Text

LR-N21-0036 LAR to Adopt TSTF-577, Revised Frequencies for Steam Generator Tube Inspections
	ML21118B060
Person / Time
Site:	Salem
Issue date:	04/28/2021
From:	Sharbaugh D; Public Service Enterprise Group
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	LAR S21-01, LR-N21-0036
	Download: ML21118B060 (20)
	v • d • e

10 CFR 50.90 April 28, 2021 LR-N21-0036 LAR S21-01 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Salem Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-70 and DPR-75 NRC Docket Nos. 50-272 and 50-311

Subject:

Application to Revise Technical Specifications to Adopt TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections" In accordance with the provisions of 10 CFR 50.90, PSEG Nuclear LLC (PSEG) is submitting a request for an amendment to the Technical Specifications (TS) for Salem Generating Station (Salem) Units 1 and 2.

PSEG 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 Salem Units 1 and 2 TS. The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history. provides a description and assessment of the proposed changes. Attachment 1 provides the existing TS pages marked up to show the proposed changes. The TS Bases are not affected by the proposed changes.

PSEG requests that the amendment be reviewed under the Consolidated Line Item Improvement Process (CLIIP). The amendment is requested to be approved by September 10, 2021 to support the Fall 2021 refueling outage for Salem Unit 2. Once approved, the amendment shall be implemented within 30 days.

In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated State of New Jersey Official.

There are no regulatory commitments contained in this letter.

If you have any questions or require additional information, please contact Mr. Brian Thomas at 856-339-2022.

LR-N21-0036 10 CFR 50.90 Page 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed on Lt!t i'o} i \

( d-at e)

Respectfully, Dave Sharbaugh Site Vice President Salem Generating Station

Enclosure:

Evaluation of the Proposed Changes Mark-up of Proposed Technical Specification Pages cc: Mr. D. Lew, Administrator, Region I, NRC Mr. J. Kim, Project Manager, NRC NRC Senior Resident Inspector, Salem Ms. A Pfaff, Manager NJBNE PSEG Corporate Commitment Tracking Coordinator Site Commitment Tracking Coordinator

LR-N21-0036 LAR S21-01 Enclosure Evaluation of the Proposed Changes Table of Contents

1.0 DESCRIPTION

................................................................................................................1 2.0 ASSESSMENT ................................................................................................................1 2.1 Applicability of Safety Evaluation ...............................................................................1 2.2 Variations ..................................................................................................................1

3.0 REGULATORY ANALYSIS

.............................................................................................1 3.1 No Significant Hazards Consideration .......................................................................1 3.2 Conclusion.................................................................................................................3 4.0 ENVIRONMENTAL EVALUATION ..................................................................................3

LR-N21-0036 LAR S21-01 DESCRIPTION AND ASSESSMENT

1.0 DESCRIPTION

PSEG 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 Salem Units 1 and 2 Technical Specifications (TS). 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 PSEG has reviewed the safety evaluation for TSTF-577 provided to the Technical Specifications Task Force in a letter dated April 14, 2021. This review included a review of the NRC staffs evaluation, as well as the information provided in TSTF-577. PSEG has concluded that the justifications presented in TSTF-577 and the safety evaluation prepared by the NRC staff are applicable to Salem Units 1 and 2 and justify this amendment for the incorporation of the changes to the Salem TS.

The current SG TS requirements are based on TSTF-510, "Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection." PSEG has 2 units. The Unit 1 SGs have Alloy 600 thermally treated (Alloy 600TT) tubes. The Unit 2 SGs have Alloy 690 thermally treated (Alloy 690TT) tubes.

The initial inspection period described in the SG Program, paragraph d.2, began in March 2020 for Salem Unit 1 and April 2017 for Salem Unit 2. PSEG will submit a SG Tube Inspection Report meeting the revised TS 6.9.1.10 requirements within 30 days after implementation of the license amendment.

2.2 Variations The Salem TS utilize different numbering than the Standard Technical Specifications on which TSTF-577 was based. Specifically, the "Steam Generator (SG) Program" in the Salem Unit 1 and 2 TS is numbered 6.8.4.i rather than 5.5.9, and the "Steam Generator Tube Inspection Report" is numbered 6.9.1.10 rather than 5.6.7. These differences are administrative and do not affect the applicability of TSTF-577 to the Salem Unit 1 and 2 TS.

The Salem Unit 1 SG Program TS currently contains a provision for an alternate tube plugging or repair criteria. The descriptions of the alternate tube plugging or repair criteria in the proposed change are equivalent to the descriptions in the current TS.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Analysis PSEG requests adoption of TSTF-577, "Revised Frequencies for Steam Generator Tube Inspections," which is an approved change to the Standard Technical Specifications (STS),

1

LR-N21-0036 LAR S21-01 into the Salem Units 1 and 2 Technical Specifications (TS). The TS related to steam generator (SG) tube inspections and reporting are revised based on operating history.

PSEG 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 kind of accident from any previously evaluated?

Response: No The proposed change revises the inspection frequencies for SG tube inspections and associated reporting requirements. The proposed change does not alter the design function or operation of the SGs or the ability of an SG to perform the design function.

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

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

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

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

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

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

2

LR-N21-0036 LAR S21-01 Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, PSEG 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 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

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

no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

3

LR-N21-0036 LAR S21-01 Attachment 1 Mark-up of Proposed Technical Specification Pages The following Technical Specifications pages for Renewed Facility Operating License DPR-70 are affected by this change request:

Technical Specification Page 6.8.4.i, Steam Generator (SG) Program 6-19b 6-19c 6-19d 6-19e 6.9.1.10, Steam Generator Tube Inspection Report 6-24a 6-24b The following Technical Specifications pages for Renewed Facility Operating License DPR-75 are affected by this change request:

Technical Specification Page 6.8.4.i, Steam Generator (SG) Program 6-19b 6-19c 6-19d 6-19e 6-19f 6.9.1.10, Steam Generator Tube Inspection Report 6-24a 6-24b 1

LR-N21-0036 LAR S21-01 Technical Specification Mark-Up Inserts Insert 1: (Unit 1 Only)

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 2:

b. Then 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;

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

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.

2

ADMINISTRATIVE CONTROLS

7) Limitations on the dose rate resulting from radioactive material released in gaseous effluents to areas beyond the SITE BOUNDARY conforming to the doses associated with 10 CFR Part 20, Appendix B, Table II, Column 1,

8) Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,

9) Limitations on the annual and quarterly doses to a MEMBER OF THE PUBLIC from lodine-131, lodine-133, tritium, and all radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents released from each unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,

10) Limitations on the annual dose or dose commitment to any MEMBER OF THE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources conforming to 40 CFR Part 190.

6.8.4.h Radiological Environmental Monitoring Program A program shall be provided to monitor the radiation and radionuclides in the environs of the plant. The program shall provide (1) representative measurements of radioactivity in the highest potential exposure pathways, and (2) verification of the accuracy of the effluent monitoring program and modeling of environmental exposure pathways. The program shall (1) be contained in the ODCM, (2) conform to the guidance of Appendix I to 10 CFR Part 50, and (3) include the following:

1) Monitoring, sampling, analysis, and reporting of radiation and radionuclides in the environment in accordance with the methodology and parameters in the ODCM,

2) A Land Use Census to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the monitoring program are made if required by the results of the census, and

3) Participation in a lnterlaboratory Comparison Program to ensure that independent checks on the precision and accuracy of the measurements of radioactive materials in environmental sample matrices are performed as part of the quality assurance program for environmental monitoring.

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

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the 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 SALEM - UNIT 1 6-19b Amendment No. 309

ADMINISTRATIVE CONTROLS 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.

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 1 gallon per minute per SG.

3. The operational leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System 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.

The following alternate plugging criteria shall be applied as an alternative to the 40%

depth based criteria:

1. Tubes with service-induced flaws located greater than 15.21 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 15.21 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.

SALEM - UNIT 1 6-19c Amendment No. 309 except for any portions of the tube that are exempt from inspection by alternate repair criteria

ADMINISTRATIVE CONTROLS The portion of the tube below 15.21 inches from the top of the tubesheet is excluded from this requirement.

The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

2. After the first refueling outage following SG installation, inspect each SG at least every 48 effective full power months or at least every other refueling outage (whichever results in more frequent inspections). In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of Insert 1 tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a, b, and c below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a) After the first refueling outage following SG installation, inspect 100% of the tubes during the next 120 effective full power months. This constitutes the first inspection period; b) During the next 96 effective full power months, inspect 100% of the tubes.

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

SALEM - UNIT 1 6-19d Amendment No. 309 I

excluding any region that is exempt from inspection by alternate repair criteria ADMINISTRATIVE CONTROLS

3. If crack indications are found in portions of the SG tube not excluded above, 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.

6.8.4.j Deleted 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.2 6.8.4.k Reactor Coolant Pump Flywheel Inspection Program In addition to the requirements of the ISi Program, each Reactor Coolant Pump flywheel shall be inspected per the recommendations of Regulatory Position C.4.b of Regulatory Guide 1.14, Revision 1, August 1975. In lieu of 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 20 year intervals.

SALEM - UNIT 1 6-19e Amendment No.319

ADMINISTRATIVE CONTROLS

2. WCAP-8385, Power Distribution Control and Load Following Procedures -

Topical Report, 0!:J... Proprietary) Methodology for Specification 3/4.2.1 Axial Flux Difference.

3. WCAP-10054-P-A, Westinghouse Small Break ECCS Evaluation Model Using NOTRUMP Code 0!:J... Proprietary), Methodology for Specification 3/4.2.2 Heat Flux Hot Channel Factor.

4. WCAP-10266-P-A, The 1981 Version of Westinghouse Evaluation Model Using BASH Code, 0!:J... Proprietary) Methodology for Specification 3/4.2.2 Heat Flux Hot Channel Factor.

5. WCAP-12472-P-A, BEACON - Core Monitoring and Operations Support System, 0!:J... Proprietary).

6. CENPD-397-P-A, Improved Flow Measurement Accuracy Using Crossflow Ultrasonic Flow Measurement Technology.

c. The core operating limits shall be determined such that all applicable limits (e.g.,

fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (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 revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

6.9.1.10 STEAM GENERATOR TUBE INSPECTION REPORT A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "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, Insert 2

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 e mechanism,

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

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

f. The results of any SG secondary side inspections; SALEM - UNIT 1 6-24a Amendment No. 309

ADMINISTRATIVE CONTROLS g

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

i. The calculated accident induced leakage rate from the portion of the tubes below 15.21 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 2.16 times the maximum operational primary to secondary leakage rate, the report should describe how it was i determined,

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

SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, D.C. 20555, with a copy to the Administrator, USNRC Region I within the time period specified for each report.

6.9.3 DELETED 6.9.4 When a report is required by ACTION 1, 4, 8 or 9 of Table 3.3-11 "Accident Monitoring Instrumentation", a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring for inadequate core cooling, the cause of the inoperability, and the plans and schedule for restoring the instrument channels to OPERABLE status.

SALEM - UNIT 1 6-24b Amendment No. 320