not practical to assign the leakage to an individual steam generator, the entire primary to secondary leakage should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report,
i. For Unit 2, the calculated accident induced leakage rate from h 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 induced leakage rate from the most limiting accident is less than 3.11 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, and
j. For Unit 2, the results of monitoring for tube axial i displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

BRAIDWOOD UNITS 1 & 2 5.6 7 Amendment 172

Braidwood TS Inserts INSERT: Braidwood 5.5.9.d.3 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.

INSERT: Braidwood TS 5.6.9

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;

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 1b Byron Station, Units 1 and 2, Proposed Technical Specifications Changes (Mark-up)

NRC Docket Nos. STN 50-454 and STN 50-455 TS Page 5.5-7 TS Page 5.5-8 TS Page 5.5-9 TS Page 5.5-10 TS Page 5.5-11 TS Page 5.6-6 TS Page 5.6-7 Byron TS Inserts

Programs and Manuals 5.5 5.5 Programs and Manuals SG 5.5.9 Steam Generator (SG) Program n

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" SG 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.
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.

SG

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.

BYRON UNITS 1 & 2 5.5 7 Amendment 179

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (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 not to exceed a total of 1 gpm for all SGs.

3. The operational LEAKAGE performance criteria 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 wall thickness shall be plugged. The following alternate tube plugging criteria shall be applied as an alternative to the 40% depth based may criteria:

For Unit 2, 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. 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. For Unit 2, portions of the tube below 14.01 inches from the top of the tubesheet are excluded from this requirement.

BYRON UNITS 1 & 2 5.5 8 Amendment 222

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

, and d.4 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. 100% of the tubes in

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

96

2. For Unit 1, 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

, which defines the inspections). In addition, the minimum number of inspection period. 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.

BYRON UNITS 1 & 2 5.5 9 Amendment 222

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 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.

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 INSERT: inspections) with the exception that each SG is to be Byron TS 5.5.9.d.3 inspected during the third refueling outage in B2R23 following inspections completed in refueling outage B2R20. 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 BYRON UNITS 1 & 2 5.5 10 Amendment 222

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 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.

be at the next

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 effective full power months 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 tubesheet on the hot leg side to 14.01 inches below the top of the be at the next 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

, but may be deferred to the indication shall not exceed 24 effective full power following refueling outage if the months or one refueling outage (whichever results in more frequent inspections).

100% inspection of all SGs was performed with enhanced If definitive information, such as from examination of probes as described in a pulled tube, diagnostic non-destructive testing, or paragraph d.3 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.

BYRON UNITS 1 & 2 5.5 11 Amendment 179

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report When a report is required by Condition C or G of LCO 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be reported in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI.

5.6.9 Steam Generator (SG) 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 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 INSERT: degradation mechanism, Byron f. The number and percentage of tubes plugged to date, and the TS 5.6.9 effective plugging percentage in each steam generator,
g. The results of condition monitoring, including the results of tube pulls and in-situ testing, BYRON UNITS 1 & 2 5.6 6 Amendment 221

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Steam Generator (SG) Tube Inspection Report (continued)

h. For Unit 2, the operational primary to secondary leakage rate g observed (greater than three gallons per day) in each steam generator (if it is not practical to assign the leakage to an individual steam generator, the entire primary to secondary leakage should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report,
i. For Unit 2, the calculated accident induced leakage rate from h 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 induced leakage rate from the most limiting accident is less than 3.11 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, and
j. For Unit 2, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the i implications of the discovery and corrective action shall be provided.

BYRON UNITS 1 & 2 5.6 7 Amendment 179

Byron TS Inserts INSERT: Byron 5.5.9.d.3 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.

INSERT: Byron TS 5.6.9

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;

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 1c Calvert Cliffs Nuclear Power Plant, Units 1 and 2, Proposed Technical Specifications Changes (Mark-Up)

NRC Docket Nos. 50-317 and 50-318 TS Page 5.5-6 TS Page 5.5-7 TS Page 5.5-8 TS Page 5.5-9 TS Page 5.5-10 TS Page 5.6-6 TS Page 5.6-7 Calvert Cliffs TS Insert

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.6 Concrete Containment Tendon Surveillance Program This program provides controls for monitoring any tendon degradation in pre-stressed concrete containments, including effectiveness of its corrosion protection medium, to ensure containment structural integrity. The program shall include baseline measurements prior to initial operation. The Tendon Surveillance Program, inspection frequencies, and acceptance criteria shall be in accordance with Section XI, Subsection IWL of the ASME Boiler and Pressure Vessel Code and applicable addenda as required by 10 CFR 50.55a, as amended by relief granted in accordance with 10 CFR 50.55a(a)(3).

The provisions of SR 3.0.3 are applicable to the Tendon Surveillance Program inspection frequencies.

5.5.7 Reactor Coolant Pump Flywheel Inspection Program This program shall provide for the inspection of each reactor coolant pump flywheel per the recommendations of regulatory position C.4.b of Regulatory Guide 1.14, Revision 1, August 1975.

In lieu of Regulatory Position C.4.b(1) and C.4.b(2), a qualified in-place UT examination over the volume from the inner bore of the flywheel to the circle one-half of the outer radius or a surface examination (MT and/or PT) of exposed surfaces of the removed flywheels may be conducted at an interval not to exceed 20 years.

5.5.8 DELETED SG 5.5.9 Steam Generator (SG) Program n

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 SG monitoring assessment means an evaluation of the as found condition of the tubing with respect to the performance CALVERT CLIFFS - UNIT 1 5.5-6 Amendment No. 336 CALVERT CLIFFS - UNIT 2 Amendment No. 314

Programs and Manuals 5.5 5.5 Programs and Manuals 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. SG

b. 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.

SG

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.

CALVERT CLIFFS - UNIT 1 5.5-7 Amendment No. 336 CALVERT CLIFFS - UNIT 2 Amendment No. 314

Programs and Manuals 5.5 5.5 Programs and Manuals

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 100 gpd per SG.
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.

100% of the tubes in

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

96

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

, which defines the refueling outage (whichever results in more frequent inspection period.

CALVERT CLIFFS - UNIT 1 5.5-8 Amendment No. 336 CALVERT CLIFFS - UNIT 2 Amendment No. 314

Programs and Manuals 5.5 5.5 Programs and Manuals 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.

CALVERT CLIFFS - UNIT 1 5.5-9 Amendment No. 336 CALVERT CLIFFS - UNIT 2 Amendment No. 314

Programs and Manuals 5.5 5.5 Programs and Manuals This constitutes the fourth and subsequent inspection periods.

be at the next

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 inspection). 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.

5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit steam generator tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;
b. Identification of the procedures used to measure the values of the critical variables;
c. Identification of process sampling points which shall include monitoring the discharge of the condensate pumps for evidence of condenser in leakage;
d. Procedures for the recording and management of data;
e. Procedures defining corrective actions for all off control point chemistry conditions; and CALVERT CLIFFS - UNIT 1 5.5-10 Amendment No. 336 CALVERT CLIFFS - UNIT 2 Amendment No. 314

Reporting Requirements 5.6 5.6 Reporting Requirements thermal mechanical limits, core thermal hydraulic limits, ECCS limits, nuclear limits such as SOM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d. The COLR, including any mid cycle rev1s1ons or supplements, shall be provided upon issuance for each reload cycle to the NRC.

5.6.6 Not Used 5.6.7 Post-Accident Monitoring Report When a report is required by Condition B or F of LCO 3.3.10, 11 Post Accident Monitoring Instrumentation, 11 a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken.

5.6.9 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:

CALVERT CLIFFS - UNIT 1 5.6-6 Amendment No. 301 CALVERT CLIFFS - UNIT 2 Amendment No. 278

Reporting Requirements 5.6 5.6 Reporting Requirements

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, J e. Number of tubes plugged during the inspeltion outage for each degradation mechanism, INSERT:

Calvert Cliffs f. The number and percentage of tubes plugged to date and the TS 5.6.9 effective plugging percentage in each steam generator,

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

CALVERT CLIFFS - UNIT 1 5.6-7 Amendment No. 308 CALVERT CLIFFS - UNIT 2 Amendment No. 286

Calvert Cliffs TS Insert INSERT: Calvert Cliffs TS 5.6.9

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.

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 1d R.E. Ginna Nuclear Power Plant Proposed Technical Specifications Changes (Mark-Up)

NRC Docket No. 50-244 TS Page 3.4.17-1 TS Page 3.4.17-2 TS Page 5.5-5 TS Page 5.5-6 TS Page 5.6-5 Ginna TS Inserts

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LCO 3.4.17 SG tube integrity shall be maintained.

AND plugging All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged in maintained until the next accordance with the refueling outage or SG tube Steam Generator inspection.

Program.

plugging AND A.2 Plug the affected tube(s) in Prior to entering accordance with the Steam MODE 4 following Generator Program. the next refueling outage or SG tube inspection B. Required Action and B.1 Be in MODE 3 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube integrity not maintained.

R.E. Ginna Nuclear Power Plant 3.4.17-1 Amendment 100

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the Steam In accordance with Generator Program. the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged in accordance with the MODE 4 following a Steam Generator Program. SG tube inspection plugging R.E. Ginna Nuclear Power Plant 3.4.17-2 Amendment 100

Programs and Manuals 5.5 SG 5.5.8 n Steam Generator (SG) Program SG 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 provisions:

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. SG
b. 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. SG
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 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 steady state and a safety factor of 1.4 against burst applied to the design primary-to-secondary 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 each SG. Leakage is not to exceed 1 gpm per SG.

R.E. Ginna Nuclear Power Plant 5.5-5 Amendment 110

Programs and Manuals 5.5 plugging

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."
c. Provisions for SG tube repair 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 repair criteria. The tube-to-tubesheet weld is not plugging 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. An assessment of degradation shall be performed to determine the type and assessment 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 replacement.

installation

2. Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of INSERT: the tubes by the refueling outage nearest the midpoint of the Ginna TS 5.5.8.d.2 period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected, with the exception that each SG is to be inspected during the fourth refueling outage in G1R44 following inspections completed affected and in refueling outage G1R40.

be at the next potentially affected

3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). 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 R.E. Ginna Nuclear Power Plant 5.5-6 Amendment 110, 145

Reporting Requirements 5.6

2. As an alternative to the use of WCAP-14040-A Section 3.2 methodology, the existing Ginna specific LTOP Setpoint Methodology submitted to the NRC in the letter to Guy S.

Vissing (NRC) from Robert C. Mecredy (RG&E), "Application for Amendment to Facility Operating License, Revision to Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR) Administrative Controls Requirements,"

Attachment VI, Section 3.2, dated September 29, 1997 and approved in letter to Robert C. Mecredy (RG&E) from S.

Singh Bajwa (NRC), "R.E. Ginna - Acceptance for Referencing of Pressure Temperature Limits Report,"

Revision 2 (TAC No. M96529), dated November 28, 1997, may be utilized.

d. The PTLR shall be provided to the NRC upon issuance for each reactor vessel fluence period and for revisions or supplement thereto.

5.6.7 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 5.5.8, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,
b. Active 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 active degradation mechanism, INSERT:

Ginna f. Total number and percentage of tubes plugged to date, and TS 5.6.7

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

R.E. Ginna Nuclear Power Plant 5.6-5 Amendment 106

Ginna TS Inserts INSERT: Ginna TS 5.5.8.d.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 INSERT: Ginna TS 5.6.7

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.

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 2a Braidwood Station, Units 1 and 2, Revised Technical Specifications Changes NRC Docket Nos. STN 50-456 and STN 50-457 TS Page 5.5-7 TS Page 5.5-8 TS Page 5.5-9 TS Page 5.5-10 TS Page 5.5-11 TS Page 5.5-12 TS Page 5.5-13 TS Page 5.5-14 TS Page 5.5-15 TS Page 5.5-16 TS Page 5.5-17 TS Page 5.5-18 TS Page 5.5-19 TS Page 5.5-20 TS Page 5.5-21 TS Page 5.5-22 TS Page 5.5-23 TS Page 5.5-24 TS Page 5.6-6 TS Page 5.6-7

Programs and Manuals 5.5 5.5 Programs and Manuals 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.
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.

BRAIDWOOD UNITS 1 & 2 5.5 7 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (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 not to exceed a total of 1 gpm for all SGs.

3. The operational LEAKAGE performance criteria 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 wall thickness shall be plugged. The following alternate tube plugging criteria may be applied as an alternative to the 40% depth based criteria:

For Unit 2, 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. 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. For Unit 2, portions of the tube below 14.01 inches from the top of the tubesheet are excluded from this requirement.

BRAIDWOOD UNITS 1 & 2 5.5 8 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of 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.

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.

BRAIDWOOD UNITS 1 & 2 5.5 9 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

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 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, 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 a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

BRAIDWOOD UNITS 1 & 2 5.5 10 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;
b. Identification of the procedures used to measure the values of the critical variables;
c. Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;
d. Procedures for the recording and management of data;
e. Procedures defining corrective actions for all off control point chemistry conditions; and
f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BRAIDWOOD UNITS 1 & 2 5.5 11 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR.

a. Demonstrate for each of the ESF filter systems that an inplace test of the High Efficiency Particulate Air (HEPA) filters shows a penetration specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation Flow Rate Penetration System Control Room 5400 cfm and < 0.05%

Ventilation (VC) 6600 cfm Filtration System (makeup)

Nonaccessible Area 60,210 cfm and < 1%

Exhaust Filter 73,590 cfm per Plenum Ventilation train, and System (after 20,070 cfm and structural 24,530 cfm per maintenance of the bank HEPA filter housings)

Nonaccessible Area 60,210 cfm and < 1%

Exhaust Filter 73,590 cfm per Plenum Ventilation train System (for reasons other than structural maintenance of the HEPA filter housings)

Fuel Handling 18,900 cfm and < 1%

Building Exhaust 23,100 cfm Filter Plenum (FHB)

Ventilation System BRAIDWOOD UNITS 1 & 2 5.5 12 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

b. Demonstrate for each of the ESF filter systems that an inplace test of the charcoal adsorber shows a bypass specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate Bypass VC Filtration System 5400 cfm and < 1%

(makeup) 6600 cfm VC Filtration System 44,550 cfm and < 0.1%

(recirculation, charcoal 54,450 cfm bed after complete or partial replacement)

VC Filtration System 44,550 cfm and < 2%

(recirculation for 54,450 cfm reasons other than complete or partial charcoal bed replacement)

Nonaccessible Area 60,210 cfm and < 1%

Exhaust Filter Plenum 73,590 cfm per Ventilation System train, and (after structural 20,070 cfm and maintenance of the 24,530 cfm per charcoal adsorber bank housings)

Nonaccessible Area 60,210 cfm and < 1%

Exhaust Filter Plenum 73,590 cfm per Ventilation System (for train reasons other than structural maintenance of the charcoal adsorber housings)

FHB Ventilation System 18,900 cfm and < 1%

23,100 cfm per train BRAIDWOOD UNITS 1 & 2 5.5 13 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

c. Demonstrate for each of the ESF filter systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, ANSI N510-1980, and ASTM D3803-1989, with any exceptions noted in Appendix A of the UFSAR, at a temperature of 30°C and a Relative Humidity (RH) specified below:

ESF Ventilation System Penetration RH VC Filtration System 2.0% 70%

(makeup)

VC Filtration System 4% 70%

(recirculation)

Nonaccessible Area 4.5% 70%

Exhaust Filter Plenum Ventilation System FHB Ventilation System 10% 95%

d. Demonstrate for each of the ESF filter systems that the pressure drop across the combined HEPA filters and the charcoal adsorbers is < 6 inches of water gauge when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate VC Filtration System 5400 cfm and 6600 cfm (makeup)

Nonaccessible Area 60,210 cfm and Exhaust Filter Plenum 73,590 cfm per train Ventilation System FHB Ventilation System 18,900 cfm and 23,100 cfm BRAIDWOOD UNITS 1 & 2 5.5 14 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

e. Demonstrate for each of the ESF filter systems that a bypass test of the combined HEPA filters and damper leakage shows a total bypass specified below at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.12.4 and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate Bypass Nonaccessible Area 60,210 cfm 1%

Exhaust Filter Plenum and Ventilation System 73,590 cfm per train FHB Ventilation System 18,900 cfm 1%

and 23,100 cfm

f. Demonstrate that the heaters for each of the ESF filter systems dissipate the value specified below when tested in conformance with ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR.

ESF Ventilation System Wattage VC Filtration System 29.9 kW and 24.5 kW The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

BRAIDWOOD UNITS 1 & 2 5.5 15 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the waste gas system, the quantity of radioactivity contained in gas decay tanks or fed into the off gas treatment system, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined following the methodology in Branch Technical Position (BTP) ETSB 11-5, "Postulated Radioactive Release due to Waste Gas System Leak or Failure." The liquid radwaste quantities shall be determined in accordance with the ODCM.

The program shall include:

a. The limits for concentrations of hydrogen and oxygen in the waste gas system and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);
b. A surveillance program to ensure that the quantity of radioactivity contained in each gas decay tank and fed into the offgas treatment system is less than the amount that would result in a whole body exposure of 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and
c. A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system is less than the amount that would result in concentrations less than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

BRAIDWOOD UNITS 1 & 2 5.5 16 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:
1. an API gravity or an absolute specific gravity within limits,
2. a flash point and kinematic viscosity within limits, and
3. a clear and bright appearance with proper color or a water and sediment content within limits;
b. Other properties of new fuel oil are within limits within 30 days following sampling and addition to storage tanks; and
c. Total particulate concentration of the fuel oil is 10 mg/l when tested every 31 days.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.

BRAIDWOOD UNITS 1 & 2 5.5 17 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.
b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:
1. a change in the TS incorporated in the license; or
2. a change to the UFSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.
c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.
d. Proposed changes that meet the criteria of Specification 5.5.14.b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e) as modified by approved exemptions.

BRAIDWOOD UNITS 1 & 2 5.5 18 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists.

Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;
b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;
c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and
d. Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming no concurrent single failure, no concurrent loss of offsite power or no concurrent loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or
b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or
c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

BRAIDWOOD UNITS 1 & 2 5.5 19 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.16 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 42.8 psig for Unit 1 and 38.4 psig for Unit 2 The maximum allowable containment leakage rate, La, at Pa, shall be 0.20% of containment air weight per day.

Leakage Rate acceptance criteria are:

a. Containment leakage rate acceptance criterion is 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are

< 0.60 La for the Type B and C tests and < 0.75 La for Type A tests; and BRAIDWOOD UNITS 1 & 2 5.5 20 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Containment Leakage Rate Testing Program (continued)

b. Air lock testing acceptance criteria are:
1. Overall air lock leakage rate is 0.05 La when tested at Pa; and
2. For each door, seal leakage rate is:
i. < 0.0024 La, when pressurized to 3 psig, and ii. < 0.01 La, when pressurized to 10 psig.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

5.5.17 Battery Monitoring and Maintenance Program This program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries For Stationary Applications, or of the battery manufacturer of the following:

a. Actions to restore battery cells with float voltage

< 2.13 V, and

b. Actions to equalize and test battery cells that had been discovered with electrolyte level below the minimum established design limit.

5.5.18 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Ventilation (VC) Filtration System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident. The program shall include the following elements:

BRAIDWOOD UNITS 1 & 2 5.5 21 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Control Room Envelope Habitability Program (continued)

a. The definition of the CRE and CRE boundary.
b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
c. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors,"

Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.

d. Measurement of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one train of the VC Filtration System, operating at the flow rate required by the VFTP, at a Frequency of 18 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the 18 month assessment of the CRE boundary.
e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfilitered air inleakage limit for radiological challenges is the inleakage flow rate assumend in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.
f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.

BRAIDWOOD UNITS 1 & 2 5.5 22 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.19 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.
b. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.
c. The Provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

5.5.20 Risk Informed Completion Time Program This program provides controls to calculate a Risk Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines." The program shall include the following:

a. The RICT may not exceed 30 days;
b. A RICT may only be utilized in MODE 1 and 2;
c. When a RICT is being used, any change to the plant configuration change, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.
1. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.
2. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the plant configuration change, whichever is less.
3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.

BRAIDWOOD UNITS 1 & 2 5.5 23 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.20 Risk Informed Completion Time Program (continued)

d. For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:
1. Numerically accounting for the increased possibility of CCF in the RICT calculation; or
2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.
e. The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods approved for use with this program, or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

BRAIDWOOD UNITS 1 & 2 5.5 24 Amendment

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report When a report is required by Condition C or G of LCO 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be reported in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI.

5.6.9 Steam Generator (SG) 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 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.

BRAIDWOOD UNITS 1 & 2 5.6 6 Amendment

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Steam Generator (SG) 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;
f. The results of any SG secondary side inspections;
g. For Unit 2, the operational primary to secondary leakage rate observed (greater than three gallons per day) in each steam generator (if it is not practical to assign the leakage to an individual steam generator, the entire primary to secondary leakage should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report;
h. For Unit 2, the calculated accident induced 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 induced leakage rate from the most limiting accident is less than 3.11 times the maximum operational primary to secondary leakage rate, the report should 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.

BRAIDWOOD UNITS 1 & 2 5.6 7 Amendment

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 2b Byron Station, Units 1 and 2, Revised Technical Specifications Changes NRC Docket Nos. STN 50-454 and STN 50-455 TS Page 5.5-7 TS Page 5.5-8 TS Page 5.5-9 TS Page 5.5-10 TS Page 5.5-11 TS Page 5.5-12 TS Page 5.5-13 TS Page 5.5-14 TS Page 5.5-15 TS Page 5.5-16 TS Page 5.5-17 TS Page 5.5-18 TS Page 5.5-19 TS Page 5.5-20 TS Page 5.5-21 TS Page 5.5-22 TS Page 5.5-23 TS Page 5.5-24 TS Page 5.6-6 TS Page 5.6-7

Programs and Manuals 5.5 5.5 Programs and Manuals 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.
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.

BYRON UNITS 1 & 2 5.5 7 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (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 not to exceed a total of 1 gpm for all SGs.

3. The operational LEAKAGE performance criteria 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 wall thickness shall be plugged. The following alternate tube plugging criteria may be applied as an alternative to the 40% depth based criteria:

For Unit 2, 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. 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. For Unit 2, portions of the tube below 14.01 inches from the top of the tubesheet are excluded from this requirement.

BYRON UNITS 1 & 2 5.5 8 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of 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.

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.

BYRON UNITS 1 & 2 5.5 9 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

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 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, 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 a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

BYRON UNITS 1 & 2 5.5 10 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;
b. Identification of the procedures used to measure the values of the critical variables;
c. Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;
d. Procedures for the recording and management of data;
e. Procedures defining corrective actions for all off control point chemistry conditions; and
f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BYRON UNITS 1 & 2 5.5 11 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR.

a. Demonstrate for each of the ESF filter systems that an inplace test of the High Efficiency Particulate Air (HEPA) filters shows a penetration specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation Flow Rate Penetration System Control Room 5400 cfm and < 0.05%

Ventilation (VC) 6600 cfm Filtration System (makeup)

Nonaccessible Area 55,669 cfm and < 1%

Exhaust Filter 68,200 cfm per Plenum Ventilation train, and System (after 18,556 cfm and structural 22,733 cfm per maintenance of the bank HEPA filter housings)

Nonaccessible Area 55,669 cfm and < 1%

Exhaust Filter 68,200 cfm per Plenum Ventilation train System (for reasons other than structural maintenance of the HEPA filter housings)

Fuel Handling 18,900 cfm and < 1%

Building Exhaust 23,100 cfm Filter Plenum (FHB)

Ventilation System BYRON UNITS 1 & 2 5.5 12 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

b. Demonstrate for each of the ESF filter systems that an inplace test of the charcoal adsorber shows a bypass specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate Bypass VC Filtration System 5400 cfm and < 1%

(makeup) 6600 cfm VC Filtration System 44,550 cfm and < 0.1%

(recirculation, charcoal 54,450 cfm bed after complete or partial replacement)

VC Filtration System 44,550 cfm and < 2%

(recirculation for 54,450 cfm reasons other than complete or partial charcoal bed replacement)

Nonaccessible Area 55,669 cfm and < 1%

Exhaust Filter Plenum 68,200 cfm per Ventilation System train, and (after structural 18,556 cfm and maintenance of the 22,733 cfm per charcoal adsorber bank housings)

Nonaccessible Area 55,669 cfm and < 1%

Exhaust Filter Plenum 68,200 cfm per Ventilation System (for train reasons other than structural maintenance of the charcoal adsorber housings)

FHB Ventilation System 18,900 cfm and < 1%

23,100 cfm per train BYRON UNITS 1 & 2 5.5 13 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

c. Demonstrate for each of the ESF filter systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, ANSI N510-1980, and ASTM D3803-1989, with any exceptions noted in Appendix A of the UFSAR, at a temperature of 30°C and a Relative Humidity (RH) specified below:

ESF Ventilation System Penetration RH VC Filtration System 2.0% 70%

(makeup)

VC Filtration System 4% 70%

(recirculation)

Nonaccessible Area 4.5% 70%

Exhaust Filter Plenum Ventilation System FHB Ventilation System 10% 95%

d. Demonstrate for each of the ESF filter systems that the pressure drop across the combined HEPA filters and the charcoal adsorbers is < 6 inches of water gauge when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate VC Filtration System 5400 cfm and 6600 cfm (makeup)

Nonaccessible Area 55,669 cfm and Exhaust Filter Plenum 68,200 cfm per train Ventilation System FHB Ventilation System 18,900 cfm and 23,100 cfm BYRON UNITS 1 & 2 5.5 14 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

e. Demonstrate for each of the ESF filter systems that a bypass test of the combined HEPA filters and damper leakage shows a total bypass specified below at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.12.4 and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate Bypass Nonaccessible Area 55,669 cfm 1%

Exhaust Filter Plenum and Ventilation System 68,200 cfm per train FHB Ventilation System 18,900 cfm 1%

and 23,100 cfm

f. Demonstrate that the heaters for each of the ESF filter systems dissipate the value specified below when tested in conformance with ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR.

ESF Ventilation System Wattage VC Filtration System 24.0 kW The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

BYRON UNITS 1 & 2 5.5 15 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the waste gas system, the quantity of radioactivity contained in gas decay tanks or fed into the off gas treatment system, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined following the methodology in Branch Technical Position (BTP) ETSB 11-5, "Postulated Radioactive Release due to Waste Gas System Leak or Failure." The liquid radwaste quantities shall be determined in accordance with the ODCM.

The program shall include:

a. The limits for concentrations of hydrogen and oxygen in the waste gas system and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);
b. A surveillance program to ensure that the quantity of radioactivity contained in each gas decay tank and fed into the offgas treatment system is less than the amount that would result in a whole body exposure of 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and
c. A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system is less than the amount that would result in concentrations less than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

BYRON UNITS 1 & 2 5.5 16 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:
1. an API gravity or an absolute specific gravity within limits,
2. a flash point and kinematic viscosity within limits, and
3. a clear and bright appearance with proper color or a water and sediment content within limits;
b. Other properties of new fuel oil are within limits within 30 days following sampling and addition to storage tanks; and
c. Total particulate concentration of the fuel oil is 10 mg/l when tested every 31 days.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.

BYRON UNITS 1 & 2 5.5 17 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.
b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:
1. a change in the TS incorporated in the license; or
2. a change to the UFSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.
c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.
d. Proposed changes that meet the criteria of Specification 5.5.14.b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e) as modified by approved exemptions.

BYRON UNITS 1 & 2 5.5 18 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists.

Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;
b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;
c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and
d. Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming no concurrent single failure, no concurrent loss of offsite power or no concurrent loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or
b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or
c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

BYRON UNITS 1 & 2 5.5 19 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.16 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 42.8 psig for Unit 1 and 38.4 psig for Unit 2 The maximum allowable containment leakage rate, La, at Pa, shall be 0.20% of containment air weight per day.

Leakage Rate acceptance criteria are:

a. Containment leakage rate acceptance criterion is 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type B and C tests and < 0.75 La for Type A tests; and BYRON UNITS 1 & 2 5.5 20 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Containment Leakage Rate Testing Program (continued)

b. Air lock testing acceptance criteria are:
1. Overall air lock leakage rate is 0.05 La when tested at Pa; and
2. For each door, seal leakage rate is:
i. < 0.0024 La, when pressurized to 3 psig, and ii. < 0.01 La, when pressurized to 10 psig.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

5.5.17 Battery Monitoring and Maintenance Program This program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead - Acid Batteries For Stationary Applications, or of the battery manufacturer of the following:

A. Actions to restore battery cells with float voltage

< 2.13 V, and B. Actions to equalize and test battery cells that had been discovered with electrolyte level below the minimum established design limit.

5.5.18 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Ventilation (VC) Filtration System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident. The program shall include the following elements:

BYRON UNITS 1 & 2 5.5 21 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Control Room Envelope Habitability Program (continued)

a. The definition of the CRE and the CRE boundary.
b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
c. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors," Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.
d. Measurement, at designed locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one train of the VC Filtration System, operating at the flow rate required by the VFTP, at a Frequency of 18 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the 18 month assessment of the CRE boundary.
e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.
f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.

BYRON UNITS 1 & 2 5.5 22 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.19 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.
b. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.
c. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program 5.5.20 Risk Informed Completion Time Program This program provides controls to calculate a Risk Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines." The program shall include the following:
a. The RICT may not exceed 30 days;
b. A RICT may only be utilized in MODE 1 and 2;
c. When a RICT is being used, any change to the plant configuration change, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.
1. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.
2. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the plant configuration change, whichever is less.
3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.

BYRON UNITS 1 & 2 5.5 23 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.20 Risk Informed Completion Time Program (continued)

d. For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:
1. Numerically accounting for the increased possibility of CCF in the RICT calculation; or
2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.
e. The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods approved for use with this program, or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

BYRON UNITS 1 & 2 5.5 24 Amendment

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report When a report is required by Condition C or G of LCO 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be reported in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI.

5.6.9 Steam Generator (SG) 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 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.

BYRON UNITS 1 & 2 5.6 6 Amendment

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Steam Generator (SG) 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;
f. The results of any SG secondary side inspections;
g. For Unit 2, the operational primary to secondary leakage rate observed (greater than three gallons per day) in each steam generator (if it is not practical to assign the leakage to an individual steam generator, the entire primary to secondary leakage should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report;
h. For Unit 2, the calculated accident induced 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 induced leakage rate from the most limiting accident is less than 3.11 times the maximum operational primary to secondary leakage rate, the report should 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.

BYRON UNITS 1 & 2 5.6 7 Amendment

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 2c Calvert Cliffs Nuclear Power Plant, Units 1 and 2, Revised Technical Specifications Changes NRC Docket Nos. 50-317 and 50-318 TS Page 5.5-6 TS Page 5.5-7 TS Page 5.5-8 TS Page 5.5-9 TS Page 5.5-10 TS Page 5.6-6 TS Page 5.6-7

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.6 Concrete Containment Tendon Surveillance Program This program provides controls for monitoring any tendon degradation in prestressed concrete containments, including effectiveness of its corrosion protection medium, to ensure containment structural integrity. The program shall include baseline measurements prior to initial operation. The Tendon Surveillance Program, inspection frequencies, and acceptance criteria shall be in accordance with Section XI, Subsection IWL of the ASME Boiler and Pressure Vessel Code and applicable addenda as required by 10 CFR 50.55a, as amended by relief granted in accordance with 10 CFR 50.55a(a)(3).

The provisions of SR 3.0.3 are applicable to the Tendon Surveillance Program inspection frequencies.

5.5.7 Reactor Coolant Pump Flywheel Inspection Program This program shall provide for the inspection of each reactor coolant pump flywheel per the recommendations of regulatory position C.4.b of Regulatory Guide 1.14, Revision 1, August 1975.

In lieu of Regulatory Position C.4.b(1) and C.4.b(2), a qualified inplace UT examination over the volume from the inner bore of the flywheel to the circle onehalf of the outer radius or a surface examination (MT and/or PT) of exposed surfaces of the removed flywheels may be conducted at an interval not to exceed 20 years.

5.5.8 DELETED 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 CALVERT CLIFFS UNIT 1 5.56 Amendment No.

CALVERT CLIFFS UNIT 2 Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 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.

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 steadystate full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primarytosecondary 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.

CALVERT CLIFFS UNIT 1 5.57 Amendment No.

CALVERT CLIFFS UNIT 2 Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals

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 100 gpd per SG.
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 tubetotubesheet weld at the tube inlet to the tubeto tubesheet weld at the tube outlet, and that may satisfy the applicable tube plugging criteria. The tubetotubesheet 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.

CALVERT CLIFFS UNIT 1 5.58 Amendment No.

CALVERT CLIFFS UNIT 2 Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals

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 nondestructive testing, or engineering evaluation indicates that a cracklike 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.

CALVERT CLIFFS UNIT 1 5.59 Amendment No.

CALVERT CLIFFS UNIT 2 Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit steam generator tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;
b. Identification of the procedures used to measure the values of the critical variables;
c. Identification of process sampling points which shall include monitoring the discharge of the condensate pumps for evidence of condenser in leakage;
d. Procedures for the recording and management of data;
e. Procedures defining corrective actions for all off control point chemistry conditions; and CALVERT CLIFFS UNIT 1 5.510 Amendment No.

CALVERT CLIFFS UNIT 2 Amendment No.

Reporting Requirements 5.6 5.6 Reporting Requirements thermal mechanical limits, core thermal hydraulic limits, ECCS limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d. The COLR, including any mid cycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

5.6.6 Not Used 5.6.7 Post-Accident Monitoring Report When a report is required by Condition B or F of LCO 3.3.10, "Post Accident Monitoring Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken.

5.6.9 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:

CALVERT CLIFFS - UNIT 1 5.6-6 Amendment No.

CALVERT CLIFFS - UNIT 2 Amendment No.

Reporting Requirements 5.6 5.6 Reporting Requirements

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.

CALVERT CLIFFS - UNIT 1 5.6-7 Amendment No.

CALVERT CLIFFS - UNIT 2 Amendment No.

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 2d R.E. Ginna Nuclear Power Plant Revised Technical Specifications Changes NRC Docket No. 50-244 TS Page 3.4.17-1 TS Page 3.4.17-2 TS Page 5.5-5 TS Page 5.5-6 TS Page 5.6-5 TS Page 5.6-6

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LCO 3.4.17 SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube plugging criteria shall be plugged in accordance with the Steam Generator Program.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube affected tube(s) is plugging criteria and not maintained until the next plugged in accordance refueling outage or SG tube with the Steam Generator inspection.

Program.

AND A.2 Plug the affected tube(s) in Prior to entering accordance with the Steam MODE 4 following Generator Program. the next refueling outage or SG tube inspection B. Required Action and B.1 Be in MODE 3 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube integrity not maintained.

R.E. Ginna Nuclear Power Plant 3.4.17-1 Amendment SURVEILLANCE REQUIREMENTS

SG Tube Integrity 3.4.17 SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the Steam In accordance with Generator Program. the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the Prior to entering tube plugging criteria is plugged in accordance with MODE 4 following a the Steam Generator Program. SG tube inspection R.E. Ginna Nuclear Power Plant 3.4.17-2 Amendment

Programs and Manuals 5.5 5.5.8 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.
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 each SG. Leakage is not to exceed 1 gpm per SG.

R.E. Ginna Nuclear Power Plant 5.5-5 Amendment

Programs and Manuals 5.5

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 100% of the tubes in each SG at least every 96 effective full power months, which defines the inspection period, with the exception that each SG is to be inspected during the fourth refueling outage in G1R44 following inspections completed in refueling outage G1R40.
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 R.E. Ginna Nuclear Power Plant 5.5-6 Amendment

Reporting Requirements 5.6

2. As an alternative to the use of WCAP-14040-A Section 3.2 methodology, the existing Ginna specific LTOP Setpoint Methodology submitted to the NRC in the letter to Guy S.

Vissing (NRC) from Robert C. Mecredy (RG&E), "Application for Amendment to Facility Operating License, Revision to Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR) Administrative Controls Requirements,"

Attachment VI, Section 3.2, dated September 29, 1997 and approved in letter to Robert C. Mecredy (RG&E) from S.

Singh Bajwa (NRC), "R.E. Ginna - Acceptance for Referencing of Pressure Temperature Limits Report,"

Revision 2 (TAC No. M96529), dated November 28, 1997, may be utilized.

d. The PTLR shall be provided to the NRC upon issuance for each reactor vessel fluence period and for revisions or supplement thereto.

5.6.7 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 5.5.8, 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.

R.E. Ginna Nuclear Power Plant 5.6-5 Amendment

Reporting Requirements 5.6

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.

R.E. Ginna Nuclear Power Plant 5.6-6 Amendment

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 3 R.E. Ginna Nuclear Power Plant Proposed Technical Specifications Bases Changes (Mark-up) - (Provided for Information Only)

NRC Docket No. 50-244 Bases Page B 3.4.17-2 Bases Page B 3.4.17-4 Bases Page B 3.4.17-5 Bases Page B 3.4.17-6

basis event for SG tubes and avoiding SG Tube Integrity an SGTR is the basis for this B 3.4.17 APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting SAFETY design Specification. The analysis of a SGTR event assumes a ANALYSES bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE,"

plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is released to the atmosphere via safety valves and the atmospheric relief valves.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on primary to secondary LEAKAGE from each SG which is assumed to increase to 1 gpm (500 gallons per day for a locked rotor or rod ejection accident) as a result of accident induced conditions.

For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT I-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 50.67 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

plugging LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.

plugging plugging During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.

The tube-to-tubesheet weld is not considered part of the tube.

A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 5.5.8, "Steam Generator (SG) Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the R.E. Ginna Nuclear Power Plant B 3.4.17-2 Revision 46

SG Tube Integrity B 3.4.17 The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 plugging plugging Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.17.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next R.E. Ginna Nuclear Power Plant B 3.4.17-4 Revision 46

SG Tube Integrity B 3.4.17 SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to entering MODE 4 following the next refueling outage or SG inspection.

This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.17.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

plugging The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

R.E. Ginna Nuclear Power Plant B 3.4.17-5 Revision 46

SG Tube Integrity B 3.4.17 Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.17.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.8 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.17.2 plugging plugging During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging.

The tube repair criteria delineated in Specification 5.5.8 are intended to ensure that tubes accepted for continued service satisfy the SG plugging performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

plugging If crack indications are found in any SG tube, the maximum inspection interval for all affected and potentially affected SGs is restricted by Specification 5.5.8 until subsequent inspections support extending the inspection interval.

R.E. Ginna Nuclear Power Plant B 3.4.17-6 Revision 46

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 4a Braidwood Station, Units 1 and 2, Proposed Renewed Facility Operating License Changes (Mark-up)

NRC Docket Nos. STN 50-456 and STN 50-457 Renewed License Nos. NPF-72 and NPF-77 Unit 1 RFOL Page 6 Unit 2 RFOL Page 6 (No changes)

Unit 2 RFOL Page 7 RFOL INSERTS

(c) The flux thimble tube corrective actions, inspections, and replacements identified in the SER, Commitment No. 24, for Braidwood Units 1 and 2, shall be implemented in accordance with the schedule in the Commitment. Periodic eddy current testing/inspections of all flux thimble tubes shall be performed at least every two refueling outages, and the data shall be trended and retained in auditable form. A flux thimble tube shall not remain in service for more than two (2) operating fuel cycles without successful completion of eddy current testing for that thimble tube.

(14) Adoption of 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems, and components for nuclear power plants Constellation Energy Generation, LLC is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 structures, systems, and components (SSCs) using:

Probabilistic Risk Assessment (PRA) models to evaluate risk associated with internal events, including internal flooding, and internal fire; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2, Class 3, and non-Code class SSCs and their associated supports; and the results of non-PRA evaluations that are based on the IPEEE Screening Assessment for External Hazards, i.e.,

seismic margin analysis (SMA) to evaluate seismic risk, and a screening of other external hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009; as specified in the license amendment No. 198, dated October 22, 2018.

The licensee will complete the updated implementation items listed in Attachment 1 of Exelon letter to NRC dated September 13, 2018, prior to implementation of 10 CFR 50.69. All issues identified in the attachment will be addressed and any associated changes will be made, focused scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to implementation of the 10 CFR 50.69 categorization process.

Prior NRC approval, under 10 CFR 50.90, is required for a change INSERT: to the categorization process specified above (e.g., change from a License Condition seismic margins approach to a seismic probabilistic risk 2.C.(15) assessment approach).

Renewed License No. NPF-72 Amendment No. 224

NO PROPOSED CHANGES TO THIS PAGE.

PROVIDED FOR INFORMATION ONLY.

(c) The flux thimble tube corrective actions, inspections, and replacements identified in the SER, Commitment No. 24, for Braidwood Units 1 and 2, shall be implemented in accordance with the schedule in the Commitment. Periodic eddy current testing/inspections of all flux thimble tubes shall be performed at least every two refueling outages, and the data shall be trended and retained in auditable form. A flux thimble tube shall not remain in service for more than two (2) operating fuel cycles without successful completion of eddy current testing for that thimble tube.

(d) The Braidwood Unit 2 reactor head closure stud hole location No. 35 will be repaired no later than June 18, 2027, or before the end of the last refueling outage prior to the period of extended operation (whichever occurs later), so that all 54 reactor head closure studs are operable and tensioned during the period of extended operation.

(13) Adoption of 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems, and components for nuclear power plants Constellation Energy Generation, LLC is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 structures, systems, and components (SSCs) using:

Probabilistic Risk Assessment (PRA) models to evaluate risk associated with internal events, including internal flooding, and internal fire; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2, Class 3, and non-Code class SSCs and their associated supports; and the results of non-PRA evaluations that are based on the IPEEE Screening Assessment for External Hazards, i.e.,

seismic margin analysis (SMA) to evaluate seismic risk, and a screening of other external hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009; as specified in the license amendment No. 198, dated October 22, 2018.

The licensee will complete the updated implementation items listed in Attachment 1 of Exelon letter to NRC dated September 13, 2018, prior to implementation of 10 CFR 50.69. All issues identified in the attachment will be addressed and any associated changes will be made, focused scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to implementation of the 10 CFR 50.69 categorization process.

Renewed License No. NPF-77 Amendment No. 224

INSERT:

License Condition Prior NRC approval, under 10 CFR 50.90, is required for a change 2.C.(14) to the categorization process specified above (e.g., change from a seismic margins approach to a seismic probabilistic risk assessment approach).

D. An exemption was previously granted pursuant to 10 CFR 70.24. The exemption was granted with NRC materials license No. SNM-1938, issued October 8, 1985, and relieved the licensee from the requirement of having a criticality alarm system. Therefore, the licensee is exempted from the criticality alarm system provision of 10 CFR 70.24 so far as this section applies to the storage of fuel assemblies held under this license.

E. The licensee shall implement and maintain in affect all provisions of the approved fire protection program as described in the Final Safety Analysis Report, as supplemented and amended, and as approved in the SER dated November 1983 and its supplements, subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission, only if these changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

F. Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualifications, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled:

Braidwood Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 3, submitted by letter dated May 17, 2006.

Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p).

The CSP was approved by License Amendment No. 168 and modified by License Amendment No. 185.

G. Deleted H. The licensee shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.

1 The training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

Renewed License No. NPF-77 Amendment No. 224

RFOL INSERTS UNIT 1 RFOL License Condition 2.C.(15)

(15) Adoption of TSTF-577, Revision 1, "Revised Frequencies for Steam Generator Tube Inspections" The extended inspection interval of TS 5.5.9 will not be permitted following implementation of the TSTF-577 amendment until after performance of a 100% inspection of all tubes in a single outage.

UNIT 2 RFOL License Condition 2.C.(14)

(14) Adoption of TSTF-577, Revision 1, "Revised Frequencies for Steam Generator Tube Inspections" The extended inspection interval of TS 5.5.9 will not be permitted following implementation of the TSTF-577 amendment until after performance of a 100% inspection of all tubes in a single outage.

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 4b Calvert Cliffs Nuclear Power Plant, Units 1 and 2, Proposed Renewed Facility Operating License Changes (Mark-up)

NRC Docket Nos. 50-317 and 50-318 Renewed License Nos. DPR-53 and DPR-69 Unit 1 RFOL Page 5 Unit 2 RFOL Page 6 RFOL INSERTS

(c) Actions to minimize release to include consideration of:

1. Water spray scrubbing
2. Dose to onsite responders (6) Risk-Informed Categorization and Treatment of Structures, Systems, and Components Constellation Energy Generation, LLC is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 Structures, Systems, and Components (SSCs) using: Probabilistic Risk Assessment (PRA) models to evaluate risk associated with internal events, including internal flooding, and internal fire; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2 and Class 3 and non-Class SSCs and their associated supports: the results of the non-PRA evaluations that are based on the IPEEE Screening Assessment for External Hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009 for other external hazards except seismic: and the alternative seismic approach as described in Exelons original submittal letter dated November 28, 2018, and all its subsequent associated supplements as specified in License Amendment No. 332 dated February 28, 2020.

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from a seismic margins approach to a seismic probabilistic risk assessment approach).

(7) Constellation Energy Generation, LLC shall provide to the Director of the Office of Nuclear Reactor Regulation or the Director of the Office of Nuclear Material Safety and Safeguards, as applicable, a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from INSERT: Constellation Energy Generation, LLC to its direct or indirect parent, or to any License Condition other affiliated company, facilities for the production, transmission, or 2.C.(8) distribution of electric energy having a depreciated book value exceeding ten percent (10%) of Constellation Energy Generation, LLCs consolidated net utility plant, as recorded on Constellation Energy Generation, LLCs books of account.

D. Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency. plans, including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: Calvert Cliffs Nuclear Power Plant Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 1 submitted May 19, 2006.

Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The licensees Amendment No. 343

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from a seismic margins approach to a seismic probabilistic risk assessment approach).

(9) Constellation Energy Generation, LLC shall provide to the Director of the Office of Nuclear Reactor Regulation or the Director of the Office of Nuclear Material Safety and Safeguards, as applicable, a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from INSERT: Constellation Energy Generation, LLC to its direct or indirect parent, or to any License Condition other affiliated company, facilities for the production, transmission, or 2.C.(10) distribution of electric energy having a depreciated book value exceeding ten percent (10%) of Constellation Energy Generation, LLCs consolidated net utility plant, as recorded on Constellation Energy Generation, LLCs books of account.

D. Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans, including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: Calvert Cliffs Nuclear Power Plant Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 1 submitted dated May 19, 2006.

Constellation Energy Generation, LLC shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The licensees CSP was approved by License Amendment No. 275 and modified by License Amendment No. 290.

E. Constellation Energy Generation, LLC shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c), as specified in the license amendment request dated September 24, 2013; as supplemented by letters dated February 9, 2015, March 11, 2015, April 13, 2015, July 6, 2015, August 13, 2015, February 24, 2016, and April 22, 2016, and as approved in the NRC safety evaluation dated August 30, 2016. Except where NRC approval for changes or deviations is required by 10 CFR 50.48(c), and provided no other regulation, technical specification, license condition or requirement would require prior NRC approval, the licensee may make changes to the fire protection program without prior approval of the Commission if those changes satisfy the provisions set forth in 10 CFR 50.48(a) and 10 CFR 50.48(c), and the criteria listed below are satisfied.

Amendment 321

RFOL INSERTS UNIT 1 RFOL License Condition 2.C.(8)

(8) Adoption of TSTF-577, Revision 1, "Revised Frequencies for Steam Generator Tube Inspections" The extended inspection interval of TS 5.5.9 will not be permitted following implementation of the TSTF-577 amendment until after performance of a 100% inspection of all tubes in a single outage.

UNIT 2 RFOL License Condition 2.C.(10)

(10) Adoption of TSTF-577, Revision 1, "Revised Frequencies for Steam Generator Tube Inspections" The extended inspection interval of TS 5.5.9 will not be permitted following implementation of the TSTF-577 amendment until after performance of a 100% inspection of all tubes in a single outage.

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" Attachment 4c R.E. Ginna Nuclear Power Plant Proposed Renewed Facility Operating License Changes (Mark-up)

NRC Docket No. 50-244 Renewed License No. DPR-244 RFOL Page 9 RFOL INSERT

(17) Adoption of Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times -RITSTF Initiative 4b Constellation Energy Generation, LLC is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to Completion Times (CT) for Required Actions to provide the option to calculate a longer, risk-informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0, which was approved by the NRC on May 17, 2007.

Constellation Energy Generation, LLC will complete the implementation items listed in Attachment 6 of Exelon Letter to the NRC dated May 20, 2021, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to the implementation of the RICT Program.

(18) Deleted (19) Constellation Energy Generation, LLC shall provide to the Director of the Office of Nuclear Reactor Regulation or the Director of the Office of Nuclear Material Safety and Safeguards, as applicable, a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from Constellation Energy Generation, LLC to its direct INSERT: or indirect parent, or to any other affiliate company, facilities for the License Condition production, transmission, or distribution of electric energy having a depreciated book value exceeding ten percent (10%) of Constellation 2.C.(20)

Energy Generation, LLCs consolidated net utility plant, as recorded on Constellation Energy Generation, LLCs books of account.

D. The facility requires an exemption from certain requirements of 10 CFR 50.46(a)(1). This includes an exemption from 50.46(a)(1), that emergency core cooling system (ECCS) performance be calculated in accordance with an acceptable calculational model which conforms to the provisions in Appendix K (SER dated April 18, 1978). The exemption will expire upon receipt and approval of revised ECCS calculations. The aforementioned exemption is authorized by law and will not endanger life property or the common defense and security and is otherwise in the public interest. Therefore, the exemption is hereby granted pursuant to 10 CFR 50.12.

R. E. Ginna Nuclear Power Plant Amendment No. 150

RFOL INSERT RFOL License Condition 2.C.(20)

(20) Adoption of TSTF-577, Revision 1, "Revised Frequencies for Steam Generator Tube Inspections" The extended inspection interval of TS 5.5.8 will not be permitted following implementation of the TSTF-577 amendment until after performance of a 100% inspection of all tubes in a single outage.

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