ML112580517

Issuance of Amendment Steam Generator Tube Inspection Alternate Repair Criteria

ML112580517
Person / Time
Site:	Millstone
Issue date:	10/07/2011
From:	Sanders C Plant Licensing Branch 1
To:	Heacock D Dominion Nuclear Connecticut
Sandeers, Carleen, NRR/DORL, 415-1603
References
TAC ME5389
Download: ML112580517 (35)

Text

'UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 October 7, 2011 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Nuclear Connecticut, Inc, Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711

SUBJECT:

MILLSTONE POWER STATION, UNIT NO.3 - ISSUANCE OF AMENDMENT RE: STEAM GENERATOR TUBE INSPECTION ALTERNATE REPAIR CRITERIA (TAC NO. ME5389)

Dear Mr. Heacock:

The Commission has issued the enclosed Amendment No. 252 to Renewed Facility Operating License No. NPF-49 for the Millstone Power Station, Unit No.3, in response to your application dated January 20, 2011.

The amendment revises Technical Specification (TS) Section 6.8.4.g, "Steam Generator (SG)

Program," to exclude a portion of the tubes below the top of the SG tubesheet from periodic SG inspections for Refueling Outage 14 and the subsequent operating cycle. In addition, this amendment revises TS Section 6.9.1.7, "Steam Generator Tube Inspection Report," to remove reference to the previous interim alternate repair criteria and provide reporting requirements specific to the current temporary alternate repair criteria.

A copy of the related Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely,

~,~ J~

Carleen Plant Lice'~'ing

'anders. Project Manager Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-423

Enclosures:

1. Amendment No. 252 to NPF-49

2. Safety Evaluation cc w/encls: Distribution via Listserv

UNrrED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555"()001 DOMINION NUCLEAR CONNECTICUT, INC., ET AL.

DOCKET NO. 50-423 MILLSTONE POWER STATION, UNIT NO.3 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 252 Renewed License No. NPF-49

1. The Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by the applicant dated January 20, 2011, 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 10 CFR Chapter I; B. The facility will operate in conformity with the 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; 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, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License 1\10. NPF-49 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No.252 ,and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated in the license. DNC 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 issuance, and shall be implemented within 30 days of issuance and prior to Mode 5 startup.

FOR THE NUCLEAR REGULATORY COMMISSION

~

m~

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

Attachment:

Changes to the License and Technical Specifications Date of Issuance: October 7, 2011

ATTACHMENT TO LICENSE AMENDMENT NO. 252 RENEWED FACILITY OPERATING LICENSE NO. NPF-49 DOCKET NO. 50-423 Replace the following page of the Renewed Facility Operating License with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove 4

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

Remove Insert 6-17b 6-17b 6-17c 6-17c 6-21 6-21 6-21a 6-21a

-4 (2) Technical Specifications The Technical Specifications contained in Appendix A, revised through Amendment NO.252and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto are hereby incorporated into the license. DNC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) DNC shall not take any action that would cause Dominion Resources, Inc.

(DRI) or its parent companies to void, cancel, or diminish DNC's commitment to have sufficient funds available to fund an extended plant shutdown as represented in the application for approval of the transfer of the licenses for MPS Unit NO.3.

(4) Immediately after the transfer of interests in MPS Unit NO.3 to DNC, the amount in the decommissioning trust fund for MPS Unit NO.3 must, with respect to the interest in MPS Unit No.3, that DNC would then hold, be at a level no less than the formula amount under 10 CFR 50.75.

(5) The decommissioning trust agreement for MPS Unit No.3 at the time the transfer of the unit to DNC is effected and thereafter is subject to the following:

(a) The decommissioning trust agreement must be in a form acceptable to the NRC.

(b) With respect to the decommissioning trust fund, investments in the securities or other obligations of Dominion Resources, Inc. or its affiliates or subsidiaries, successors, or assigns are prohibited.

Except for investments tied to market indexes or other non-nuclear-sector mutual funds, investments in any entity owning one or more nuclear power plants are prohibited.

(c) The decommissiong trust agreement for MPS Unit No.3 must provide that no disbursement or payments from the trust, other than for ordinary administrative expenses, shall be made by the trustee until the trustee has first given the Director of the Office of Nuclear Reactor Regulation 30 days prior written notice of payment. The decommissioning trust agreement shall further contain a provision that no disbursements or payments from the trust shall be made if the trustee receives prior written notice of objection from the NRC.

(d) The decommissioning trust agreements must provide that the agreement can not be amended in any material respect without 30 days prior written notification to the Director of the Office of Nuclear Reactor Regulation.

Renewed License No. NPF-49 Amendment N0252

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

Leakage is not to exceed 500 gpd per So.

3. The operational LEAKAGE perfonnance criterion is specified in RCS LCO 3.4.6.2, "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 tube repair criteria shall be applied as an alternative to the 40% depth-based criteria:

1. For Refueling Outage 14 and the subsequent operating cycle, tubes with service-induced flaws located greater than 15.2 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 15.2 inches below the top of the tubesheet shall be plugged upon detection.

MILLSTONE - UNIT 3 6-17b Amendment No. 238, 245, 249252

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

d. Provisions for SG tube inspections: Periodic SG tube inspections shall be perfonned. The number and portions of the tubes inspected and methods of inspection shall be perfonned 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 Refueling Outage 14 and the subsequent operating cycle, portions of the tube below 15.2 inches below the top of the tubesheet are excluded from this requirement.

The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.l , 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 perfonned to detennine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to detennine 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 infonnation such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not MILLSTONE - UNIT 3 6-17c Amendment No. 69, +86, ~, ~

243,245,-249 252

ADMINISTRATIVE CONTROLS 6.9.1.6.c The core operating limits shall be determined so that all applicable limits (e.g. fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as SHUTDOWN MARGIN, and transient and accident analysis limits) of the safety analysis are met.

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

STEAM GENERATOR TUBE INSPECTION REPORT 6.9.1.7 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with TS 6.KA.g, Steam Generator (SG)

Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

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

h. The effective plugging percentage for all plugging in each So,

1. During Refueling Outage 14 and the subsequent operating cycle, 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, MILLSTONE - UNIT 3 6-21 Amendment No. ~, 4G, W, 69, +G4,

~,~,~,~,~,245,249252

ADMINISTRATIVE CONTROLS STEAM GENERATOR TUBE INSPECTION REPORT (Continued)

J. During Refueling Outage 14 and the subsequent operating cycle, the calculated accident induced leakage rate from the portion of the tubes below 15.2 inches from the top of the tubesheet for the most limiting accident in the most limiting So. In addition, if the calculated accident induced leakage rate from the most limiting accident is less than 2.49 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined; and

k. During Refueling Outage 14 and the subsequent operating cycle, 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, one copy to the Regional Administrator Region I, and one copy to the NRC Resident Inspector, within the time period specified for each report.

6.10 Deleted.

6.11 RADIATION PROTECTION PROGRAM 6.11.1 Procedures for personnel radiation protection shall be prepared consistent with the requirements of 10 CFR Part 20 and shall be approved, maintained, and adhered to for all operations involving personnel radiation exposure.

6.12 HIGH RADIATION AREA As provided in paragraph 20.160 I (c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph 20.1601 (a) and (b) of 10 CFR Part 20:

MILLSTONE - UNIT 3 6-21a Amendment No. m, 245, 249252

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 252 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-49 DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION, UNIT NO.3 DOCKET NO. 50-423

1.0 INTRODUCTION

By letter dated January 20, 2011 (Reference 1), Dominion Nuclear Connecticut, Inc. (DNC or the licensee), submitted a request for changes to the Millstone Power Station, Unit NO.3 (MPS3) Technical Specifications (TSs). The proposed changes would revise TS Section 6.8.4.g, "Steam Generator (SG) Program," to exclude a portion of the tubes below the top of the SG tubesheet from periodic SG inspections for Refueling Outage 14 and the subsequent operating cycle. In addition, these proposed changes would revise TS Section 6.9.1.7, "Steam Generator Tube Inspection Report," to remove reference to the previous interim alternate repair criteria and provide reporting requirements specific to the current temporary alternate repair criteria.

The January 20, 2011, letter includes an enclosure which is being withheld from public disclosure because it contains proprietary information. A non-proprietary version is available for public consumption (Reference 7).

2.0 BACKGROUND

MPS3 has four Model F SGs that were designed and fabricated by Westinghouse Electric Company, LLC (Westinghouse). There are 5,626 Alloy 600 thermally treated (TT) tubes in each SG, each with an 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 21.23-inch thick tubesheet and are welded to the tubesheet at each tube end. Until the fall of 2004, no instances of stress corrosion cracking (SCC) affecting the tubesheet region of thermally treated Alloy 600 tubing had been reported at any nuclear power plants in the United States.

Enclosure

- 2 In the fall of 2004, crack-like indications were found in tubes in the tubesheet region of Catawba Nuclear Station, Unit No.2 (Catawba), which has Westinghouse Model 05 SGs. Like MPS3, the Catawba SGs use thermally treated Alloy 600 tUbing that is hydraulically expanded against the tubesheet. The crack-like indications at Catawba were found in a tube overexpansion (OXP), in the tack expansion region, and near the tube-to-tubesheet weld.

An OXP is created when the tube is expanded into a tubesheet bore hole that is not perfectly round. These out-of-round conditions were created during the tubesheet drilling process by conditions such as drill bit wandering or chip gouging.

The tack expansion is an approximately 1-inch long expansion at each tube end. The purpose of the tack expansion is to facilitate performing the tube-to-tubesheet weld, which is made prior to the hydraulic expansion of the tube over the full tubesheet depth.

Since the initial findings at Catawba in the fall of 2004, other nuclear plants have also found crack-like indications in tubes within the tubesheet. These plants include Braidwood Station, Unit No.2; Byron Station, Unit No.2; Comanche Peak Steam Electric Station, Unit No.2; Surry Power Station, Unit No.2; Vogtle Electric Generating Plant, Unit No.1; and Wolf Creek Generating Station. Most of the indications were found in the tack expansion region near the tube-end welds and were a mixture of axial and circumferential primary water stress-corrosion cracking.

On February 21, 2006, Wolf Creek Nuclear Operating Corporation (WCNOC), the licensee for Wolf Creek Generating Station, submitted a license amendment request (LAR) that would permanently limit the scope of inspections required for tubes within the tubesheet (Reference 2).

The LAR was based on an analysis performed by Westinghouse that provided a technical basis for permanently limiting the scope of inspections required for tubes within the tubesheet. After three sets of requests for additional information (RAls) and several meetings with WCNOC, the NRC staff informed WCNOC during a phone call on January 3,2008, that they had not provided sufficient information to allow the NRC staff to review and approve the permanent LAR; therefore, WCNOC withdrew the LAR. Other units with similar LARs also withdrew their amendment requests, or revised their amendment requests to incorporate a more conservative interim alternate repair criteria (IARC) approach. The NRC staff approved an IARC amendment for MPS3 on September 30,2008 (Reference 4). That IARC amendment was applicable for Refueling Outage 12 and the subsequent operating cycle.

After withdrawal of the first permanent LARs in 2008, industry addressed many questions posed by the NRC staff (Reference 3) regarding the technical analysis, referred to as H*, and improved the finite element modeling used in the analysis. Based on this work, permanent SG alternate repair criteria LARs were submitted for a number of units (not including MPS3) during the spring and summer of 2009. During its review of these LARs, the NRC staff identified a new technical issue relating to tubesheet bore eccentricity that could not be resolved in time to support approval and issuance of these LARs before the fall 2009 or spring 2010 outage seasons.

By letter dated September 30, 2009 (Reference 5), DNC submitted a request for an interim SG alternate repair criteria amendment for MPS3 applicable to Refueling Outage 13 (spring 2010) and the subsequent operating cycle. The NRC staff approved this interim amendment (Reference 6), and concluded that notwithstanding any potential non-conservatism in the

- 3 calculated H* distance which may be associated with the eccentricity issue, there is sufficient conservatism embodied in the H* distance to ensure for at least one operating cycle (one fuel cycle) 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.

Subsequent analyses by industry to address the NRC staff's concerns revealed that tubesheet bore eccentricity did not have a significant bearing on the outcome of the H* analyses.

However, these analyses did reveal a significant shortcoming in how displacements from the 3 Diminsion (3-D) finite element model of the lower SG assembly were being applied to the tube to-tubesheet interaction model which was based on thick shell equations. The industry developed a new tUbe-to-tubesheet interaction model to address this shortcoming, and the H*

analyses were updated accordingly. This more recent background is discussed in more detail as part of the NRC staff's technical evaluation in Section 4.0 of this safety evaluation. Details of these more recent analyses became available for NRC staff review too late to support applications for a permanent SG alternate repair criteria amendment in the spring or fall of 2011.

For this reason, the subject amendment request for MPS3 is for an interim amendment, applicable to Refueling Outage 14 and the subsequent operating cycle. The requested changes are shown below. The proposed changes are shown in markup form for clarity.

TS 6.8.4.g.c. would be changed 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 Refueling Outage 4.a 14 and the subsequent operating cycle, tubes with service-induced flaws located greater than 4.a4 15.2 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.a4 15.2 inches below the top of the tubesheet shall be plugged upon detection.

TS 6.8.4.g.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 Refueling Outage 4.a 14 and the subsequent operating cycle, portions of the tube below 4.a4 15.2 inches below the top of the tubesheet are 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

- 4 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.

TS 6.9.1.7 would be revised as follows:

i. During Refueling Outage 4J 14 and the subsequent operating cycle, the primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report;

j. During Refueling Outage 4J 14 and the subsequent operating cycle, the calculated accident induced leakage rate from the portion of the tubes below 3:4 15.2 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 2.49 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined; and

k. During Refueling Outage 4J 14 and the subsequent operating cycle, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

3.0 REGULATORY EVALUATION

In Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Section 50.36 'Technical specifications', the requirements related to the content of the TSs are established. Pursuant to 10 CFR 50.36, TSs 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 (LCOs); (3) surveillance requirements; (4) design features; and (5) administrative controls. The rule does not specify the particular requirements to be included in a planfs TSs.

In 10 CFR 50.36(c)(5), administrative controls are stated to be, 'the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure the operation of the facility in a safe manne(' This also includes the programs established by the licensee, and listed in the administrative controls section of the TSs, for the licensee to operate the facility in a safe manner. For MPS3, the requirements for performing SG tube inspections and repair are in TS 6.8.4.g, while the requirements for reporting the SG tube inspections and repair are in TS 6.9.1.7.

The TSs for all pressurized-water reactor (PWR) plants require that a SG program be established and implemented to ensure that SG tube integrity is maintained. For MPS3, SG tube integrity is maintained by meeting the performance criteria specified in TS 6.8.4.g.b for structural integrity and leakage criterion, consistent with the plant design and licensing basis.

- 5 TS 6.8.4.g.a requires that a condition monitoring assessment, an evaluation of the "as found" condition of the tubing, be performed during each outage in which the SG tubes are inspected to confirm that the performance criteria are being met. TS 6.8.4.g.d 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 tube-to-tubesheet weld at the tube inlet to the tube-to tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The applicable tube repair criteria, specified in TS 6.8.4.g.c, is 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.

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. SG tube integrity means that the tubes are capable of performing this safety function in accordance with the plant design and licensing basis. 10 CFR Part 50, Appendix A, "General Design Criteria for Nuclear Power Plants," provides regulatory requirements for the RCPB. The General Design Criterion (GDCs) states that the RCPB shall have "an extremely low probability of abnormal leakage ... and of gross rupture" (GDC 14), "shall be designed with sufficient margin" (GDCs 15 and 31), shall be of "the highest quality standards practical" (GDC 30), and shall be designed to permit "periodic inspection and testing ... to assess ... structural and leaktight integrity" (GDC 32).

To this end, 10 CFR 50.55a 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 further requires that throughout the service life of PWR facilities like MPS3, 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 inservice inspection of SG tubing are augmented by additional requirements in the TSs.

As part of the plant licensing basis, applicants for PWR licenses are required to analyze the consequences of postulated design-basis accidents (DBA), such as a 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 100.11 for 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 are being changed at MPS3 because of the proposed amendment and, thus, no radiological consequences of any accident analysis are being changed. The proposed changes to MPS3 TS 6.8.4.g meet the GDC requirements for the SG tubes and maintain the accident analyses and consequences that the NRC has reviewed and approved for the postulated DBAs for SG tubes.

License amendment No. 249 is currently approved at MPS3. This amendment modified TS 6.8.4.g, "Steam Generator (SG) Program," and TS 6.9.1.7, "Steam Generator Inspection Report," incorporating interim alternate repair criteria and associated tube inspection and reporting requirements that are applicable during Refueling Outage 13 and the subsequent

- 6 operating cycle. This amendment exempts the portion of tubing located more than 13.1 inches (the H* distance) below the top of the tubesheet (ITS) from the TS inspection and repair requirements. Tubes with service-induced flaws located in the portion of the tube from the ITS to 13.1 inches below the ITS shall be plugged upon detection. The proposed amendment is similar to the currently approved amendment, with the exception that the H* distance would be 15.2 inches and would be applicable to Refueling Outage 14 (fall 2011) and the subsequent operating cycle.

4.0 TECHNICAL EVALUATION

4.1 Definition of H*

The tube-to-tubesheet (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 transmitting the tube end cap pressure loads. 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 times the applicable coefficient of friction.

To support the proposed TS changes, the licensee's contractor, Westinghouse, has defined a parameter called H*. H* is the 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 DBA 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 MPS3, the proposed H* distance is 15.2 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 TSs 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.

-7 The regulatory standard by which the NRC staff has evaluated the subject license amendment request is that the amended TSs should continue to ensure that tube integrity will be maintained, consistent with the MPS3 current design and licensing basis. This includes maintaining structural safety margins consistent with the structural performance criteria in TS 6.S.4.g.b.1 and the design basis, as is discussed in Section 4.2.1.1 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.S.4.g.b.2, which are consistent with values assumed in the licensing basis accident analyses. Maintaining tube integrity in this manner ensures that the amended TSs 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 4.2.1 and 4.2.2 of this safety evaluation, respectively.

4.2 Technical Assessment 4.2.1 Joint Structural Integrity 4.2.1.1 Acceptance Criteria Westinghouse has conducted extensive analyses to establish the necessary H* distance to resist pullout under normal operating and DBA conditions. The NRC staff concurs that pullout is the structural failure mode of interest since the tubes are radially constrained against axial fishmouth 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 concurs that these are the appropriate safety factors to apply to demonstrate structural integrity. These safety factors are consistent with the safety factors embodied in the structural integrity performance criteria in TS 6.S.4.g.b.1 and with the design basis; namely the stress limit criteria in the ASME Code,Section III.

4.2.1.2 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 separating 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 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 tube-to-tubesheet (TITS) interaction analysis evaluated in Section 4.2.1.3 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.

- 8 A number of FEA mesh enhancements in the tubesheet region have been made (Reference 7) since the reference analysis (Reference 8). The mesh near the plane of symmetry (perpendicular to the divider plate) was revised to permit obtaining displacements parallel to the direction of the divider directly from the 3-D FEA for application (as displacement boundary conditions) to the edges of the square cell model discussed in Section 4.2.1.3.2. The mesh near the top of the tubesheet was enhanced to accommodate high temperature gradients in this area during normal operating conditions.

This 3-D FEA replaces the 2-D axisymmetric FEA used to support H* amendment requests submitted prior to 2008. The NRC staff finds that the 3-D analysis adequately addresses the NRC staff concern regarding the validity of the axisymmetric model to conservatively bound significant non-axisymmetric features of the actual tubesheets (Reference 3). These non axisymmetric features include the solid (non-bored) portion of the tubesheet between the hot and cold leg sides, and the divider plate which acts to connect the solid part of the tubesheet to the channel head.

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 analyses (Reference 8), a factor was applied to the 3-D FEA results to account for a non-functional divider plate, based on earlier sensitivity studies performed with the 2-D axisymmetric FEA model of the lower SG assembly.

The 3-D FEA model now 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.

Separate 3-D FEA analyses were conducted for each loading condition considered (I.e., normal operating conditions, MSLB and, feedwater line break (FLB>>, rather than scaling unit load analyses to prototypical conditions, as was done in analyses prior to 2008. The NRC staff finds that this addresses (corrects) a significant source of error in analyses used by applicants prior to 2008 (Reference 3). In addition, the temperature distributions throughout the lower SG assembly, including the tubesheet region, were calculated directly in the 3-D FEA from the assumed plant temperature conditions (i.e. from the assumed primary and secondary water temperatures) for each operating condition. The NRC staff finds this to be a more realistic approach relative to the reference analysis (Reference 8) where a linear distribution of temperature was assumed to exist through the thickness of the tubesheet in the 3-D FEA with an adjustment factor being applied to the H* calculations to account for the actual temperature distribution in the tubesheet based on sensitivity analyses for normal operating conditions.

- 9 4.2.1.3 TfTS Interaction Model 4.2.1.3.1 Thick Shell Model The 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

8) supporting the interim H* amendment issued on May 3, 2010, for MPS 3 (Reference 6),

Westinghouse used classical thick-shell equations to model the interaction between the tubes and tubesheet under various pressure and temperature conditions for purposes of calculating contact pressure (TfTS interaction model). Calculated displacements from the 3-D FEA of the lower tubesheet assembly (see Section 4.2.1.2 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 TfTS 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 TfTS 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 TfTS 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 05 SGs under MSLB conditions (Reference 9). In reviewing 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 TfTS contact is maintained around the entire tube circumference. This concern was applicable to all SG models with alloy 600 IT tubing.

The NRC staff documented a list of questions (Reference 12) that would need to be addressed satisfactorily 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 05 SGs.

On June 14 and 15, 2010, the NRC staff conducted an audit at the Westinghouse Waltz Mill Site (Reference 13). 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 (Reference 12),

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, the NRC staff concluded that eccentricity does not appear to be a significant variable affecting either average tube-to-tubesheet 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

- 10 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.

During the audit, Westinghouse presented preliminary details of a new TfTS interaction model developed as an alternative to the thick shell interaction model. This model is termed the square cell model. This model was originally developed in response to the above-mentioned difficulty encountered when applying the eccentriCity adjustment to Model D SGs TfTS 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 4.2.1.2 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 TfTS interaction analysis. The square cell model was still under development at the time of the audit and no draft documentation of the model was available for NRC staff review. Although the NRC staff found that objectives of the new model approach appeared reasonable, the NRC staff was unable to provide feedback on the details of the approach at that time. The NRC staff also observed (Reference 13) that the square cell model approach may also need to be applied to the Model F, 44F, and 51 F SGs to confirm that the analyses for these plants are conservative.

4.2.1.3.2 Square Cell Model Documentation for the square cell model (Reference 7) is included with the subject amendment request for an interim H" at MPS3 (Reference 1). 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 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.

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. TfTS 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

- 11 distance times the tubesheet bore surface area (equal to the tube outer diameter surface area) over the incremental axial distance times the coefficient of friction. The NRC staff reviewed the coefficient of friction used in the analysis and judged 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 4.2.1.1.

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.

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 4.2.1.2. 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 inside tube surface and crevice pressure 1 acting on both the tube outside surface and tubesheet bore surface are 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 4.2.1.4.

The NRC staff has not completed its review of the square cell model. However, for reasons discussed in Section 4.2.4, the NRC staff concludes the proposed H* distances will ensure, for at least one operating cycle (one fuel cycle), that tube structural and leakage integrity will be maintained with structural safety margins consistent with the design basis and with leakage integrity within the assumptions employed in the licensing basis accident analyses, without undue risk to public health and safety.

4.2.1.4 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 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 4.2.1.4 for more information

- 12 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 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. The NRC staff finds that this approach acceptably addresses the NRC staff's concerns regarding the use of the limiting median crevice pressure value of the normal operating and MSLB data, respectively, for each axial slice in previous H* analyses (Reference 3). The NRC staff finds the crevice pressure distributions used to support the current amendment request to be more realistic and more conservative than those previously used.

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. Therefore 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.

4.2.1.5 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 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. This initial estimate did not consider the effect of the Poisson's contraction of the tube radius associated with application of the axial end cap load (see step 6 below).

2. A O.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

- 13 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 4.2.1.5.1 of this safety evaluation.

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 the FES. This adjustment is no longer necessary, as discussed in Section 4.2.1.2, since the temperature distributions throughout the tubesheet were calculated directly in the 3-D FEA supporting the current request for an interim H* amendment.

4. Steps 1 through 3 yield a so-called "mean" estimate of H*, which is deterministically based. This step is 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 staff's evaluation of the probabilistic analysis is provided in Section 4.2.1.6 and 4.2.1.7 of this safety evaluation.

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 4.2.1.5.2 of this safety evaluation.

6. This step has been added to the H* calculation process based on the latest information presented in the January 20, 2011, letter. 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 4.2.1.5.3 of this safety evaluation.

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

estimate to account for uncertainty in the BET location, relative to the top of the tubesheet, based on a BET uncertainty analysis for Model F SGs conducted by Westinghouse. As discussed previously in Section 4.2.1.3.1, the reference analysis was based on the thick shell model and the results of that analysis did not indicate a loss of contact pressure at the TTS during normal operating procedure or SLB conditions; therefore, this adjustment for the BET location was necessary. In response to NRC staff questions regarding the BET uncertainty analysis, Westinghouse performed an analysis (Reference 22) that showed BET locations as great as one inch below the TTS could be tolerated at any tube location. The limiting calculated H* value is in the most limiting tubesheet sector, therefore that H* value provides greater than one inch of margin for most other tubesheet sectors. For those few sectors in the tubesheet where the local H* distance was within one inch of the maximum H* distance, Westinghouse showed that the contact pressure gradient was positive with increasing depth into the tubesheet, and therefore, an H* length reduced by one inch still met the pull out resistance requirements, including appropriate safety factors.

- 14 The new analysis (Reference 7) has made the need for this adjustment moot, as the square cell model shows a loss of contact pressure at the TIS 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.

4.2.1.5.2 Crevice Pressure Adjustment As discussed in Section 4.2.1.5, steps 1 through 4 of the H* calculation process 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 are 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 during the reference analysis 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 (Le., the crevice pressure adjustment referred to in step 5 of Section 4.2.1.5) was plotted as a function of the initial H* estimate for the limiting loading case and tube radial location. The NRC staff concludes this to be an acceptable approach where the H* estimates are based on the thick shell model; however, the NRC staff has not yet reached a conclusion regarding the applicability of this adjustment to H* estimates that are based on the square cell model. However, for reasons discussed in Section 4.2.4, the NRC staff concludes the proposed H* distances will ensure, for at least one operating cycle (one fuel cycle), that tube structural integrity 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.

4.2.1.5.3 Poisson Contraction Effect The axial end cap load acting on each tube is equal to the primary-to-secondary pressure difference times the tube 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 TrrS contact pressure and, thus, to increase the H* distance. The axial end cap force is resisted by the axial friction force developed at the TrrS joint. Thus, the axial end cap force begins to decrease with increasing distance into the tubesheet, reaching zero at a location 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 4.2.1.1.

This Poisson radial contraction effect was neglected in the reference analyses, but is accounted for in the analyses supporting the subject amendment request. A simplified approach was followed. 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 reacted by the tubesheet. The TrrS contact pressure distributions determined in Step 4 of the H* calculation process in Section 4.2.1.5 were reduced by this amount. Second, the friction force associated with these reduced TrrS contact pressures were integrated with distance into

- 15 the tubesheet, and the length of engagement necessary to react one times the end cap loading (i.e., no safety factor applied) was determined. At this distance (i.e. attenuation distance), the entire end cap loading was assumed to have been reacted by the tubesheet, and the axial load in the tube below the attenuation distance was assumed to be zero. Thus, the TfTS 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 TfTS contact pressures from Step 4 of Section 4.2.1.5 were reduced only over the attenuation distance. The NRC staff has not completed its review of the applied adjustment to account for the Poisson radial contraction effect at this time. However, for reasons discussed in Section 4.2.4, the NRC staff concludes the proposed H* distances will ensure, for at least one operating cycle (one fuel cycle), 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.

4.2.1.6 Acceptance Standard - Probabilistic Analysis The purpose of the probabilistic analysis is to develop an H* distance that ensures, with a probability of 0.95, that the population of tubes will retain margins against pullout consistent with criteria evaluated in Section 4.2.1.1 of this safety evaluation, 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; for example, the upper voltage limit for the voltage based tube repair criteria in NRC Generic Letter 95-05 (Reference

14) employs a consistent criterion. The NRC staff also finds that use of the 0.95 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 15 and 16).

In terms of the confidence level that should be attached to the 0.95 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 17). In the meantime, the calculated H* distances supporting the interim amendment currently being requested 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 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 4.2.1.1. 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 requested interim amendment are 0.95 probability/95

- 16 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.

4.2.1.7 Probabilistic Analyses Sensitivity studies were conducted during the reference analyses (Reference 8) 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-508 Class 2a tubesheet material. Given that no credit was taken in the reference H* analyses (Reference 8) 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 were ignored, with the exception of Young's modulus of elasticity 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 concurs 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 4.2.1.5), 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.

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 Monte Carlo sampling approach. The NRC staff's review (Reference 6) 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 (References 8 and 18) and questioned whether the H* influence curves had been conservatively treated. To address this concern, new H* analyses were performed as documented in References 10 and 11. These analyses made direct use of the H* influence curves in a manner the NRC staff found to be acceptable (Reference 6).

The revised reference analyses (References 10 and 11) 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 2 Residual contact pressures are sensitive to variability of other input parameters.

- 17 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 (Reference 3) 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 0.95 probability value at the desired level of confidence for a single SG tube population or all SG population, as appropriate. The !\IRC staff concludes that this approach addresses the NRC staff's question in a realistic fashion and is acceptable.

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 in support of the subject interim amendment. Instead, the probabilistic analysis utilized the results of the Monte Carlo 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 high ranking 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% 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 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 values of alpha. From these plots, paired sets of tube and tubesheet CTE values were selected such as to maximize the H* estimate and to upper and lower bound the rank orders corresponding to the appropriate probabilistic acceptance criteria described and evaluated in Section 4.2.1.6. 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. These H* estimates were then plotted as a function of rank ordering, allowing the interpolation of H* values at the desired rank orders.

The limiting probabilistic H* value, evaluated at the appropriate acceptance standard as discussed in Section 4.2.1.6 and with the adjustments for crevice pressure and Poisson radial contraction effect discussed in Section 4.2.1.5, is bounded by the proposed H* value of 15.2 inches in the subject request for an interim amendment.

The NRC staff has not completed its evaluation of the above probabilistic analysis; however, for .

reasons discussed in Section 4.2.4, the NRC staff concludes the proposed H* distances will ensure, for at least one operating cycle (one fuel cycle), 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.

- 18 4.2.1.8 Coefficient of Thermal Expansion During operation, a large part of contact pressure in a SG tube-to-tubesheet joint is derived from the difference in CTE between the tube and tubesheet. As discussed in Section 4.2.1.7, 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. 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 (Reference 3).

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 19). 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° Fahrenheit (F) to 1300° F. The polynomial fit chosen resulted in mean CTE values that were significantly different from the ASME Code values from 75° F to about 300° F. When the raw data was reanalyzed using the locally weighted least squares regression (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 700° Celsius (C),

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 8.

- 19 The testing showed that the nominal ASME Code values for Alloy 600 and SA-50S 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-50S 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 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 3 and are acceptable.

4.2.2 Accident Induced Leakage Considerations Operational leakage integrity is assured by monitoring primary-to-secondary leakage relative to the applicable TS LCO limits in TS 3/4.4.6.2, "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 criteria in TS 6.S.4.g.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 ratio of the maximum primary-to-secondary pressure difference during the accident divided by that for normal operating conditions. The second quantity is the ratio of viscosity under normal operating primary water temperature divided by viscosity under the accident condition primary water temperature. The third quantity is the ratio of crevice length under normal operating conditions to crevice length under accident conditions.

This ratio equals 1, provided it can be shown that positive contact pressure is maintained along the entire H* distance for both conditions. 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 such that the ratio is equal to 1. The NRC staff agrees that this is a conservative assumption, provided there is a positive contact pressure for

- 20 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.

As a condition of NRC approval of Amendment Number 249 (Le., the currently approved interim repair criteria (Reference 6)) for MPS3, the licensee provided a commitment in Reference 5 that described how the leakage factor would be used to satisfy TS 6.8.4.g.a for condition monitoring and TS 6.8.4.g.b.2 regarding performance criteria for 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 2.49 and added to the total accident 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 accident induced leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.49 and compared to the observed operational leakage. An administrative limit will be established to not exceed the calculated value.

In the subject amendment request (Reference 1), the licensee stated the program/procedure changes needed to meet these commitments were completed in accordance with Amendment Number 249 and that these changes remain in place and will also apply to the subject license amendment. The NRC staff finds these previously implemented program/procedural changes acceptable, since they provide further assurance, in addition to the licensee's operational leakage monitoring processes, that accident induced SG tube leakage will not exceed values assumed in the licensing bases accident analyses.

4.2.3 Proposed Change to TS 6.9.1.7. "Steam Generator Tube Inspection Report' The NRC staff has reviewed the proposed reporting requirements and finds that they are sufficient to allow the NRC staff to monitor the implementation of the proposed amendment.

Based on this conclusion, the NRC staff finds that the proposed reporting requirements are acceptable.

4.2.4 Technical Bases for Interim H* Amendment The proposed H* value is based on the conservative assumption that all tubes in all steam generators are severed at the H* location. This is a bounding, but necessary assumption for purposes of supporting a permanent H* amendment because the tubes may not be inspected below the H* distance for the remaining life of the steam generators, which may range up to 30 years from now depending on the plant, and because the tubes are susceptible to stress corrosion cracking below the H* distance. In addition, the proposed H* distance conservatively

21 takes no credit for residual contact pressure associated with the tube hydraulic expansion process, As discussed in Sections 4.2.1.3.2,4,2,1,5,2,4,2,1.5.3, and 4,2,1,7, the NRC staff has not completed its review of certain elements of the technical basis for the proposed H* distance.

Thus, in spite of the significant conservatisms embodied in the proposed H* distance, the NRC staff is unable to conclude at this time that the proposed H* distance is, on net, conservative from the standpoint of ensuring that all tubes will retain acceptable margins against pullout (Le.,

structural integrity) and acceptable accident leakage integrity for the remaining lifetime of the steam generators, assuming all tubes to be severed at the H* location. This NRC staff will need to complete its review of these certain elements before it can approve any request for a permanent H* amendment. However, for the reasons below, the NRC staff concludes the proposed H* distances will ensure, for at least one operating cycle (one fuel cycle), 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.

From a fleet-wide perspective (for all Westinghouse plants with tubes fabricated from thermally treated Alloy 600), the NRC staff has observed from operating experience that the extent of cracking is at an early stage in terms of the number of tubes affected by cracking below the H*

distance and the severity of cracks, compared to the idealized assumption that all tubes are severed at the H* distance. Most of these cracks occur in the lower-most one inch of tubing, which is a region of relatively high residual stress associated with the 1 inch tack roll expansion in that region, Although the extent of cracking can be expected to increase with time, it is the NRC staff's judgment based on experience that it will continue to be limited to a small percentage of tubes, mostly near the tube ends, over the next operating cycle (approximately 18 months for MPS3), The NRC staff's observations are based on the review of SG tube inspection reports from throughout the PWR fleet. These reports are reviewed and the NRC staff's conclusions are documented within one year of each SG tube inspection.

In the fall of 2008, tube-end inspections were conducted on 17,889 tubes in the hot-legs of SGs

'A', 'B', 'C', and 'D', and an additional 8,924 tubes in the four SG cold-legs at MPS3. These tube end inspections revealed 99 axial indications and 53 circumferential indications that resulted in 23 tubes being plugged (Reference 20). The NRC staff finds this to be within the envelope of industry experience. In addition, inspection of the tubes at the top of the tubesheet and tube support plate locations and the small radius u-bends during the fall of 2008 and spring of 2010 (Reference 21) revealed no indications of cracking such as has been observed at other similar plants with thermally treated alloy 600 tubing. The NRC staff finds that the extent and severity of cracking at MPS3 to be within the envelope of industry experience with similar units.

Whereas the proposed H* distance of 15.2 inches was developed on the assumption that all tubes are severed at the H* location, the NRC staff concludes that few, if any tubes, are likely to be severed at the H* distance over the next operating cycle based on the recent experience at MPS3. For this reason, the NRC staff concludes that there is sufficient conservatism, as discussed above, embodied in the proposed H* distances to ensure acceptable margins against tube pullout during the next operating cycle. The NRC staff also concludes there is reasonable assurance during the next inspection cycle that any potential accident induced leakage will not exceed the technical specification performance criteria for accident induced leakage. This

- 22 reflects current operating experience trends that cracking below the H* distance is occurring predominantly in the tack roll region near the bottom of the tube. At this location, it is the NRC staffs judgment that the total resistance to primary-to-secondary leakage will be dominated by the resistance of any "crevice' in the roll expansion region (due to very high TrrS contact pressures in this region), such that the leakage factors discussed in Section 4.2.2 will remain conservative should there be a loss of TrrS contact near the top of the tubesheet due to tubesheet bore eccentricity effects.

4.3 Conclusion The NRC staff concludes that there is sufficient conservatism embodied in the proposed H*

distances to ensure for at least one operating cycle 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. The proposed license amendment applies only to Refueling Outage 14, and the subsequent operating cycle for MPS3.

Based on this finding, the NRC staff further concludes that the proposed amendment meets 10 CFR 50.36 and, thus, the proposed amendment is acceptable.

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Connecticut State official was notified of the proposed issuance of the amendment. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes 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 amendment involves 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 amendment involves no significant hazards consideration, and there has been no public comment on such finding (76 FR 39136). Accordingly, the amendment meets 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 amendment.

7.0 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) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

- 23

8.0 REFERENCES

1. Dominion Nuclear Connecticut, Inc. (DNC) letter, "Millstone Power Station Unit 3 - License Amendment Request to Revise Technical Specification (TS) 6.8.4.g, 'Steam Generator (SG)

Program' and TS 6.9.1.7, 'Steam Generator Tube Inspection Report' for Temporary Alternate Repair Criteria," January 20,2011. ADAMS Accession No. ML110280208. This letter also transmitted Reference 7.

2. Wolf Creek Nuclear Operating Corporation, Letter ET-06-004, "Revision to Technical Specification 5.5.9, 'Steam Generator Tube Surveillance Program,'" February 21,2006.

ADAMS Accession No. ML060600456.

3. NRC letter to Wolf Creek Nuclear Operating Corporation, "Wolf Creek Generating Station Withdrawal of License Amendment Request on Steam Generator tube Inspections,"

February 28, 2008. ADAMS Accession No. ML080450185.

4. NRC letter to DNC, "Millstone Power Station, Unit NO.3 - Issuance of Amendment Regarding Changes to Technical Specification (TS) Section 6.8.4.g, 'Steam Generator Program' and Section 6.9.1.7, 'Steam Generator Tube Inspection Report,'" September 30, 2008. ADAMS Accession No. ML082321292.

5. DNC letter, "Millstone Power Station Unit 3 - License Amendment Request to Revise Technical Specification (TS) 6.8.4.g, 'Steam Generator (SG) Program' and TS 6.9.1.7,

'Steam Generator Tube Inspection Report' for One-Time Alternate Repair Criteria (H*},"

November 23, 2009. ADAMS Accession No. ML093620085. This letter also transmitted Reference 8.

6. NRC letter to DNC, "Millstone Power Station, Unit NO.3 - Issuance of Amendment Re:

Changes to the Steam Generator Inspection Scope and Repair Requirements (TAC No.

ME2978}," May 3,2010. ADAMS Accession No. ML100770358.

7. Westinghouse Electric Company, LLC (WEC) report, WCAP-17330-P (Proprietary) and WCAP-17330-NP (Non- Proprietary), Rev. 0, "H*: Resolution of NRC Technicaflssue Regarding Tubesheet Bore Eccentricity (Model F/Model D5}," November 2010. ADAMS Accession Nos. ML110280216 (Proprietary) and ML110280213 (Non- Proprietary). This report was enclosed with Reference 1 above.

8. WEC report, WCAP-17071-P (Proprietary) and WCAP-17071-NP (Non-Proprietary), "H*:

Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)," Revision 0, dated April 2009. ADAMS Accession Nos. ML093620087 (Proprietary) and ML093620086 (Non-Proprietary). This report was enclosed with Reference 5 above.

9. WEC report, WCAP-17072-P (Proprietary) and WCAP-17072-NP (Non-Proprietary), Rev. 0, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 05)," May 2009. ADAMS Accession Nos.

ML091670159 (Introduction through Section 6.2.2.2.2 - Proprietary), ML091670160 (Section

- 24 6.2.2.2.3 through Section 6.2.5.3 - Proprietary), ML091670161 (Section 6.2.6 through Appendix - Proprietary), and ML091670172 (Non- Proprietary).

10. WEC letter LTR-SGMP-09-100-P (Proprietary) and LTR-SGMP-09-100-NP (Non Proprietary), "Response to NRC Request for Additional Information on H*; Model F and D5 Steam Generators," dated August 12, 2009. ADAMS Accession Nos. ML092370305 (Proprietary) and ML092370304 (Non-Proprietary).

11. WEC letter SGMP-09-109-P (Proprietary) and SGMP-09-109-NP (Non-Proprietary),

"Response to NRC Request for Additional Information on H*; RAI #4; Model F and Model D5 Steam Generators," dated August 25,2009. ADAMS Accession Nos. ML092450334 (Proprietary) and ML092470144 (Non-Proprietary).

12. NRC letter to Southern Nuclear Operating Company, "Vogtle Electric Generating Plant, Units 1 and 2, Transmittal of Unresolved Issues Regarding Permanent Alternate Repair Criteria for Steam Generators (TAC Nos. ME1339 and ME13340)," November 23,2009.

ADAMS Accession No. ML093030490.

13. NRC memorandum, R. Taylor to G. Kulesa, "Vogtle Electric Generating Plant - Audit of Steam Generator H* Amendment Reference Documents (TAC Numbers ME3003 and ME3004}," July 9,2010. ADAMS Accession No. ML101900227.

14. NRC Generic Letter 95-05, "Voltage Based Alternate Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking," August 3, 1995. ADAMS Accession No. ML031070113.

15. 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. ADAMS Accession No. ML108240071.

16. NUREG-1570, "Risk Assessment of Severe Accident-Induced Steam Generator Tube Rupture," March 1998. ADAMS Accession No. ML003769765.

17. 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,"

February 6, 2009. ADAMS Accession No. ML090370782.

18. WEC letter LTR-SGMP-09-1 04-P (Proprietary) and LTR-SGMP-09-1 04-NP (Non Proprietary), Rev. 1, "White Paper on Probabilistic Assessment of H*" dated August 13, 2009. ADAMS Accession Nos. ML092450030 (Proprietary) and ML092450029 (Non Proprietary) .

19. Nuclear Energy Institute letter dated July 7, 2009, NRC ADAMS Accession No. ML082100086, transmitting Babcock and Wilcox Limited Canada letter 2008-06-PK-001, liRe-assessment of PMIC measurements for the determination of CTE of SA 508 steel,"

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

- 25

20. DNC letter 09-125, "Millstone Power Station Unit 3 End of Cycle 12 Steam Generator Tube Inspection Report," March 13, 2009. ADAMS Accession No. ML090850344.

21. DNC letter 10-632, "Millstone Power Station Unit 3 End of Cycle 13 Steam Generator Tube Inspection Report," October 28, 2010. ADAMS Accession No. ML103130038.

22. WEC letter, LTR-SGMP-09-111-P (Proprietary) and LTR-SGMP-09-111-NP (Non Proprietary), Rev. 1, "Acceptable Value of the Location of the Bottom of the Expansion Transition (BET) for Implementation of H*," September 2010. ADAMS Accession Nos.

ML103300254 (Proprietary) and ML103300251 (Non-Proprietary).

Principal Contributor: E. Murphy Date: October 7, 2011

October 7, 2011 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Nuclear Connecticut, Inc.

Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711

SUBJECT:

MILLSTONE POWER STATION, UNIT NO.3 - ISSUANCE OF AMENDMENT RE: STEAM GENERATOR TUBE INSPECTION ALTERNATE REPAIR CRITERIA (TAC NO. ME5389)

Dear Mr. Heacock:

The Commission has issued the enclosed Amendment No. 252 to Renewed Facility Operating License No. NPF-49 for the Millstone Power Station, Unit No.3, in response to your application dated January 20, 2011.

The amendment revises Technical Specification (TS) Section 6.8.4.g, "Steam Generator (SG)

Program," to exclude a portion of the tubes below the top of the SG tubesheet from periodic SG inspections for Refueling Outage 14 and the subsequent operating cycle. In addition, this amendment revises TS Section 6.9.1.7, "Steam Generator Tube Inspection Report," to remove reference to the previous interim alternate repair criteria and provide reporting requirements specific to the current temporary alternate repair criteria.

A copy of the related Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, Iral Carleen J. Sanders, Project Manager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-423

Enclosures:

1. Amendment No. 252 to NPF-49

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

PUBLIC LPLI-2 R/F RidsAcrsAcnw_MaiICTR Resource RidsNrrDirsltsb Resource RidsNrrDorlDpr Resource RidsNrrDorlLpl1-2 Resource RidsNrrCsgb Resource RidsNrrPMMilistone Resource RidsNrrLAABaxter Resource RidsOgcRp Resource RidsRgn1 MailCenter Resource EMurphy, NRR Accesslon Nurn ber: ML112580517 *Bly memo dated OFFICE NRR/LPLI-2/PM NRR/LPLI-2/LA OGC NRR/CSGB/BC NRR/LPLI-2/BC i ABaxter PKlein for HChernoff NAME CSanders (w/comments) MSpencer RTaylor JREnnis for} I DATE 9/20/11 9/26/11 10/3/11 08/04/2011*

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