ML13072A105

Issuance of Amendments Revision to Technical Specification 6.8.4.i, Steam Generator Program, and Technical Specifications 6.9.1.10, Steam Generator Tube Inspection Report, for a Permanent Alternate

ML13072A105
Person / Time
Site:	Salem
Issue date:	03/28/2013
From:	John Hughey Plant Licensing Branch 1
To:	Joyce T Public Service Enterprise Group
Hughey J
References
TAC ME8578
Download: ML13072A105 (33)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 March 28, 2013 Mr. Thomas Joyce President and Chief Nuclear Officer PSEG Nuclear LLC P.O. Box 236, N09 Hancocks Bridge, NJ 08038

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NO.1-ISSUANCE OF AMENDMENT RE: REVISION TO TECHNICAL SPECIFICATION 6.8.4.i, "STEAM GENERATOR PROGRAM," AND TECHNICAL SPECIFICATION 6.9.1.10, "STEAM GENERATOR TUBE INSPECTION REPORT," FOR A PERMANENT ALTERNATE REPAIR CRITERIA (TAC NO. ME8578)

Dear Mr. Joyce:

The Nuclear R~gulatory Commission (NRC) has issued the enclosed Amendment No. 303 to Renewed Facility Operating License (FOL) No. DPR-70 for the Salem Nuclear Generating Station (Salem), Unit No.1, in response to your application dated May 8,2012.

The amendment approves changes to TS Section 6.8.4.i, "Steam Generator (SG) Program,"

and TS 6.9.1.10, "Steam Generator Tube Inspection Report." The approved changes establish permanent SG tube alternate repair criteria for tubing flaws located in the lower region of the tubesheet. The approved changes replace sirnilar criteria foi' Salem that were approved on an interim basis during Refueling Outage 20 for tne subsequent operating cycles, until the next scheduled SG tube inspection.

Our safety evaluation (SE) is also enciosed. Section 3.2,2 of the SE describes the NRC staff's evaluation of the reguiatory commitments proposed by the licensee in the amendment application. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sinpo.~

John D. Hughey, Project Manager Plant Licensing Branch 1-2 Division ('If Operating Reactor Licensing OfficE; of Nuc:ear Reactor Regulation Docket No. 50-272

Enclosures:

1, Amendment No. 30::; to Renewed License No DPR-70

2. Safety Evaluation cc wiencls: Distribution via ListSarv

uNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 PSEG NUCLEAR, LLC EXELON GENERATION COMPANY, LLC DOCKET NO. 50-272 SALEM NUCLEAR GENERATING STATION, UNIT NO.1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 303 Renewed license No. DPR-70

1. The Nuclear Regulatory Commission (the Commission) has found that" A. The application for amendment filed by PSEG Nuclear, LLC, acting on behalf of itself and Exelon Generation Company, LLC (the licensees), dated May 8,2012, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth In Title 10 of the Code of Federal Regulations (to CFR), Chapter I; B. The facility will operate in conformity with tr!e application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance: (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth In 10 CFR Chapter \;

D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is In accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

-2

2. Accordingly, paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-70 is hereby amended. as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 303, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications, and the Environmental Protection Plan.

3. This license amendment is effective as of the date of its issuance and shall be implemented within 60 days.

FOR THE NUCLEAR REGULATORY COMMISSION

~~

Meena K. Khanna, Chief Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the License and the Technical Specifications Date of Issuance: March 28, 2013

ATTACHMENT TO LICENSE AMENDMENT NO. 303 RENEWED FACILITY OPERATING LICENSE NO. DPR-70 DOCKET NO. 50-272 Replace the following pages of Renewed Facility Operating License No. DPR-70 with the attached revised pages as indicated. The revised pages are identified by amendment number and contain a marginal line indicating the areas of change.

Remove Insert Page 3 Page 3 Replace the following pages of the Appendix A, Technical Specifications, with the attached revised pages as indicated. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert Page 6-19c Page 6-19c Page 6-19d Page 6-19d Page 6-24b Page 6-24b

-3 instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at a steady state reactor core power level not in excess of 3459 megawatts (one hundred percent of rated core power).

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 303, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications, and the Environmental Protection Plan.

(3) Deleted Per Amendment 22, 11-20-79 (4) Less than Four Loop Operation PSEG Nuclear LLC shall not operate the reactor at power levels above P-7 (as defined in Table 3.3-1 of Specification 3.3.1.1 of Appendix A to this renewed license) with less than four (4) reactor coolant loops in operation until safety analyses for less than four loop operation have been submitted by the licensees and approval for less than four loop operation at power levels above P-7 has been granted by the Commission by Amendment of this renewed license.

(5) PSEG Nuclear LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Renewed License No. DPR-70 Amendment No. 303

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 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 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 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.

The following alternate repair 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 repair criteria.

SALEM - UNIT 1 6-19c Amendment No. 303

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. An assessment of degradation 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 replacement.

2. Inspect 100% of the tubes at sequential periods of 120, 90, 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 the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.

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

SALEM - UNIT 1 6-19d Amendment No. 303

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,

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 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 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 preplan ned 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. 303

UNITED STATES NUCLEAR REGULATORY COMMISSION

...:; WASHINGTON. D.C. 20555*0001

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• • • • . SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 303 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-70 P$.EG NUCLEAR LLC SALEM NUCLEAR GENERATING STATION. UNIT NO.1 DOCKET NO. 50-272

1.0 INTRODUCTION

By letter dated May 8,2012 (Reference 1), PSEG Nuclear, LLC (the licensee) submitted a request for a license amendment in the form of changes to the Technical Specifications (TS) for Salem Generating Station (Salem), Unit 1. The request proposed changes to TS Section 6.8.4.1, "Steam Generator (SG) Program," and TS 6.9.1.10, "Steam Generator Tube Inspection Report." The proposed changes would establish permanent SG tube alternate repair criteria for tubing flaws located in the lower region of the tubesheet. The proposed cnanges would replace similar criteria for Salem that were approved on an interir:-: basis during Refueling Outage 20 (RF020) for the subsequent operating cycles, untIl the next scheduled SG tube inspection.

1.1 Background Salem Unit 1 has four Model F SGs, which were designed and fabricated by Westinghouse.

There are 5,626 Alloy 600 thermally treated (Alloy 600TT) tubes in each SG. each with a nominal outside diameter of 0.688 inches and a nominal wall thickness of 0.040 inches.

The tubes are hydraulically expanded for the full depth of the 21-inch tubesheet and are welded to the tubesheet at each tube end. Until the fall of 2004. no instances of stress-corrosion cracking affecting the *tubesheet region of Alloy 600TT tubing had been reported at any nuclear power plants in the United States.

In the fall of 2004, crack-like indications were found in tubes in the tubesheet region of Catawba Nuclear Station (Catawba) Unit 2. These crack-like indications were found in a tube overexpansion (OXP) that was approximately 7 Inches below the hot-leg tubesheet in one tube, and just above the tube-to-tubeshee~ (TITS) weld in a region of the tube known as the tack expansion region in several otner tubes. Indications were also reported near the TITS welds, which join the tube to tt"le tubesheet An OXP is created when the ~ube is expanded into a tubesheet bore hole that is not perfectly round. These out-of-round conditions were created during the tubesheet driiling process by conditions such as drill bit wandering or chip gouging.

The tack expansion is an approx1mately 1-inch long expansion at each tube end. The purpose of the tack expansion is to facilitate performing the TITS weld, 'Nhich is made prior to the hydraulic expansion of the tube over the fuil tubesheet depth.

Enclosure

-2 Since the initial findings at Catawba Unit 2 in the fall of 2004, other nuclear plants with Alloy 600TT tubing have found crack-like indications in tubes within the tubesheet as well; most of these indications were in the tack expansion region near the tube-end welds and were a mixture of axial and circumferential primary water stress-corrosion cracking.

Over time, these cracks can be expected to become more and more extensive, necessitating more extensive inspections of the lower tubesheet region and more extensive tube plugging or repair, with attendant increased cost and the potential for shortening the useful lifetime of the SGs. To avoid these impacts, the affected licensees and their contractor, Westinghouse Electric Company, LLC (Westinghouse), have developed proposed alternative inspection and repair criteria, applicable to the tubes in the lowermost region of the tubesheets. These criteria are referred to as the "H*" criteria. H* is the minimum engagement distance between the tube and tubesheet, measured downward from the top of the tubesheet, that is proposed as needed to ensure the structural and leakage integrity of the TfTS joints. The proposed H* amendment would exclude the portions of tubing below the H* distance from inspection and plugging requirements on the basis that flaws below the H* distance are not detrimental to the structural and leakage integrity of the TfTS joints.

Requests for permanent H* amendments were proposed for a number of plants as early as 2005. The U.S. Nuclear Regulatory Commission (NRC) staff identified a number of issues with these early proposals and in subsequent proposals made in 2009, and was unable to approve H* amendments on a permanent basis, pending resolution of these issues. The NRC staff found that it did have a sufficient basis to approve H* amendments on an interim (temporary) basis, based on the relatively limited extent of cracking existing in the lower tubesheet region, at the time the interim amendments were approved. The technical basis for approving the interim amendments was provided in detail in the NRC staff's safety evaluations (SEs) accompanying issuance of those amendments. An interim H* amendment was approved most recently in 2010 for Salem Unit 1 (Reference 2).

2.0 REGULATORY EVALUATION

The SG tubes are part of the reactor coolant pressure boundary (RCPB) and isolate fission products in the primary coolant from the secondary coolant and the environment. For the purposes of this SE, SG tube integrity means that the tubes are capable of performing this safety function in accordance with the plant design and licensing basis. The General Oesign Criteria (GOC) in Appendix A to Title 10 of the Code of Federal Regulations (10 CFR), Part 50, provide regulatory requirements and state that the RCPB shall have "an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture" (GOC 14),

"shall be designed with sufficient margin" (GOC 15 and 31), shall be of "the hjghest quality standards practical" (GOC 30), and shall be designed to permit "periodic inspection and testing ... to assess ... structural and leaktight integrity" (GOC 32). Because the construction permit for Salem Unit 1 was issued in September 1968, Salem Unit 1 was designed to the Atomic Industrial Forum version of the GOC, dated October 2, 1967. In Section 3.1.3 of the Updated Final Safety Analysis Report (UFSAR), the licensee discusses compliance with each of the GOC in Appendix A of 10 CFR Part 50, and does not identify any deviations from these GOC for SG tube-related issues.

-3 Section 50.55a(c)(1) of 10 CFR specifies that components which are part of the RCPB must meet the requirements for Class 1 components in Section III of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code), except as provided in 10 CFR 50.55a(c)(2), (3), and (4). Section 50.55a(f)(4) further requires that throughout the service life of pressurized-water reactor (PWR) facilities (like Salem Unit 1), ASME Code Class 1 components meet the Section XI requirements of the ASME Code to the extent practical, except for design and access provisions, and pre-service examination requirements. This requirement includes the inspection and repair criteria of Section XI of the ASME Code. The Section XI requirements pertaining to in-service inspection of SG tubing are augmented by additional requirements in the TS.

The requirements related to the content of the TS are established in 10 CFR 50.36, "Technical specifications." Pursuant to 10 CFR 50.36, TS are required to include items in the following five categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings, (2) limiting conditions for operation (LCO), (3) surveillance .

requirements, (4) design features, and (5) administrative controls. The rule does not specify the particular requirements to be included in a plant's TS.

LCOs are stated to be "the lowest functional capability or performance levels of equipment required for safe operation of the facility," in 10 CFR 50.36(c)(2). For Salem Unit 1, the LCO pertaining to the subject license amendment request (LAR) is in TS 3.4.6.2, "Reactor Coolant System Operational Leakage."

Administrative controls are described as, "the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner," in 10 CFR 50.36(c)(5). Programs established by the licensee, including the SG program, are listed in the administrative controls section of the TS and are established to operate the facility in a safe manner. For Salem Unit 1, the SG program requirements, including requirements for SG tube inspection and repair, are in TS 6.8.4.i, "Steam Generator (SG) Program," while the reporting requirements for the SG Program are in TS 6.9.1.10, "Steam Generator Tube Inspection Report."

The TS for all PWR plants require that an SG program be established and implemented to ensure that SG tube integrity is maintained. For Salem Unit 1, SG tube integrity is maintained by meeting the performance criteria specified in TS 6.8.4.i.b for structural and leakage integrity, consistent with the plant design and licensing basis. Technical Specification 6.8.4.La requires that a condition monitoring assessment be performed during each outage in which the SG tubes are inspected, to confirm that the performance criteria are being met. Technical Specification 6.8.4.Ld includes provisions regarding the scope, frequency, and methods of SG tube inspections. These provisions require that the inspections be performed with the objective of detecting flaws of any type that may be present along the length of a tube, from the TfTS weld at the tube inlet to the TfTS weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The applicable tube repair criteria, specified in TS 6.8.4.i.c., are that tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40 percent of the nominal wall thickness shall be plugged, unless the tubes are permitted to remain in service through application of the alternate repair criteria provided in TS 6.8.4.i.c. Section 3.4.6.2 of the plant TSs includes a limit on operational primary-to-secondary leakage of 150 gallons per day, which if exceeded, requires the plant to be promptly shut down. Should a flaw exceeding the

- 4 tube repair limit not be detected during the periodic tube surveillance required by the plant TSs, the operational leakage limit provides added assurance of timely plant shutdown before tube structural and leakage integrity, consistent with the design and licensing bases, are impaired.

As part of the plant's licensing bases, applicants for PWR licenses are required to analyze the consequences of postulated design-basis accidents (DBA), such as an SG tube rupture and a main steamline break (MSLB). These analyses consider primary-to-secondary leakage that may occur during these events and must show that the offsite radiological consequences do not exceed the applicable limits of the 10 CFR Part 50.67 accident source term, GDC 19 for control room operator doses (or some fraction thereof as appropriate to the accident), or the NRC-approved licensing basis (e.g., a small fraction of these limits). No accident analyses for Salem Unit 1 are being changed because of the proposed amendment and, thus, no radiological consequences of any accident analysis are being changed. The use of the proposed alternate repair criteria does not impact the integrity of the SG tubes; therefore, the SG tubes still meet the requirements of the GDC in Appendix A to 10 CFR Part 50, and the requirements for Class 1 components in Section III of the ASME Code. The proposed changes maintain the accident analyses and consequences that the NRC has previously reviewed and approved for the postulated DBAs for SG tubes.

License Amendment 294 is currently approved for Salem Unit 1. This amendment modified TS 6.8.4.i, "Steam Generator (SG) Program," and TS 6.9.1.10, "Steam Generator Tube Inspection Report," incorporating interim alternate repair criteria and associated tube inspection and repoliing requirements that were applicable during RF020, and the subsequent operating cycles, until the next scheduled SG tube inspection. The proposed permanent amendment uses the same tube inspection and reporting requirements that were approved for the interim amendment, but allows these requirements to be used on a permanent basis. The alternate repair criteria (i.e., the H* distance) associated with the permanent amendment is slightly longer (more conservative) than the criteria used in the prior interim amendment.

3.0 TECHNICAL EVALUATION

3.1 Proposed Changes to the TS The reference for the indicated changes below are the current TSs, including the currently approved interim alternate repair criteria and associated tube inspection and reporting requirements. The proposed changes are shown in markup form for clarity.

TS 6.8.4.i.c. would be revised as follows:

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.

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

1. For Refuel Outage 1R20 through the subsequent operating cycles until the next scheduled SG tube inspection, tTubes with service-induced flaws

- 5 located greater than -4&.4 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 -4&.4 15.21 inches below the top of the tubesheet shall be plugged upon detection.

TS 6.8.4.i.d. would be revised as follows:

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. For Refuel Outage 1R20 through the subsequent operating cycles until the next scheduled SG tube inspection, The portions of the tube below -4&.4 15.21 inches from the top of the tubesheet afe 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. An assessment of degradation 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. [No change]

2. [No change]

3. [No change]

TS 6.9.1.10 would be revised as follows:

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 a.8.4.i, "Steam Generator (SG) Program." The report shall include:

a. - g [No change]

Reporting requirements h, i and j are applicable for Refuel Outage 1R20 through the subsequent operating eyeles until the next seheduled SG tube inspection.

h. [No change]

i. The calculated accident induced leakage rate from the portion of the tubes below

-4&.4 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

-6 primary to secondary leakage rate, the report should describe how it was determined,

j. [No change]

3.2 Technical Evaluation The TfTS joints are part of the pressure boundary between the primary and secondary systems.

Each TfTS joint consists of the tube, which is hydraulically expanded against the bore of the tubesheet, the TfTS weld located at the tube end, and the tubesheet. The joints were designed in accordance with the ASME Code,Section III, as welded joints, not as friction joints. The TfTS welds were designed to transmit the tube end cap pressure loads, during normal operating and DBA conditions, from the tubes to the tubesheet with no credit taken for the friction developed between the hydraulically-expanded tube and the tubesheet. In addition, the welds serve to make the jOints leak tight.

This design basis is a conservative representation of how the TfTS jOints actually work, since it conservatively ignores the role of friction between the tube and tubesheet in reducing the tube end cap load that is transmitted to the TfTS weld. The initial hydraulic expansion of the tubes against the tubesheet produces an "interference fit" between the tubes and the tubesheet; thus, producing a residual contact pressure (RCP) between the tubes and tubesheet, which acts normally to the outer surface of the tubes and the inner surface of the tubesheet bore holes.

Additional contact pressure between the tubes and tubesheet is induced by operational conditions, as will be discussed in detail below. The amount of friction force that can be developed between the outer tube surface and the inner surface of the tubesheet bore is a direct function of the contact pressure between the tube and tubesheet multiplied by the applicable coefficient of friction.

To support the proposed TS changes, the licensee's contractor, Westinghouse, has defined a parameter called H* to be that distance below the top of the tubesheet over which sufficient frictional force, with acceptable safety margins, can be developed between each tube and the tubesheet under tube end cap pressure loads associated with normal operating and design basis accident conditions to prevent significant slippage or pullout of the tube from the tubesheet, assuming the tube is fully severed at the H* distance below the top of the tubesheet.

For Salem Unit 1, the licensee has proposed an H* distance of 15.21 inches. Given that the frictional force developed in the TfTS joint over the H* distance is sufficient to resist the tube end cap pressure loads, it is the licensee's and Westinghouse's position that the length of tubing between the H* distance and the TfTS weld is not needed to resist any portion of the tube end cap pressure loads. Thus, the licensee is proposing to change the TS to not require inspection of the tubes below the H* distance and to exclude tube flaws located below the H* distance (including flaws in the TfTS weld) from the application of the TS tube repair criteria. Under these changes, the TfTS joint would now be treated as a friction joint extending from the top of the tubesheet to a distance below the top of the tubesheet equal to H* for purposes of evaluating the structural and leakage integrity of the joint.

The regulatory standard by which the NRC staff has evaluated the subject license amendment is that the amended technical specifications should continue to ensure that tube integrity will be maintained, consistent with the current design and licensing basis. This includes maintaining

-7 structural safety margins consistent with the structural performance criteria in TS 6.8.4.i.b.1 and the design basis, as is discussed in Section 3.2.1.1 below. In addition, this includes limiting the potential for accident-induced primary-to-secondary leakage to values not exceeding the accident-induced leakage performance criteria in TS 6.8.4.i.b.2, which are consistent with values assumed in the licensing basis accident analyses. Maintaining tube integrity in this manner ensures that the amended TS are in compliance with all applicable regulations.

The NRC staff's evaluation of joint structural integrity and accident-induced leakage integrity is discussed in Sections 3.2.1 and 3.2.2 of this SE, respectively.

3.2.1 Joint Structural Integrity 3.2.1.1 Acceptance Criteria Westinghouse has conducted extensive analyses to establish the necessary H* distance to resist pullout under normal operating and DBA conditions. Based on the physical geometry of the SG tubesheet, the NRC staff finds that pullout is the structural failure mode of interest, since the tubes are radially constrained against axial rupture by the presence of the tubesheet. The axial force which could produce pullout derives from the pressure end cap loads due to the primary-to-secondary pressure differentials associated with normal operating and DBA conditions. Westinghouse determined the needed H* distance on the basis of maintaining a factor of three against pullout under normal operating conditions and a factor of 1.4 against pullout under DBA conditions. The NRC staff finds that these are the appropriate safety factors to apply to demonstrate structural integrity, because they are consistent with the safety factors embodied in the structural integrity performance criteria in TS 6.8.4.i.b.1 and with the design basis; namely the stress limit criteria in the ASME Code,Section III.

The above approach equates tube pullout to gross structural failure which is conservative.

Should the pullout load be exceeded, tube slippage would be limited by the presence of adjacent tubes and support structures such that the tube would not be expected to pull out of the tubesheet.

The licensee has committed in Reference 1 to monitor for tube slippage as part of the SG inspection program. Under the proposed license amendment, as part of the SG inspection program, TS 6.9.1.1 OJ will require that the results of slippage monitoring be included as part of the 180-day report, which is required by TS 6.9.1.10. In addition, TS 6.9.1.1 OJ requires that should slippage be discovered, the implications of the discovery and corrective action shall be included in the report. The NRC staff finds that slippage is not expected to occur for the reasons discussed in this SE. However, in the unexpected event it should occur, it will be important to understand why it occurred so that the need for corrective action can be evaluated.

Therefore the NRC staff concludes that the commitment to monitor for slippage, and the accompanying reporting requirements are acceptable.

3.2.1.2 3-D Finite Element Analysis A detailed 3-D finite element analysis (FEA) of the lower SG assembly (consisting of the lower portion of the SG shell, the tubesheet, the channel head, and the divider plate that separates the hot- and cold-leg inlet plenums inside the channel head) was performed to calculate tubesheet displacements due to primary pressure acting on the primary face of the tubesheet

- 8 and SG channel head; secondary pressure acting on the secondary face of the tubesheet and SG shell; and the temperature distribution throughout the entire lower SG assembly. The calculated tubesheet displacements were used as input to the TITS interaction analysis evaluated in Section 3.2.1.3 below.

The tubesheet bore holes were not explicitly modeled. Instead, the tubesheet was modeled as a solid structure with equivalent material property values selected such that the solid model exhibited the same stiffness properties as the actual perforated tubesheet. This is a classical approach for analyzing perforated plates and, therefore the NRC staff finds it to be acceptable.

Two versions of the 3-D FEA model were used to support the subject license amendment request, a "reference model" documented in Reference 3, which was submitted to support a request for a one-time H* amendment for Salem Unit 1 in 2009 (Reference 4), and a "revised model" described in the technical support document, Reference 5. The revised model was submitted with a permanent H* amendment request from Duke Energy Carolinas, LLC for Catawba Nuclear Power Station Unit 2. The revised model described in Reference 5 is applicable to the Salem Unit 1 SGs. The reference 3-D FEA model was used to provide displacement input to the thick shell TITS interaction model described in Section 3.2.1.3.1 below. The revised 3-D FEA model was used to provide displacement input to the square cell TITS interaction model described in Section 3.2.1.3.2 below. The revised 3-D model employs a revised mesh near the plane of symmetry (perpendicular to the divider plate) to be consistent with the geometry of the square cell model such that the displacement output from the 3-D model can be applied directly to the edges of the square cell model.

Some non-U.S. units have experienced cracks in the weld between the divider plate and the stub runner attachment on the bottom of the tubesheet. Should such cracks ultimately cause the divider plate to become disconnected from the tubesheet, tubesheet vertical and radial displacements under operational conditions could be significantly increased relative to those for an intact divider plate weld. Although the industry believes that there is little likelihood that cracks such as those seen abroad could cause a failure of the divider plate weld, the 3-D FEA conservatively considered both the case of an intact divider plate weld and a detached divider plate weld to ensure a conservative analysis. The case of a detached divider plate weld was found to produce the most limiting H* values. In the reference model (Reference 3), a factor was applied to the 3-D FEA results to account for a non-functional divider plate, based on earlier sensitivity studies. The revised 3-D FEA model in Reference 5 assumes the upper 5 inches of the divider plate to be non-existent. The NRC staff finds this further improves the accuracy of the 3-D FEA for the assumed condition of a non-functional divider plate and therefore finds this acceptable.

3.2.1.3 TITS Interaction Model 3.2.1.3.1 Thick Shell Model The licensee describes in its LAR that resistance to tube pullout is the axial friction force developed between the expanded tube and the tubesheet over the H* distance. The friction force is a function of the radial contact pressure between the expanded tube and the tubesheet.

In the reference analysis (Reference 3), Westinghouse used classical thick-shell equations to model the interaction effects between the tubes and tubesheet under various pressure and

- 9 temperature conditions for purposes of calculating contact pressure (TITS interaction model).

Calculated displacements from the 3-D FEA of the lower tubesheet assembly (see Section 3.2.1.2 above) were applied to the thick shell model as input to account for the increment of tubesheet bore diameter change caused by the primary pressure acting on the primary face of the tubesheet and SG channel head, secondary pressure acting on the secondary face of the tubesheet and SG shell, and the temperature distribution throughout the entire lower SG assembly. However, the tubesheet bore diameter change from the 3-D FEA tended to be non uniform (eccentric) around the bore circumference. The thick shell equations used in the TITS interaction model are axisymmetric. Thus, the non-uniform diameter change from the 3-D finite element analyses had to be adjusted to an equivalent uniform value before it could be used as input to the TITS interaction analysis. A 2-D plane stress finite element model was used to define a relationship for determining a uniform diameter change that would produce the same change to average TITS contact pressure as would the actual non-uniform diameter changes from the 3-D finite element analyses.

Westinghouse identified a difficultly in applying this relationship to Model D5 SGs under MSLB conditions in Reference 3. Based on review of the reasons for this difficulty, the NRC staff developed questions relating to the conservatism of the relationship and whether the tubesheet bore displacement eccentricities are sufficiently limited such as to ensure that TITS contact is maintained around the entire tube circumference. This concern was applicable to all SG models with Alloy 600TT tubing. In Reference 6, the NRC staff documented a list of questions that would need to be addressed satisfactorily before the NRC staff would be able to approve a permanent H* amendment. These questions related to the technical justification for the eccentricity adjustment, the distribution of contact pressure around the tube circumference, and a new model under development by Westinghouse to address the aforementioned issue encountered with the Model D5 SGs.

The NRC staff conducted an audit at the Westinghouse Waltz Mill Site on June 14 and 15,2010 (Reference 7). The purpose of the audit was to gain a better understanding of the H* analysis pertaining to eccentricity, to review draft responses to the NRC staff's questions in Reference 6, and to determine which documents would need to be provided on the docket to support any future requests for a permanent H* amendment. Based on the audit, including review of pertinent draft responses to the questions in Reference 6, the NRC staff concluded that eccentricity does not appear to be a significant variable affecting either average TITS contact pressure at a given elevation or calculated values of H*. The NRC staff found that average contact pressure at a given elevation is primarily a fUnction of average bore diameter change at that elevation associated with the pressure and temperature loading of the tubesheet.

Accordingly, the NRC staff concluded that no adjustment of computed average bore diameter change considered in the thick shell model is needed to account for eccentricities computed by the 3-D FEA. The material reviewed during the audit revealed that computed H* values from the reference analyses continued to be conservative when the eccentricity adjustment factor is not applied.

3.2.1.3.2 Square Cell Model Documentation for the square cell model is contained in Reference 5, and the licensee's response to the NRC staff request for additional information (RAI) regarding Reference 5 is included with the subject amendment request for Salem Unit 1 (Attachment 5 of Reference 1).

- 10 The square cell model is a 2-D plane stress FEA model of a single square cell of the tubesheet with a bore hole in the middle and each of the four sides of the cell measuring one tube pitch in length. Displacement boundary conditions are applied at the edges of the cell, based on the displacement data from the revised 3-D FEA model. The model also includes the tube cross-section inside the bore. Displacement compatibility between the tube outer surface and bore inner surface is enforced except at locations where a gap between the tube and bore tries to occur.

This model was originally developed in response to the above-mentioned difficulty encountered when applying the eccentricity adjustment to Model 05 SGs TITS interaction analysis under MSLB conditions using the thick shell model. Early results with this model indicated significant differences compared to the thick shell model, irrespective of whether the eccentricity adjustment was applied to the thick shell model. The square cell model revealed a fundamental problem with how the results of the 3-D FEA model of the lower SG assembly were being applied to the tubesheet bore surfaces in the thick shell model. As discussed in Section 3.2.1.2 above, the perforated tubesheet is modeled in the 3-D FEA model as a solid plate whose material properties were selected such that the gross stiffness of the solid plate is equivalent to that of a perforated plate under the primary-to-secondary pressure acting across the thickness of the plate. This approach tends to smooth out the distribution of tubesheet displacements as a function of radial and circumferential location in the tubesheet, and ignores local variations of the displacements at the actual bore locations. These smoothed out displacements from the 3-D FEA results were the displacements applied to the bore surface locations in the thick shell model. The square cell model provides a means for post-processing the 3-D FEA results such as to account for localized variations of tubesheet displacement at the bore locations as part of TITS interaction analysis. Based on these findings, square cell models were developed for each of the SG model types, including the Model F SGs at Salem Unit 1.

The square cell model is applied to nine different elevations, from the top to the bottom of the tubesheet, for each tube and loading case analyzed. The square cell slices at each elevation are assumed to act independently of one another. TITS contact pressure results from each of the nine slices are used to define the contact pressure distribution from the top to the bottom of the tubesheet.

The resisting force to the applied end cap load, which is developed over each incremental axial distance from the top of the tubesheet, is the average contact pressure (over that incremental distance) multiplied by both the tubesheet bore surface area (equal to the tube outer diameter surface area over the incremental axial distance) and the coefficient of friction. The NRC staff reviewed the coefficient of friction used in the analysis and judges it to be a reasonable lower bound (conservative) estimate. The H* distance for each tube was determined by integrating the incremental friction forces from the top of the tubesheet to the distance below the top of the tubesheet where the friction force integral equaled the applied end cap load times the appropriate safety factor, as discussed in Section 3.2.1.1 of this SE.

The square cell model assumes as an initial condition that each tube is fully expanded against the tubesheet bore such that the outer tube surface is in contact with the inner surface of the tubesheet bore under room temperature, atmospheric pressure conditions, with zero residual contact pressure associated with the hydraulic expansion process. The NRC staff finds the assumption of zero residual contact pressure in all tubes to be a conservative assumption.

- 11 The limiting tube locations in terms of H* were determined during the reference analysis to lie along the plane of symmetry perpendicular to the divider plate. The outer edges of the square cell model conform to the revised mesh pattern along this plane of symmetry in the 3-D FEA model of the lower SG assembly, as discussed in Section 3.2.1.2 of this SE. Because the tubesheet bore holes were not explicitly modeled in the 3-D FEA, only the average displacements along each side of the square cell are known from the 3-D FEA. Three different assumptions for applying displacement boundary conditions to the edges of the square cell model were considered to allow for a range of possibilities about how local displacements might vary along the length of each side. The most conservative assumption, in terms of maximizing the calculated H* distance, was to apply the average transverse displacement uniformly over the length of each edge of the square cell.

Primary pressure acting on the tube inside surface, and crevice pressure 1 acting on both the tube outside surface and tubesheet bore surface, is not modeled directly as in the case of the thick shell model. Instead, the primary side (inside) of the tube is assumed to have a pressure equal to the primary pressure minus the crevice pressure. Note the crevice pressure varies as a function of the elevation being analyzed, as discussed in Section 3.2.1.4 of this SE.

Based on these findings, the NRC staff concludes that the square cell model provides for improved compatibility between the 3-D FEA model of the lower SG assembly and the TITS interaction model, more realistic and accurate treatment of the TITS joint geometry, and added conservatism relative to the thick shell model used in the reference analyses.

3.2.1.4 Crevice Pressure Evaluation The H* analyses postulate that interstitial spaces exist between the hydraulically expanded tubes and tubesheet bore surfaces. These interstitial spaces are assumed to act as crevices between the tubes and the tubesheet bore surfaces. The NRC staff finds that the assumption of crevices is conservative since the pressure inside the crevices acts to push against both the tube and the tubesheet bore surfaces, thus reducing contact pressure between the tubes and tubesheet.

For tubes which do not contain through-wall flaws within the thickness of the tubesheet, the pressure inside the crevice is assumed to be equal to the secondary system pressure. For tubes that contain through-wall flaws within the thickness of the tubesheet, a leak path is assumed to exist, from the primary coolant inside the tube, through the flaw, and up the crevice to the secondary system. Hydraulic tests were performed on several tube specimens that were hydraulically expanded against tubesheet collar specimens to evaluate the distribution of the crevice pressure from a location where through-wall holes had been drilled into the tubes to the top of the crevice location. The TITS collar specimens were instrumented at several axial locations to permit direct measurement of the crevice pressures. Tests were run for both normal operating and MSLB pressure and temperature conditions.

The NRC staff finds that the use of the drilled holes, rather than through-wall cracks, is conservative, since it eliminates any pressure drop between the inside of the tube and the 1 Although the tubes are in tight contact with the tubesheet bore surfaces, surface roughness effects are conservatively assumed to create interstitial spaces, which are effectively crevices, between these surfaces. See Section 3.2.1.4 of this SE for more information.

- 12 crevice at the hole location. This maximizes the pressure in the crevice at all elevations, thus reducing contact pressure between the tubes and tubesheet.

The crevice pressure data from these tests were used to develop a crevice pressure distribution as a function of normalized distance between the top of the tubesheet and the H* distance below the top of the tubesheet where the tube is assumed to be severed. These distributions were used to determine the appropriate crevice pressure at each axial location of the TITS interaction model. Since the test methodology is conservative, the NRC staff concludes that this determination of crevice pressure is acceptable.

Because the crevice pressure distribution is assumed to extend from the H* location, where crevice pressure is assumed to equal primary pressure, to the top of the tubesheet, where crevice pressure equals secondary pressure, an initial guess as to the H* location must be made before solving for H* using the TITS interaction model and 3-D finite element model.

The resulting new H* estimate becomes the initial estimate for the next H* iteration.

3.2.1.5 H* Calculation Process The calculation of H* consists of the following steps for each loading case considered:

1. Perform initial H* estimate (mean H* estimate) using the TITS interaction model and 3-D FEA models, assuming nominal geometric and material properties, and assuming that the tube is severed at the bottom of the tubesheet for purposes of defining the contact pressure distribution over the length of the TITS crevice. Two sets of mean H* estimates are pertinent to the proposed H* value, mean H* estimates calculated with the reference TITS interaction and 3-D FEA models (Reference 3) and mean H* estimates calculated with the square cell TITS interaction and revised 3-D FEA models (Reference 5). The highest calculated mean H* estimate (for the most limiting tube) from the reference analysis is 5.23 inches, for the most limiting case of normal operating conditions (with the associated factor of safety of 3 as evaluated in Section 3.2.1.1 of this SE). This estimate includes the adjustments in items 2 and 3 below. The highest calculated mean H* estimate with the square cell TITS interaction model, in conjunction with the revised 3-D lower SG FEA model, is 8.66 inches. The most limiting loading case for this revised analysis is still the normal operating condition (with its associated factor of safety of 3.0).

The NRC staff finds that the difference in mean H* estimates between the reference analysis and the revised analysis is dominantly due to the improved post-processing of the 3-D FEA model displacements for application to the TITS interaction model.

2. In the reference analysis (Reference 3), a 0.3-inch adjustment was added to the initial H*

estimate to account for uncertainty in the bottom of the tube expansion transition (BET) location relative to the top of the tubesheet, based on an uncertainty analysis on the BET for Model F SGs conducted by Westinghouse. This adjustment is not included in the revised H* analysis accompanying the subject amendment request, as discussed and evaluated in Section 3.2.1.5.1 of this SE.

3. In the reference analysis (Reference 3), for normal operating conditions only, an additional adjustment was added to the initial H* estimate to correct for the actual temperature distribution in the tubesheet compared to the linear distribution assumed in

- 13 the reference 3-D FEA analysis. This adjustment is no longer necessary, as discussed in Section3.2.1.2, since the temperature distributions throughout the tubesheet were calculated directly in the revised 3-D FEA supporting the current request for a permanent H* amendment.

4. Steps 1 through 3 yield a so-called "mean" estimate of H*, which is deterministically based. Step 4 involves a probabilistic analysis of the potential variability of H*, relative to the mean estimate, associated with the potential variability of key input parameters for the H* analyses. This leads to a "probabilistic" estimate of H*, which includes the mean estimate. The NRC staffs evaluation of the probabilistic analysis is provided in Sections 3.2.1.6 and 3.2.1.7 of this SE.

5. Add a crevice pressure adjustment to the probabilistic estimate of H* to account for the crevice pressure distribution which results from the tube being severed at the final H*

value, rather than at the bottom of the tubesheet. This step is discussed and evaluated in Section 3.2.1.5.2 of this SE.

6. A new step, step 6, was added to the H* calculation process since the Reference 3 analysis was performed to support the subject permanent amendment request. This step involves adding an additional adjustment to the probabilistic estimate of H* to account for the Poisson contraction of the tube radius due to the axial end cap load acting on each tube. This step is discussed and evaluated in Section 3.2.1.5.3 of this SE.

3.2.1.5.1 BET Considerations The diameter of each tube transitions from its fully expanded value to its unexpanded value near the top of the tubesheet (TIS). The BET region is located a short distance below the top of tubesheet so as to avoid any potential for over-expanding the tube above the TIS. In the reference H* analysis (Reference 3), a O.3-inch adjustment was added to the mean H* estimate to account for the BET location being below the TIS, based on an earlier survey of BET distances conducted by Westinghouse. This adjustment was necessary since the reference analysis did not explicitly account for the lack of contact between the tube and tubesheet over the BET distance.

BET measurements, based on eddy current testing, have subsequently been performed for all tubes at Salem Unit 1. These measurements showed that seven tubes in SG A had a maximum BET measurement of greater than one inch and were subsequently removed from service by plugging during RF014 (Reference 1).

However, the most recent H* analyses using the square cell TITS interaction model (Reference 5) has made the need for a BET adjustment unnecessary, as the square cell model shows a loss of contact pressure at the TTS that is greater than the possible variation in the BET location. The loss of contact pressure at the TIS shown in the square cell model (which is unrelated to BET location) is compensated for by a steeper contact pressure gradient than was shown previously in the thick shell model H* analysis. Based on these findings, the NRC staff concludes that the proposed H* value adequately accounts for the range of BET values at Salem Unit 1.

- 14 3.2.1.5.2 Crevice Pressure Adjustment As discussed in Section 3.2.1.5 of this SE, steps 1 through 4 of the H* calculation process leading to a probabilistic H* estimate are performed with the assumption that the tube is severed at the bottom of the tubesheet for purposes of calculating the distribution of crevice pressure as a function of elevation. If the tube is assumed to be severed at the initially computed H*

distance and steps 1 through 4 repeated, a new H* may be calculated which will be incrementally larger than the first estimate. This process may be repeated until the change in H* becomes small (convergence). Sensitivity analyses conducted with the thick shell model showed that the delta between the initial H* estimate and final (converged) estimate is a function of the initial estimate for the tube in question. This delta (i.e., the crevice pressure adjustment referred to in step 5 of Section3.2.1.5) was plotted as a function of the initial H*

estimate for the limiting loading case and tube radial location. Although the sensitivity study was conducted with the thick shell model, the deltas from this study were used in the Reference 5 (square cell model) analYSis to make the crevice pressure adjustment to H*.

Updating this sensitivity study would have been very resource intensive, requiring many new 2-D FEA square cell runs. In response to an NRC staff question as to whether it is conservative to rely on the existing sensitivity study, as opposed to updating it to reflect the square cell model, Westinghouse submitted an analysis (Reference 1) demonstrating that if the sensitivity study were updated, it would show that the crevice pressure adjustment H* is negative, not positive as is shown by the existing study. This is because the square cell model predicts a much longer zone (approximately 4 inches) of no TITS contact below the top of the tubesheet than does the thick shell model. Therefore. the crevice pressure must reduce from primary side pressure (at the iterative H* location) to secondary side pressure approximately 4 inches below the TTS.

This leads to higher predicted pressure differentials across the tube wall over the iterative H*

distance than exists during the initial iteration, when crevice pressure is initially assumed to vary from primary pressure at the very bottom of the tubesheet to secondary pressure at the very top of the tubesheet. Based on its review of the Westinghouse analysis, the NRC staff concludes that the positive crevice pressure adjustment to H* in the Reference 5 analysis, which is based on the existing sensitivity study, is conservative and that an updated sensitivity analysis based on use of the square cell model would show that a negative adjustment can actually be justified.

Thus, the NRC staff concludes the crevice pressure adjustment performed in support of the proposed H* amendment is conservative and acceptable.

3.2.1.5.3 Poisson Contraction Effect The axial end cap load acting on each tube is equal to the primary-to-secondary pressure difference multiplied by the tube's cross-sectional area. For purposes of resisting tube pullout under normal and accident conditions, the end cap loads used in the H* analyses are based on the tubesheet bore diameter, which the NRC staff finds to be a conservative assumption.

The axial end cap load tends to stretch the tube in the axial direction, but causes a slight contraction in the tube radius due to the Poisson's Ratio effect. This effect, by itself, tends to reduce the TITS contact pressure and, thus, to increase the H* distance. The axial end cap force is resisted by the axial friction force developed at the TITS joint. Thus, the axial end cap force begins to decrease with increasing distance into the tubesheet, reaching zero at a location

- 15 before the H* distance is reached. This is because the H* distances are intended to resist pullout under the end cap loads with the appropriate factors of safety applied as discussed in Section 3.2.1.1 of this SE.

A simplified approach was taken to account for the Poisson radial contraction effect. First, thick shell equations were used to estimate the reduction in contact pressure associated with application of the full end cap load, assuming none of this end cap load has been reduced by friction between the tube and the tubesheet. The TrrS contact pressure distributions determined in Step 4 of the H* calculation process in Section 3.2.1.5 were reduced by this amount. Second, the friction force associated with these reduced TrrS contact pressures were integrated with distance into the tubesheet, and the length of engagement necessary to react one times the end cap loading (Le., no safety factor applied) was determined. At this distance (termed attenuation distance by Westinghouse), the entire end cap loading was assumed to have been reacted by friction with the tubesheet, and the axial load in the tube below the attenuation distance was assumed to be zero. Thus, the TrrS contact pressures below the attenuation distance were assumed to be unaffected by the Poisson radial contraction effect.

Finally, a revised H* distance was calculated, where the TrrS contact pressures from Step 4 of Section 3.2.1.5 of this SE were reduced only over the attenuation distance.

The NRC staff finds the simplified approach for calculating the H* adjustment for the Poisson contraction effect to contain significant conservatism relative to a more detailed approach.

Regarding the safety factor of unity assumption, Westinghouse states that it is unrealistic to apply a safety factor to a physical effect such as Poisson's ratio. The NRC staff has not reached a conclusion on this point. However, irrespective of whether a safety factor is applied to the Poisson's contraction effect (consistent with Section 3.2.1.1 above), the NRC staff concludes there is ample conservatism embodied in the proposed H* distance to accommodate the difference.

3.2.1.6 Acceptance Standard - Probabilistic Analysis The purpose of the probabilistic analysis is to develop an H* distance that ensures with a probability of 95 percent that the population of tubes will retain margins against pullout consistent with criteria evaluated in Section 3.2.1.1 of this SE, assuming all tubes to be completely severed at their H* distance. The NRC staff finds this probabilistic acceptance standard is consistent with what the NRC staff has approved previously and is acceptable.

For example, the upper voltage limit for the voltage based tube repair criteria in NRC Generic Letter 95-05 (Reference 8) employs a consistent criterion. The NRC staff also notes that use of the 95 percent probability criterion ensures that the probability of pullout of one or more tubes under normal operating conditions and conditional probability of pullout under accident conditions is well within tube rupture probabilities that have been considered in probabilistic risk assessments (References 9 and 10).

In terms of the confidence level that should be attached to the 95 percent probability acceptance standard, it is industry practice for SG tube integrity evaluations, as embodied in industry guidelines, to calculate such probabilities at a 50 percent confidence level. The NRC staff has been encouraging the industry to revise its guidelines to call for calculating such probabilities at a 95 percent confidence level when performing operational assessments and a 50 percent confidence level when performing condition monitoring (Reference 11). In the meantime, the

- 16 calculated H* distances supporting the subject amendment request have been evaluated at the 95 percent confidence level, as recommended by the NRC staff.

Another issue relating to the acceptance standard for the probabilistic analysis is determining what population of tubes needs to be analyzed. For accidents such as MSLB or Feedline Break (FLB), the NRC staff and licensee agree that the tube population in the faulted SG is of interest, since it is the only SG that experiences a large increase in the primary-to-secondary pressure differential. However, normal operating conditions were found to be the most limiting in terms of meeting the tube pullout margins in Section 3.2.1.1 of this SE. For normal operating conditions, tubes in all SGs at the plant are subject to the same pressures and temperatures. Although there is not a consensus between the NRC staff and industry on which population needs to be considered in the probabilistic analysis for normal operating conditions, the calculated H*

distances for normal operating conditions supporting the subject amendment request are 95 percent probability/95 percent confidence estimates based on the entire tube population for the plant, consistent with the NRC staff's recommendation.

Based on the above, the NRC staff concludes that the proposed H* distance in the subject license amendment request is based on acceptable probabilistic acceptance standards evaluated at acceptable confidence levels.

3.2.1.7 Probabilistic Analyses 3.2.1 .7.1 Reference Analvses Sensitivity studies were conducted during the reference analyses (Reference 3) and demonstrated that H* was highly sensitive to the potential variability of the coefficients of thermal expansion (CTE) for the Alloy 600 tubing material and the SA-50B Class 2a tubesheet material. Given that no credit was taken in the reference H* analyses (Reference 3) for residual contact pressure associated with the tube hydraulic expansion process,2 the sensitivity of H* to other geometry and material input parameters was judged by Westinghouse to be inconsequential and was ignored, with the exception of Young's modulus of elasticity (a measure of stiffness) for the tube and tubesheet materials. Although the Young's modulus parameters were included in the reference H* analyses sensitivity studies, these parameters were found to have a weak effect on the computed H*. Based on its review of the analysis models and its engineering judgment, the NRC staff finds that the sensitivity studies adequately capture the input parameters which may significantly affect the value of H*. This conclusion is based, in part, on no credit being taken for RCP during the reference H* analyses.

These sensitivity studies were used to develop influence curves describing the change in H*,

relative to the mean H* value estimate (see Section 3.2.1.5 above), as a function of the variability of each CTE parameter and Young's modulus parameter, relative to the mean values of CTE and Young's Modulus. Separate influence curves were developed for each of the four input parameters. The sensitivity studies showed that of the four input parameters, only the CTE parameters for the tube and tubesheet material had any interaction with one another.

A combined set of influence curves containing this interaction effect were also created.

2 Residual contact pressures are sensitive to variability of other input parameters.

- 17 Two types of probabilistic analyses were performed independently in the reference analyses.

One was a simplified statistical approach utilizing a "square root of the sum of the squares" method and the other was a detailed statistical (Monte Carlo) sampling approach. The NRC staff's review of the reference analysis relied on the Monte Carlo analysis, which provides the most realistic treatment of uncertainties. The NRC staff reviewed the implementation of probabilistic analyses in the reference analyses and questioned whether the H* influence CIJrves had been conservatively treated. To address this concern, new H* analyses were performed as documented in References 12 and 13. These analyses made direct use of the H* influence curves in a manner that the NRC staff finds to be acceptable.

The revised reference analyses in Reference 12 divided the tubes by sector location within the tube bundle and all tubes were assumed to be at the location in their respective sectors where the initial value of H* (based on nominal values of material and geometric input parameters) was at its maximum value for that sector. The H* influence curves discussed above, developed for the most limiting tube location in the tube bundle, were conservatively used for all sectors.

The revised reference analyses also addressed a question posed by the NRC staff concerning the appropriate way to sample material properties for the tubesheet, whose properties are unknown but do not vary significantly for a given SG, in contrast to the tubes whose properties tend to vary much more randomly from tube to tube in a given SG. This issue was addressed by a staged sampling process where the tubesheet properties were sampled once and then held fixed, while the tube properties were sampled a number of times equal to the SG tube population. This process was repeated 10,000 times, and the maximum H* value from each repetition was rank ordered. The final H* value was selected from the rank ordering to reflect a 95 percent probability value at the desired level of confidence for a single SG tube population or all SG population, as appropriate. The NRC staff concludes that this approach addresses the NRC staff's question in a realistic fashion and is acceptable.

The reference analyses in References 3 and 12 indicated normal operating conditions (with associated safety factor of 3) to be the limiting case for determining H* for ModelF SGs.

As discussed earlier in Section3.2.1.5, subsequent analyses with the more accurate square cell model and revised 3-D FEA model (due to the improved displacement compatibility between the two models) show that normal operating conditions (with associated safety factor of 3) to still be the limiting case for the Model F SGs.

3.2.1.7.2 Revised Analvses to Reflect Square Cell and Revised 3-D FEA Models New Monte Carlo analyses using the square cell model to evaluate the statistical variability of H* due to the CTE variability for the tube and tubesheet materials were not performed. This was because such an approach would have been extremely resource intensive and because a simpler approach involving good approximation was available. The simplified approach involved using the results of the Monte Carlo analyses from the reference analysis, which are based on the thick shell TITS interaction model, to identify CTE values for the tube and tubesheet associated with the probabilistic H* values near the desired rank ordering. Tube CTE values associated with the upper 10 percent rank order estimates are generally negative variations from the mean value whereas tubesheet CTE values associated with the higher ranking order estimates are generally positive variations from the mean value. For the upper 10 percent of the Monte Carlo results ranking order, a combined uncertainty parameter, "alpha,"

was defined as the square root of the sum of the squares of the associated tube and tubesheet

- 18 CTE values for each Monte Carlo sample. Alpha was plotted as a function of the corresponding H* estimate and separately as a function of rank order. Each of these plots exhibited well defined "break lines," representing the locus of maximum H* estimates and maximum rank orders associated with a given value of alpha. From these plots, three paired sets of tube and tubesheet CTE values, located near the break line, were selected. One of these pairs was for the rank order corresponding to an upper 95 percent probability and 95 percent confidence value for H* on a whole plant basis, which the NRC staff finds is appropriate for normal operating conditions (see Section 3.2.1.6 above). These CTE values were then input to the lower SG assembly 3-D FEA model and the square cell model to yield probabilistic H* estimates which approximate the H* values for these same rank orderings, had a full Monte Carlo been performed with the square cell and revised 3-D FEA models. These H* estimates were then plotted as a function of rank ordering, allowing the interpolation of H* values at the other rank orders. The resulting 95/95 upper bound H* estimate is 14.04 inches, which compares to the mean estimate of 8.66 inches as discussed in Section 3.2.1.5 above. With adjustments for Poisson's contraction (see Section 3.2.1.5.3 above) and crevice pressure (Section 3.2.1.5.2 above), the final 95/95 upper bound H* estimate is 15.21 inches.

The NRC staff has determined that the above break line approach is a very good approximation of what an actual Monte Carlo would show. A perfect approximation would mean that if, hypothetically, one were to perform a square cell analysis for each paired set of tube and tubesheet CTE values associated with the top 10 percent of rank orders, and plot the resulting H* values versus the original rank ordering associated with the CTE couple, the calculated H*

values should monotonically increase from rank order to rank order. Westinghouse performed additional square cell analyses with CTE pairs for five consecutive rank orders for both Model D5 and Model F SGs. The results showed deviations from monotonically increasing values of H* with rank order to be on the order of only 0.3 inches for the Model D5 SGs and 0.1 inches for the Model F SGs. Therefore, the NRC staff concludes that the use of the break line approach adds little imprecision to the probabilistic H* estimates and is acceptable.

3.2.1.8 Coefficient of Thermal Expansion During operation, a large part of contact pressure in a SG TITS joint is derived from the difference in CTE between the tube and tubesheet. As discussed in Section 3.2.1.7 above, the calculated value of H* is highly sensitive to the assumed values of these CTE parameters.

However, CTE test data acquired by an NRC contractor, Argonne National Laboratory (ANL),

suggested that CTE values may vary substantially from values listed in the ASME Code for design purposes. In Reference 14, the NRC staff highlighted the need to develop a rigorous technical basis for the CTE values, and their potential variability, to be employed in future H*

analyses.

In response, Westinghouse had a subcontractor review the CTE data in question, determine the cause of the variance from the ASME Code CTE values, and provide a summary report (Reference 15). Analysis of the CTE data in question revealed that the CTE variation with temperature had been developed using a polynomial fit to the raw data, over the full temperature range from 75 OF to 1300 OF. The polynomial fit chosen resulted in mean CTE values that were significantly different from the ASME Code values from 75 OF to about 300 oF.

When the raw data was reanalyzed using the locally weighted least squares regression

- 19 (LOWESS) method, the mean CTE values determined were in good agreement with the established ASME Code values.

Westinghouse also formed a panel of licensee experts to review the available CTE data in open literature, review the ANL provided CTE data, and perform an extensive CTE testing program on Alloy 600 and SA-508 steel material to supplement the existing data base. Two additional sets of CTE test data (different from those addressed in the previous paragraph) had CTE offsets at low temperature that were not expected. Review of the test data showed that the first test, conducted in a vacuum, had proceeded to a maximum temperature of approximately 1300 of, which changed the microstructure and the CTE of the steel during decreasing temperature conditions. As a result of the altered microstructure, the CTE test data generated in the second test, conducted in air, was also invalidated. As a result of the large "dead band" region and the altered microstructure, both data sets were excluded from the final CTE values obtained from the CTE testing program. The test program included multiple material heats to analyze chemistry influence on CTE values and repeat tests on the same samples were performed to analyze for test apparatus influence. Because the tubes are strain hardened when they are expanded into the tubesheet, strain hardened samples were also measured to check for strain hardening influence on CTE values.

The data from the test program was combined with the ANL data that was found to be acceptable, and the data obtained from the open literature search. A statistical analysis of the data uncertainties was performed by comparing deviations to the mean values obtained at the applicable temperatures. The correlation coefficients obtained indicated a good fit to a normal distribution, as expected. Finally, an evaluation of within-heat variability was performed due to increased data scatter at low temperatures. The within-heat variability assessment determined that the increase in data scatter was a testing accuracy limitation that was only present at low temperature. The CTE report is included as Appendix A to Reference 3.

The testing showed that the nominal ASME Code values for Alloy 600 and SA-508 steel were both conservative relative to the mean values from all the available data. Specifically, the CTE mean value for Alloy 600 was greater than the ASME Code value and the CTE mean value for SA-508 steel was smaller than the ASME Code value. Thus, the H* analyses utilized the ASME Code values as mean values in the H* analyses. The NRC staff finds this to be conservative because it tends to lead to an over-prediction of the expansion of the tubesheet bore and an under-prediction of the expansion of the tube, thereby resulting in an increase in the calculated H* distance. The statistical variances of the CTE parameters from the combined data base were utilized in the H* probabilistic analysis.

Based on its review of the Westinghouse CTE program, the NRC staff concludes that the CTE values used in the H* analyses are fully responsive to the concerns stated in Reference 14 and are acceptable.

3.2.2 Leakage Considerations Operational leakage integrity is assured by monitoring primary-to-secondary leakage relative to the applicable TS limiting condition for operation limits in TS 3.4.6.2, "Reactor Coolant System Operational Leakage." However, it must also be demonstrated that the proposed TS changes do not create the potential for leakage during DBA to exceed the accident leakage performance

- 20 criteria in TS S.8.4.i.b.2, including the leakage values assumed in the plant licensing basis accident analyses.

If a tube is assumed to contain a 100 percent through-wall flaw some distance into the tubesheet, a potential leak path between the primary and secondary systems is introduced between the hydraulically expanded tubing and the tubesheet. The leakage path between the tube and tubesheet has been modeled by the licensee's contractor, Westinghouse, as a crevice consisting of a porous media. Using Darcy's model for flow through a porous media, leak rate is proportional to differential pressure and inversely proportional to flow resistance. Flow resistance is a direct function of viscosity, loss coefficient, and crevice length.

Westinghouse performed leak tests of tube-to-tubesheet joint mockups to establish loss coefficient as a function of contact pressure. A large amount of data scatter, however, precluded quantification of such a correlation. In the absence of such a correlation, Westinghouse has developed a leakage factor relationship between accident induced leak rate and operational leakage rate, where the source of leakage is from flaws located at or below the H* distance.

Using the Darcy model, the leakage factor for a given type accident is the product of four quantities. The first quantity is the ratio of the maximum primary-to-secondary pressure differential during the accident to the normal operating condition pressure differential.

The second quantity is the ratio of primary coolant viscosity at normal operating temperature to primary coolant viscosity at accident condition temperature. The third quantity is the ratio of crevice length under normal operating conditions to crevice length under accident condition.

This third ratio equals 1, provided it can be shown that positive contact pressure is maintained along the entire H* distance for both normal operating and worst case accident condition.

The fourth quantity is the ratio of loss coefficient under normal operating conditions to loss coefficient under the accident condition. Although the absolute value of these loss coefficients is not known, Westinghouse has assumed that the loss coefficient is constant with contact pressure, as thus the ratio is equal to 1. The NRC staff finds that this is a conservative assumption, provided there is a positive contact pressure for both conditions along the entire H*

distance and provided that contact pressure increases at each axial location along the H*

distance when going from normal operating to accident conditions. Both assumptions were confirmed to be valid in the H* analyses.

Leakage factors were calculated for design-basis accidents exhibiting a significant increase in primary-to-secondary pressure differential, including MSLB, FLB, locked rotor, and control rod ejection. The design basis FLB heat-up transient was found to exhibit the highest leakage factor, 2.49, meaning that it is the transient expected to result in the largest increase in leakage relative to normal operating conditions.

The latest H* analyses by Westinghouse (Reference 5) continued to show an increasing TrrS contact pressure when going from normal operating to MSLB conditions. The new analyses used the revised 3-D finite element model of the lower SG assembly and the new square cell model, discussed in Section 3.2.1.3.2 of this SE.

In Reference 1, the licensee provided a description of how the leakage factor will be used to satisfy TS S.8.4.i.a for condition monitoring and TS S.8.4.i.b.2 regarding performance criteria for

- 21 accident induced leakage:

For the condition monitoring (eM) assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2. 16 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment (OA), the difference in the leakage between the allowable leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.16 and compared to the observed operational leakage. An administrative limit will be established to not exceed the calculated value.

That this commitment is not part of the Salem Unit 1 license is consistent with the fact that details of how condition monitoring and operational assessments are performed are generally not included as part of the operating license, including the technical specifications. Extensive industry guidance on conducting condition monitoring and operational assessments is available as part of the industry NEI 97-06 initiative (Reference 16). The above commitment ensures that plant procedures address the above leakage factor issues as they do industry guidelines.

The subject amendment request includes reporting requirements relating to operational leakage existing during the cycle preceding each SG inspection and condition monitoring assessment, and the associated potential for accident induced leakage from the lower portion of the tubesheet below the H* distance. These reporting requirements will allow the NRC staff to monitor how the leakage factor is actually being used, and thus are acceptable. The licensee provided another commitment in Reference 1 that states they will monitor for tube slippage as part of their SG Program.

PSEG will monitor for tube slippage as part of the steam generator tube inspection program. The results of this monitoring will be included in the report required by TS 6.9. 1. 1OJ.

As stated in the commitment, any findings relative to this commitment will be reported as part of TS 6.9.1.1 OJ. These reporting requirements will allow the NRC staff to monitor the results of the slippage inspections and thus are acceptable.

3.3 Summary and Conclusions Since the initial proposal for a permanent H* amendment in 2005, the supporting technical analyses have undergone substantial revision and refinement to address NRC staff questions and issues. The current analyses supporting the proposed permanent amendment still embody uncertainties and issues (e.g., should a factor of safety be applied to the Poisson's contraction effect) as discussed throughout this SE. However, it is important to acknowledge that there are significant conservatisms in the analyses. Some examples, also discussed elsewhere in this SE, include taking no credit for residual contact pressures associated with the hydraulic tube expansion process, the assumed value of 0.2 for coefficient of friction between the tube and tubesheet, and taking no credit for constraint against pullout provided by adjacent tubes and support structures. The NRC staff has evaluated the potential impact of the uncertainties and concludes these uncertainties to be adequately bounded by the significant conservatism within the analyses and proposed H* distance.

- 22 The NRC staff finds the proposed changes to the TSs of Salem Unit 1 ensure that tube structural and leakage integrity will be maintained, with structural safety margins consistent with the design basis and with leakage integrity within assumptions employed in the licensing basis accident analyses, without undue risk to public health and safety. Based on this finding, the NRC staff further concludes that the proposed amendment meets the requirements of 10 CFR 50.92 and 10 CFR 50.36 and. thus. the proposed amendment is acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the New Jersey State Official was notified of the proposed issuance of the amendments. The State Official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts. and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on January 22,2013 (78 FR 4474). Accordingly. the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Pursuant to 10 CFR 51.22(b}. no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above. that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributor: Andrew Johnson Date: March 28, 2013

- 23

References:

1. PSEG Nuclear LLC. (PSEG) letter LR-N12-01 08, "License Amendment Request:

Revision To Technical Specification (TS) 6.8.4.1, "Steam Generator (SG) Program," and Technical Specifications 6.9.1.10, "Steam Generator Tube Inspection Report," for a Permanent Alternate Repair Criteria," dated May 8,2012, Agencywide Documents Access and Management System (ADAMS) Accession No. ML12130A169.

2. NRC letter to PSEG, "Salem Nuclear Generating Station, Unit No.1 - Issuance of Amendment Re: Steam Generator Inspection Scope and Repair Requirements (TAC No.

ME2374)," dated March 29,2010, ADAMS Accession No. ML100570452.

3. Westinghouse Electric Company LLC, WCAP-17071-P (Proprietary) and WCAP-17071 NP (Non- Proprietary), Rev. 0, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F),"

dated April 2009, ADAMS Accession No. ML092960586.

4. PSEG letter LR-N09-0232, "License Amendment Request, Revision to Technical specification 6.8.4.i, "Steam Generator (SG) Program," for One-Time (Interim) Alternate Repair Criteria (H*)," dated October 8, 2009, ADAMS Accession No. ML092960584.

5. Westinghouse Electric Company (WEC) report, WCAP-17330-P (Proprietary) and WCAP-17330-NP (Non- Proprietary), Rev. 1, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model D5)," dated November 2010; ADAMS Accession Nos. ML11188A109 (Proprietary) and ML11188A108 (Non Proprietary). This report was enclosed with a permanent H* amendment request submitted by Duke Energy Carolinas, LLC for Catawba Nuclear Power Station Unit 2.

6. NRC letter to Southern Nuclear Operating Company, "VogUe Electric Generating Plant, Units 1 and 2, Transmittal of Unresolved Issues Regarding Permanent Alternate Repair Criteria for Steam Generators," dated November 23,2009, ADAMS Accession No. ML093030490.

7. NRC memorandum, R. Taylor to G. Kulesa, "Vogtle Electric Generating Plant Audit of Steam Generator H* Amendment Reference Documents," dated July 9,2010, ADAMS Accession No. ML101900227.

8. NRC Generic Letter 95-05, "Voltage Based Alternate Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking,"

dated August 3, 1995, ADAMS Accession No. ML031070113.

9. NUREG-0844, "NRC Integrated Program for the Resolution of Unresolved Safety Issues A-3, A-4, and A-5 Regarding Steam Generator Tube Integrity," September 1988.

10. NUREG-1570, "Risk Assessment of Severe Accident-Induced Steam Generator Tube Rupture," March 1998.

- 24

11. NRC Meeting Minutes, "Summary of the January 8, 2009, Category 2 Public Meeting with the Nuclear Energy Institute (NEI) and Industry to Discuss Steam Generator Issues," dated February 6, 2009, ADAMS Accession No. ML090370782.

12. WEC letter, LTR-SGMP-09-1 OO-P (Proprietary) and LTR-SGMP-09-1 OO-NP (Non Proprietary) "Response to NRC Request for Additional Information on H*; Model F and D5 Steam Generators," dated August 12, 2009, ADAMS Accession Number ML101730391.

13. SNC letter NL-09-1317, August 28,2009, transmitting WEC letter LTR-SGMP-09-104-P Attachment "White Paper on Probabilistic Assessment of H*," dated August 13, 2009, ADAMS Accession No. ML092450029.

14. NRC letter to Wolf Creek Nuclear Operating Corporation, Wolf Creek Generating Station - Withdrawal of License Amendment Request on Steam Generator tube Inspections," dated February 28,2008, ADAMS Accession No. ML080450185.

15. Nuclear Energy Institute (NEI) letter dated July 7,2008, NRC ADAMS Accession No. ML082100086, transmitting Babcock and Wilcox Limited Canada letter 2008-06-PK-001, "Re-assessment of PMIC measurements for the determination of CTE of SA 508 steel,"

dated June 6,2008, ADAMS Accession No. ML082100097.

16. NEI 97-06, Revision 3, "Steam Generator Program Guidelines," dated January 2011, ADAMS Accession No. ML111310708.

March 28, 2013 Mr. Thomas Joyce President and Chief Nuclear Officer PSEG Nuclear LLC P.O. Box 236, N09 Hancocks Bridge, NJ 08038

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NO.1-ISSUANCE OF AMENDMENT RE: REVISION TO TECHNICAL SPECIFICATION 6.8.4.i, "STEAM GENERATOR PROGRAM," AND TECHNICAL SPECIFICATION 6.9.1.10, "STEAM GENERATOR TUBE INSPECTION REPORT," FOR A PERMANENT ALTERNATE REPAIR CRITERIA (TAC NO ME8578)

Dear Mr. Joyce:

The Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment No. 303 to Renewed Facility Operating License (FOL) No. DPR-70 for the Salem Nuclear Generating Station (Salem), Unit No.1, in response to your application dated May 8, 2012.

The amendment approves changes to TS Section 6.8.4.i, "Steam Generator (SG) Program,"

and TS 6.9.1.10, "Steam Generator Tube Inspection Report." The approved changes establish permanent SG tube alternate repair criteria for tubing flaws located in the lower region of the tubesheet. The approved changes replace similar criteria for Salem that were approved on an interim basis during Refueling Outage 20 for the subsequent operating cycles, until the next scheduled SG tube inspection.

Our safety evaluation (SE) is also enclosed. Section 3.2.2 of the SE describes the NRC staff's evaluation of the regulatory commitments proposed by the licensee in the amendment application. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, IRA!

John D. Hughey, Project Manager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-272

Enclosures:

1. Amendment No. 303 to Renewed License No. DPR-70

2. Safety Evaluation cc w/encls: Distribution via ListServ DISTRIBUTION:

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