ML092990489

Issuance of Amendments Regarding H*: Alternate Repair Criteriaa for Steam Generator Tubsheet Expansion Region

ML092990489
Person / Time
Site:	Turkey Point
Issue date:	10/30/2009
From:	Jason Paige Plant Licensing Branch II
To:	Nazar M Florida Power & Light Co
Paige, Jason, NRR,301-415-5888
References
TAC ME1754, TAC ME1755
Download: ML092990489 (30)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 October 30, 2009 Mr. Mano Nazar Senior Vice President, Nuclear and Chief Nuclear Officer Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420

SUBJECT:

TURKEY POINT UNITS 3 AND 4 - ISSUANCE OF AMENDMENTS REGARDING H*: ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBESHEET EXPANSION REGION (TAC NOS. ME1754 AND ME1755)

Dear Mr. Nazar:

The U.S. Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No.241 to Renewed Facility Operating License No. DPR-31 and Amendment NO.236 to Renewed Facility Operating License No. DPR-41 for the Turkey Point Plant, Units Nos. 3 and 4, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated July 23, 2009, as supplemented by letters dated September 30 and October 26, 2009.

The amendments revise the inspection scope and repair requirments of TS 6.8.4.j, "Steam Generator (SG) Program," and to the reporting requirements of TS 6.9.1.8, "Steam Generator (SG) Tube Inspection Report."

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

l;P-Jason C. Paige, Project Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-250 and 50-251

Enclosures:

1. Amendment No.241 to DPR-31

2. Amendment No.236 to DPR-41

3. Safety Evaluation cc w/enclosures: Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 FLORIDA POWER AND LIGHT COMPANY DOCKET NO. 50-250 TURKEY POINT PLANT, UNIT NO.3 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No241 Renewed License No. DPR-31

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

A. The application for amendment by Florida Power and Light Company (the licensee) dated July 23, 2009, as supplemented by letters dated September 30 and October 26, 2009, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's rules and regulations set forth in Title 10 of the Code of Federal Regulations (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.

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2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 3.B of Renewed Facility Operating License No. DPR-31 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No.241 are hereby incorporated into this renewed license. The Environmental Protection Plan contained in Appendix B is hereby incorporated into this renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuance and shall be implemented within 30 days within issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Th:!~

Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Operating License and Technical Specifications Date of Issuance: October 30, 2009

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 FLORIDA POWER AND LIGHT COMPANY DOCKET NO. 50-251 TURKEY POINT PLANT UNIT NO.4 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 236 Renewed License 1\10. DPR-41

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

A. The application for amendment by Florida Power and Light Company (the licensee) dated July 30, 2009, as supplemented by letters dated September 30 and October 26, 2009, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's rules and regulations set forth in Title 10 of the Code of Federal Regulations (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.

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2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 3.B of Renewed Facility Operating License No. DPR-41 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 236 are hereby incorporated into this renewed license. The Environmental Protection Plan contained in Appendix B is hereby incorporated into this renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

I. This license amendment is effective as of its date of issuance and shall be implemented within 30 days.

FOR THE NUCLEAR REGULATORY COMMISSION

Attachment:

Changes to the Operating License and Technical Specifications Date of Issuance: October 30, 2009

ATTACHMENT TO LICENSE AMENDMENT AMENDMENT NO.241 RENEWED FACILITY OPERATING LICENSE NO. DPR-31 AMENDMENT NO.236 RENEWED FACILITY OPERATING LICENSE NO. DPR-41 DOCKET NOS. 50-250 AND 50-251 Replace Page 3 of Renewed Operating License DPR-31 with the attached Page 3.

Replace Page 3 of Renewed Operating License DPR-41 with the attached Page 3.

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

Remove pages Insert pages 6-18 6-18 6-18a 6-18a 6-18b 6-18b 6-22a 6-22a

3 E. Pursuant to the Act and 10 CFR Parts 40 and 70 to receive, possess, and use at any time 100 milligrams each of any source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactively contaminated apparatus; F. Pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of Turkey Point Units Nos. 3 and 4.

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

A. Maximum Power Level The applicant is authorized to operate the facility at reactor core power levels not in excess of 2300 megawatts (thermal).

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 241 are hereby incorporated into this renewed license. The Environmental Protection Plan contained in Appendix B is hereby incorporated into this renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

with the Technical Specifications and the Environmental Protection Plan.

C. Final Safety Analysis Report The licensee's Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on November 1, 2001, describes certain future inspection activities to be completed before the period of extended operation.

The licensee shall complete these activities no later than July 19, 2012.

The Final Safety Analysis Report supplement as revised on November 1, 2001, described above, shall be included in the next scheduled update to the Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following the issuance of this renewed license. Until that update is complete, the licensee may make changes to the programs described in such supplement without prior Commission approval, provided that the licensee evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

Unit 3 Renewed License No. DPR-31 Amendment No. 241

3 E. Pursuant to the Act and 10 CFR Parts 40 and 70 to receive, possess, and use at any time 100 milligrams each of any source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactively contaminated apparatus; F. Pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of Turkey Point Units Nos. 3 and 4.

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

A. Maximum Power Level The applicant is authorized to operate the facility at reactor core power levels not in excess of 2300 megawatts (thermal).

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 236 are hereby incorporated into this renewed license. The Environmental Protection Plan contained in Appendix B is hereby incorporated into this renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

C. Final Safety Analysis Report The licensee's Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on November 1, 2001, describes certain future inspection activities to be completed before the period of extended operation.

The licensee shall complete these activities no later than April 10, 2013.

The Final Safety Analysis Report supplement as revised on November 1, 2001, described above, shall be included in the next scheduled update to the Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following the issuance of this renewed license. Until that update is complete, the licensee may make changes to the programs described in such supplement without prior Commission approval, provided that the licensee evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

Unit 4 Renewed License No. DPR-41 Amendment No. 236

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

The combined As-left leakage rates determined on a maximum pathway leakage rate basis for all penetrations shall be verified to be less than 0.60 La, prior to increasing primary coolant temperature above 200°F following an outage or shutdown that included Type B and Type C testing only.

The As-found leakage rates, determined on a minimum pathway leakage rate basis, for all newly tested penetrations when summed with the As-left minimum pathway leakage rate leakage rates for all other penetrations shall be less than 0.6 La, at all times when containment integrity is required.

3) Overall air lock leakage acceptance criteria is ~ 0.05 La, when pressurized to Pa.

The provisions of Specification 4.0.2 do not apply to the test frequencies contained within the Containment Leakage Rate Testing Program.

L Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1. Change in the TS incorporated in the license or

2. A change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.

d. Proposed changes that meet the criteria of Specification 6.8.4 Lb. above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

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

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

TURKEY POINT - UNITS 3 & 4 6-18 AMENDMENT NOS. 241 AND 236

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

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

1. Structural integrity performance criterion: All in-service SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary-to-secondary accident induced leakage rate for any design basis accident, other than SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG.

Leakage is not to exceed 1 gpm total through all SGs and 500 gallons per day through anyone SG.

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

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

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

depth based criteria:

1. For Unit 3 through Refueling Outage 25 and the next operating cycle, and for Unit 4 during Refueling Outage 25 and the subsequent operating cycles until the next scheduled inspection, tubes with service-induced flaws located greater than 17.28 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 17.28 inches below the top of the tubesheet shall be plugged upon detection.

TURKEY POINT - UNITS 3 & 4 6-18a AMENDMENT NOS. 241 AND 236

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

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 Unit 3 through Refueling Outage 25 and the next operating cycle, and for Unit 4 during Refueling Outage 25 and the subsequent operating cycles until the next scheduled inspection, the portion of the tube below 17.28 inches from the top of the tubesheet is excluded from inspection. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tube may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outages 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 any portion of a SG tube not excluded above, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s),

then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary-secondary leakage.

6.8.5 DELETED TURKEY POINT - UNITS 3 & 4 6-18b AMENDMENT NOS. 241 AND 236

ADMINISTRATIVE CONTROLS STEAM GENERATOR TUBE INSPECTION REPORT (Cont'd)

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, and

h. The effective plugging percentage for all plugging in each SG.

Note: Report items i, j, and k are applicable following completion of inspections performed through Refueling Outage 25 at Unit 3 (and any inspection performed in the next operating cycle) and Refueling Outage 25 at Unit 4 (and any inspections performed in the subsequent operating cycles until the next scheduled inspection).

i. 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,

j. The calculated accident induced leakage rate from the portion of the tubes below 17.28 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 1.82 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, and

k. 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 Regional Administrator of the Regional Office of the NRC within the time period specified for each report as stated in the Specifications within Sections 3.0, 4.0, or 5.0.

TURKEY POINT - UNITS 3 & 4 6-22a AMENDMENT NOS. 241 AND 236

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 241 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-31 AND AMENDMENT NO.236 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-41 FLORIDA POWER AND LIGHT COMPANY TURKEY POINT PLANT, UNIT NOS. 3 AND 4 DOCKET NOS. 50-250 AND 50-251

1.0 INTRODUCTION

By application dated July 23, 2009 (Reference 1), as supplemented by letters dated September 30 and October 26, 2009 (Reference 2 and 3, respectively), the Florida Power and Light (FPL, the licensee) proposed an amendment to the Technical Specifications (TSs) for Turkey Point Plant, Units 3 and 4. The request proposed changes to the inspection scope and repair requirements of TS 6.8.4.j, "Steam Generator (SG) Program," and to the reporting requirements of TS 6.9.1.8, "Steam Generator (SG) Tube Inspection Report."

By supplemental letters dated September 30 and October 26,2009, the licensee responded to requests for additional information (RAls) from the staff, and requested that the permanent alternate repair criteria of the July 23, 2009, letter only be applicable to Unit 3 through Refueling Outage 25 (fall 2010) and the next operating cycle, and to Unit 4 during Refueling Outage 25 (fall 2009) and the subsequent operating cycles until the next scheduled inspection. Originally, the proposed changes would have established permanent alternate repair criteria for portions of the SG tubes within the tubesheet.

The September 30 and October 26,2009, supplemental letters provided additional information that clarified the application, limited the scope of the application as originally noticed, and did not change the staff's original proposed no significant hazards consideration determination as published in the Federal Register on August 28, 2009 (74 FR 44405).

2.0 BACKGROUND

Turkey Point Units 3 and 4 have three Model 44F SGs, which were designed and fabricated by Westinghouse. Each SG has 3,214 thermally treated Alloy 600 tubes with an outside diameter of 0.875 inches and a nominal wall thickness of 0.050 inches. These thermally treated tubes are hydraullcally expanded for the full depth of the 21-inch thick tubesheet and are welded to the tubesheet at each tube end.

-2 Prior to the fall of 2004, no instances of stress corrosion cracking affecting the tubesheet region of thermally treated Alloy 600 tubing had been reported at any nuclear power plants in the United States. However, in the fall of 2004, crack-like indications were found in tubes in the tubesheet region of Catawba Nuclear Station Unit 2 (Catawba), which utilized a different SG design (Model D5 SGs). Similar to the SG at Turkey Point Units 3 and 4, 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 manufacturing as a result of drill bit wandering or chip gouging. The tack expansion region 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 found crack-like indications in tubes within the tubesheet as well. These plants include Braidwood Unit 2, Byron Unit 2, Comanche Peak Unit 2, Surry Unit 2, Vogtle Unit 1, and Wolf Creek Unit 1.

Most of the crack-like 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 4).

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 RAls and several meetings with WCNOC, the staff informed WCNOC during a phone call on January 3, 2008, that it had not provided sufficient information to allow the staff to review and approve the permanent LAR. WCNOC withdrew the LAR by letter dated February 14, 2008 (Reference 5). In a letter dated February 8,2008 (Reference 6), the staff identified the specific issues that needed to be addressed to support any future request for a permanent amendment, which included, but were not limited to, thermal expansion coefficients, crevice pressure assumptions, uncertainty models, acceptance standards for probabilistic assessment, and leakage resistance.

Likewise, on April 27, 2006, FPL proposed amendments to the TSs for Turkey Point (Reference 7). The proposed changes would have permanently limited the scope of inspections and the plugging requirements for portions of the SG tubing within the hot leg tubesheet region.

During a September 19, 2006, conference call with the licensee, the staff informed FPL that further review and evaluation would be required prior to approving permanent amendments. By letter dated October 3, 2006, FPL modified the amendment to make the limited inspection and plugging requirements applicable only for Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, for both Unit 3 and 4 (Reference 8). License amendments 231 and 226 were approved for Turkey Point on November 1, 2006 (Reference 9).

After withdrawal of the initial round of permanent LARs submitted prior to 2008, the licensees and their contractor, Westinghouse, worked with the staff to address the issues identified in Reference 6. The NRC and industry held public meetings (References 10, 11, and 12) and phone calls to discuss resolution of these issues. The permanent LAR received from Turkey Point in 2009 (Reference 1), resolved the issues identified by the staff in Reference 6 but raised

- 3 an additional technical issue, as is discussed in section 4.2.1.3 of this safety evaluation. For this reason, the licensee modified its LAR to apply to Turkey Point Unit 4 during Refueling Outage 25 (fall 2009) and the subsequent operating cycles until the next scheduled inspection, and to Turkey Point Unit 3 through Refueling Outage 25 (fall 2010) and the next operating cycle, instead of the permanent change originally requested.

3.0 REGULATORY EVALUATION

The SG tubes are part of the reactor coolant pressure boundary (RCPB) and isolate fission products in the primary coolant from the secondary coolant. For the purposes of this safety evaluation, SG tube integrity means that the tubes are capable of performing this safety function in accordance with the plant design and licensing basis. The General Oesign Criteria (GOC) in Appendix A to Title 10 of the Code of Federal Regulations (10 CFR) Part 50 provide regulatory requirements, which are applicable to Turkey Point, and state that the RCPB shall have "an extremely low probability of abnormalleakage... and of gross rupture" (GOC 14), "shall be designed with sufficient margin" (GOC 15 and 31), shall be of "the highest quality standards practical" (GOC 30), and shall be designed to permit "periodic inspection and testing ... to assess... structural and leaktight integrity" (GOC 32). Turkey Point received construction permits on April 27, 1967, which was prior to the Nuclear Regulatory Commission's implementation of the current GOC in Appendix A of 10 CFR Part 50. Although the plant is exempt from the current GOC, the licensee states it is in compliance with the 1967 GOC that were in effect when Turkey Point was licensed, and discusses how it meets each of these GOC for Turkey Point in Section 4.1 of the Updated Final Safety Analysis Report (UFSAR). A review of the 1967 GOC shows that the GOC applicable to the RCPB and SG are comparable to the requirements of the current GOC.

Regulation 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(f) of 10 CFR Part 50 further requires that throughout the service life of pressurized water reactor (PWR) facilities, 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 preservice 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 TS. The use of the proposed alternate repair criteria does not impact the integrity of the SG tubes and, therefore, the SG tubes still meet the design requirements and the requirements for Class 1 components in Section III of the ASME Code.

Analyses addressing the consequences of postulated design-basis accidents (OBAs), such as an SG tube rupture or a main steam line break (MSLB) are included in the plant's licensing bases. These analyses consider primary-to-secondary leakage that may occur during these events and must demonstrate that the offsite radiological consequences and control room operator doses do not exceed the applicable limits. The proposed changes do not affect the accident analyses and consequences that the NRC has reviewed and approved for the postulated OBAs for SG tubes.

In 10 CFR 50.36, "Technical Specifications," the requirements for administrative control provisions are established to assure operation of the facility in a safe manner. The TS for all

- 4 PWR plants require that an SG program be established and implemented to ensure that SG tube integrity is maintained. Programs established by the licensee, including the SG program, are listed in the administrative controls section of the TS. For Turkey Point, the requirements for performing SG tube inspections and repair are in TS 6.8.4.j, while the requirements for reporting the SG tube inspections and repair are in TS 6.9.1.8.

SG tube integrity is maintained by meeting the performance criteria specified in TS 6.8.4.j.b for structural and leakage integrity, consistent with the plant design and licensing basis. Technical specification 6.8.4.j.a requires that a condition monitoring assessment be performed during each outage in which the SG tubes are inspected, to confirm that the performance criteria are being met. Technical specification 6.8.4.j.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.

The applicable tube repair criteria, specified in TS 6.8.4.j.c., are that tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40 percent of the nominal wall thickness shall be plugged, unless the tubes are permitted to remain in service through application of the alternate repair criteria provided in TS 6.8.4.j.c.

In License Amendment Nos. 231 and 226 the provisions for SG tube repair criteria in TS 6.8.4.j.c. were modified with alternate repair criteria that were applicable during Turkey Point Unit 3 Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection (Le. two operating cycles) and Unit 4 Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection (Le., two operating cycles). The alternate repair criteria approved in amendment nos. 231 and 226 eliminated inspections and repair of tubes more than 17.81 inches below the top of the tubesheet (TTS). The proposed amendment eliminates inspections and repair of tubes more than 17.28 inches below the top of the tubesheet. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 17.28 inches below the top of the tubesheet shall be plugged upon detection.

The proposed amendment would go into effect now and continue through Refueling Outage 25 and the next operating cycle for Turkey Point Unit 3, and during Refueling Outage 25 and the subsequent operating cycles until the next scheduled inspection for Unit 4 (Le., the inspections scheduled in accordance with TS 6.8.4.j.d).

4.0 TECHNICAL EVALUATION

4.1 Proposed Changes to the TS TS 6.8.4.j. is being revised as follows (new text in bold):

j. Steam Generator (SG) Program

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

-5 or plugged to confirm that the performance criteria are being met.

b. [No change/Not shown]

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 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 Unit 3 through Refueling Outage 25 and the next operating cycle, and for Unit 4 during Refueling Outage 25 and the subsequent operating cycles until the next scheduled inspection, tubes with service-induced flaws located greater than 17.28 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 17.28 inches below the top of the tubesheet shall be plugged upon detection.

2. [No change/Not shown]

3. [No change/Not shown]

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 outlet, and that may satisfy the applicable tube repair criteria. For Unit 3 through Refueling Outage 25 and the next operating cycle, and for Unit 4 during Refueling Outage 25 and the subsequent operating cycles until the next scheduled inspection, the portion of the tube below 17.28 inches from the top of the tubesheet is excluded from inspection. The tube-to tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tube may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1. [No change/Not shown]

2. [No change/Not shown]

3. If crack indications are found in any portion of a SG tube not excluded above, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from

-6 examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s),

then the indication need not be treated as a crack.

TS 6.9.1.8. is being revised as follows (new text in bold):

Steam Generator (SG) Tube Inspection Report 6.9.1.8 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 6.8.4.j, Steam Generator (SG) Program. The report shall include:

a. - h. [No change/Not shown]

Note: Report items i, j, and k are applicable following completion of inspections performed through Refueling Outage 25 at Unit 3 (and any inspection performed in the next operating cycle) and Refueling Outage 25 at Unit 4 (and any inspections performed in the subsequent operating cycles until the next scheduled inspection).

i. 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,

j. The calculated accident induced leakage rate from the portion of the tube below 17.28 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 1.82 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, and

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

4.2 Technical Evaluation The tube-to-tubesheet (TITS) joints are part of the pressure boundary between the primary and secondary systems. Each TITS joint consists of the tube, which is hydraulically expanded against the bore of the tubesheet, the TITS weld located at the tube end, and the tubesheet.

The TITS joints were designed in accordance with the ASME Code, Section III, as welded joints, not as friction joints. The TITS 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 TITS joints actually work, since it conservatively ignores the role of friction between the tube and tubesheet in reacting to the tube

- 7 end cap loads. The initial hydraulic expansion of the tubes against the tubesheet also produces an "interference fit" between the tubes and the tubesheet; thus, producing a residual contact pressure 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* to be that distance below the top of the tubesheet over which sufficient frictional force, with acceptable safety margins, can be developed between each tube and the tubesheet under tube end cap pressure loads associated with normal operating and 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 Turkey Point Units 3 and 4, the proposed H* distance is 17.28 inches. Given that the frictional force developed in the TITS 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 TITS weld is not needed to resist any portion of the tube end cap pressure loads. Thus, the licensee is proposing to change the TS to not require inspection of the tubes below the H*

distance and to exclude tube flaws located below the H* distance (including flaws in the TITS weld) from the application of the TS tube repair criteria. Under these changes, the TITS joint would now be treated as a friction joint extending from the top of the tubesheet to a distance below the top of the tubesheet equal to H* for purposes of evaluating the structural and leakage integrity of the joint.

The regulatory standard by which the staff has evaluated the subject license amendment is that the amended technical specifications should continue to ensure that tube integrity will be maintained consistent with the current design basis, as defined in the UFSAR. This includes maintaining structural safety margins consistent with the structural performance criteria in TS 6.8.4.j.b.1 discussed in section 4.2.1.1 below. In addition, this includes limiting the potential for accident-induced primary-to-secondary leakage to values that do not exceed the accident-induced leakage performance criteria in TS 6.8.4.j.b.2, which are consistent with values assumed in the UFSAR accident analyses. Maintaining tube integrity in this manner ensures that the amended TS are in compliance with all applicable regulations. The staffs 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.

4.2.1 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 staff finds 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

-8 conditions and a factor of 1.4 against pullout under DBA conditions. The staff finds 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 6.8.4.j.b.1 and with the design basis including the stress limit criteria in the ASME Code, Section III.

4.2.1.2 Tube-to Tubesheet (TITS) Interaction Model The resistance to 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. Westinghouse used classical thick-shell equations to model the interaction effects between the tubes and tubesheet under various pressure and temperature conditions for purposes of calculating contact pressure (TITS interaction model). For each tube, the tubesheet was modeled as an equivalent cylinder. The thickness of this equivalent cylinder was calculated to provide a stiffness equivalent to the actual tubesheet geometry in terms of the amount of tubesheet bore radial displacement that is associated with a given amount of radial pressure on the surface of the bore. Two-dimensional (2-D) finite element analyses of portions of the perforated tubesheet geometry were used to determine the thickness of the equivalent tubesheet cylinder that provided the necessary stiffness, as a function of tube location within the bundle. These analyses directly modeled a spectrum of possibilities concerning the pressure loads acting on nearby bore surfaces, instead of employing a "beta factor" adjustment as was done to support previous H* amendment requests submitted prior to 2008. The "beta factor" adjustment was an attempt to account for the pressure loads acting on nearby bore surfaces, which was used in analyses prior to 2008.

Based on its review, the staff concludes that the equivalent tubesheet cylinder thicknesses calculated by Westinghouse are conservative since they provide for lower bound stiffness estimates, leading to lower (conservative) estimates of contact pressure and resistance to pullout.

The shell model representing the tube was used to determine the relationship between the tube outer surface radial displacement and the applied axial end cap load (due to the primary-to-secondary pressure differential), primary pressure acting on the tube inner surface, 1

crevice pressure acting on the tube outer surface, contact pressure between the tube and tubesheet bore, and tube thermal expansion. However, the equivalent shell model representing the tubesheet was used only to determine the relationship between the tubesheet bore surface radial displacement with the applied crevice pressure and contact pressure. Radial displacements of the tubesheet bore surfaces are also functions of 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. These displacements are a function of tube location within the tube bundle and, also, a function of axial location within the tubesheet. To calculate these displacements, 3-D finite element finite analyses were performed. The staff's evaluation of these finite element analyses is provided in section 4.2.1.3, below. The tubesheet bore radial displacements from the 3-D finite element analyses were added to those from the tubesheet equivalent shell model to yield the total displacement of the tubesheet bore surface as a function of the tube radial and axial location.

1 Although the tubes are in tight contactwith 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.

- 9 The reference TiTS interaction model (Reference 13) 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 staff finds the assumption of zero residual contact pressure in the reference analysis to be a very conservative assumption.

The thick shell equations used in the TiTS interaction model allow calculation of the tube radial displacements and the tubesheet equivalent cylinder radial displacements for a given set of pressure and temperature conditions. Under normal operational and DBA pressures and temperatures, the tube outer surface undergoes a higher radial displacement than the tubesheet bore surface if interaction between the tube and tubesheet is ignored. Because TiTS interaction effects demand continuity of displacements (Le., the radial displacement of the tube outer surface must equal the radial displacement of the bore surface) at each axial location, contact pressure of sufficient magnitude to ensure equal radial displacements is developed between the two surfaces and can be directly solved for. The staff has reviewed the development of the TiTS interaction model and finds that it conservatively approximates the actual TiTS interaction effects and the resulting contact pressures.

The classical thick shell equations used in the interaction model were developed for cylindrical shells whose geometry and applied loads are uniform along the cylindrical axis. As discussed above, radial deflections of the tubesheet bores are non-uniform from the top to the bottom of the tubesheet, due to the temperature and pressure loadings acting on the various components of the SG lower assembly. In addition, the crevice pressure may vary in the axial direction as discussed below. The interaction model essentially divides the TiTS joint into a series of horizontal slices, where each slice is assumed to behave independently of the slices above and below. The staff concludes this to be conservative since it adds radial flexibility to the TiTS joint leading to lower contact pressures and tube pullout resistance.

The resisting force to the applied end cap load, which is developed over each incremental axial distance from the top of the tubesheet, is the average contact pressure over that incremental distance 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 staff reviewed the coefficient of friction used in the analysis and judges it to be a reasonable lower bound (conservative) estimate. The H* distance for each tube was determined by integrating the incremental friction forces from the top of the tubesheet to the distance below the top of the tubesheet where the friction force integral equaled the applied end cap load times the appropriate safety factor as discussed in section 4.2.1.1.

In summary, the staff has evaluated the TiTS interaction model and finds it to be a reasonable and conservative approach for the calculation of H* distances.

4.2.1.3 3-D Finite Element Analysis A 3-D finite element analysis 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 the diameter changes of the tubesheet bore surfaces due to primary pressure acting on the primary face of the tubesheet and

- 10 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. These calculated diameter changes tended to be non-uniform around the circumference of the bore.

The thick shell equations used in the TITS interaction model are axisymmetric. Thus, the non-uniform diameter change from the 3-D finite element analyses had to be adjusted to an equivalent uniform value before it could be used as input to the TITS interaction analysis.

A 2-D plane stress finite element model was used to define a relationship for determining a uniform diameter change that would produce the same change to average TITS contact pressure as would the actual non-uniform diameter changes from the 3-D finite element analyses.

In Reference 13, Westinghouse identified a difficultly in applying this model to the Model 44F SGs at Point Beach Unit 1 for the case of MSLB. Westinghouse attributes this difficulty to the relatively low primary water temperature that exists in the Point Beach Unit 1 Model 44F SGs under MSLB conditions, which is below the temperature range that the eccentricity relationship is intended to address. Of the five nuclear plants with Model 44F SGs that are applying for the H*

amendments (Point Beach Unit 1, Robinson Unit 2, Indian Point Unit 2, Turkey Point Units 3 and 4), only Point Beach Unit 1 has a MSLB DBA with relatively low primary water temperature, due to plant-specific assumptions made in the MSLB DBA analysis. To address this problem, Westinghouse developed a new model for the eccentricity effect, which it applied to the Model 44F MSLB case, but continued to apply the original eccentricity model for the Model 44F normal operating conditions case. Westinghouse ran the new model with conditions that bound all five nuclear plants with Model 44F SGs, rather than run multiple finite element analyses. In reviewing the report of the problem by Westinghouse, the staff developed questions relating to the conservatism of both the original and new eccentricity models and whether the tubesheet bore displacement eccentricities were small enough to ensure that TITS contact was maintained around the entire tube circumference. The responses to staff questions provided in Reference 2 did not provide sufficient information to allow the staff to reach a conclusion on these matters.

The licensee, therefore, modified its amendment request on September 30 and October 26,2009, (References 2 and 3) for a permanent H* amendment to be an interim H*

amendment request applicable only to Turkey Point Unit 3 through Refueling Outage 25 (fall 2010) and the subsequent operating cycle, and to Unit 4 during Refueling Outage 25 (fall 2009) and the subsequent operating cycles until the next scheduled inspection, as required in accordance with TS 6.8.4.j.d. Section 4.2.4 of this safety evaluation provides the staff's evaluation of the interim H* amendment request in light of the open issue relating to tubesheet bore displacement eccentricity. As described in section 4.2.4, there is sufficient information to enable the staff to evaluate the proposed one-cycle change.

This 3-D finite element analysis replaces the 2-D axisymmetric finite element analyses used to support H* amendment requests submitted prior to 2008. The staff finds that the 3-D analysis adequately addresses a concern cited by the staff in Reference 6 concerning the validity of the axisymmetric model to conservatively bound significant non-axisymmetric features of the actual tubesheets. 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.

The reference analyses for the Model F SGs assume a linear temperature distribution through the tubesheet. Because the linear distribution does not represent the actual temperature distribution during normal operating conditions, an incremental distance is added to the H*

- 11 distance to account for the actual tubesheet temperature distribution during normal operating conditions. The Model 44F SGs, however, were analyzed with newer finite element analyses that considered the actual tubesheet temperature distribution during normal operating conditions and thus, did not have an incremental distance added to the H* distance. When the Model F SGs were reanalyzed with the actual tubesheet temperature distribution, the conservatism of the linear temperature distribution was confirmed. While this does account for a minor decrease in the H* distance, the staff concludes that direct modeling of the actual temperature distribution in the tubesheet is more realistic and acceptable.

The reference finite element model used the physical dimensions of the Model F SGs. When the reference finite element model was used to analyze the Model 44F SGs, the model was not redesigned with the dimensions of the Model 44F SG, but was left with the previously used Model F SG dimensions. This was conservative because the inherent stiffness of the Model 44F lower SG assembly (channel head, tubesheet, and divider plate) is greater than that of the Model F SG. The increased stiffness results in less tubesheet deformation due to differential pressure across the tubesheet, which results in less bore-hole distortion at the TTS and a net reduction in the decrease of residual contact pressure (Le., the residual contact pressure remains higher). Therefore, it is acceptable to use the finite element model that incorporates the more limiting physical dimensions of the Model F SGs.

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 finite element analysis 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.

Separate 3-D finite element analyses were conducted for each loading condition considered (Le., normal operating conditions, MSLB). The feedwater line break (FLB) accident was not part of the licensing basis for plants with Model44F SGs (Reference 13) and therefore was not modeled. The staff finds that this adequately addresses a significant source of error in analyses used by applicants to support permanent H* amendment requests submitted prior to 2008 and which were subsequently withdrawn or modified (Reference 6).

4.2.1.4 Crevice Pressure Evaluation As discussed in an earlier footnote, 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 staff finds that the assumption of crevices is conservative since the pressure inside the crevices acts to push against both the tube and the tubesheet bore surfaces, thus reducing contact pressure between the tubes and tubesheet.

For tubes which do not contain through-wall flaws within the thickness of the tubesheet, the pressure inside the crevice is assumed to be equal to the secondary system pressure. For tubes that contain through-wall flaws within the thickness of the tubesheet, a leak path is

- 12 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 TfTS 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 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 for each axial slice of the TfTS interaction model. Based on its review of the tests and test results, the staff finds the assumed crevice pressure distributions to be realistic and acceptable.

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

4.2.1.5 H* Calculation Process The calculation of H* in the reference analyses (Reference 13) consisted of the following steps for each loading case considered:

1. Perform initial H* estimate using the interaction and 3-D finite element 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 pressure distribution over the length of the TfTS crevice.

2. Unlike Model F and D5 SGs, the analysis for the Model 44F SGs did not require an additional adjustment to correct for the actual temperature distribution in the tubesheet, because the temperature distribution was included directly in the analysis. See section 4.2.1.3 for further discussion.

3. Add O.3-inch adjustment to the initial H* estimate to account for uncertainty in the bottom of the tube expansion transition (BET) location relative to the top of the tubesheet, based on an uncertainty analysis on the BET conducted by Westinghouse.

4. Steps 1 through 3 yield a so-called "mean" estimate of H*, which is deterministically based. Step 4 involves a probabilistic analysis of the potential variability of H*, relative to the mean estimate, based on the combined potential variability of key input parameters

-13 for the H* analyses. This leads to a probabilistic estimate of H*, which is greater than the "mean" estimate calculated in steps 1 through 3.

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. The value of this adjustment was determined iteratively.

The staff's evaluation of the probabilistic analysis is provided in section 4.2.1.7 of this safety evaluation. Regarding step 3, the staff did not review the Westinghouse BET uncertainty analysis. Therefore, at the staff's request, the licensee has committed to a one-time inspection of the actual BET locations during Refueling Outage 25 for Turkey Point Unit 3 (fall 2010), and during Refueling Outage 25 for Turkey Point Unit 4 (fall 2009) to confirm that there are no significant deviations from the assumed BET value. Any such deviations will be entered into the corrective actions program for disposition. The staff finds this to be acceptable, since the BET inspections are a one-time action that is reviewable during routine NRC regional oversight activities. Any deviations are likely to be small (less than a few tenths of an inch) and not likely to impact the overall conservatism of the proposed H* distance.

4.2.1.6 Acceptance Standard - Probabilistic Analysis The purpose of the probabilistic analysis is to develop a 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 staff finds this probabilistic acceptance standard is consistent with what the staff has approved previously and is acceptable. For example, the upper voltage limit for the voltage based tube repair criteria in NRC Generic Letter 95-05 (Reference 14) employs a consistent criterion. The staff also notes 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 probability of 0.95 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 Westinghouse recommended H* value of 13.31 inches in Reference 13 for model 44F SGs is based on probabilistic estimates performed at a 50 percent confidence value. However, as discussed in the next section, 4.2.1.7, the staff finds that the 17.28-inch H* value proposed by the licensee conservatively bounds an H* value based on probabilistic estimates performed at a probability of 0.95 confidence level.

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 staff and licensee both find that the tube population in the faulted SG is of interest, since it is the only SG population 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

- 14 consensus between the staff and industry on which population needs to be considered in the probabilistic analysis for normal operating conditions, and although the Westinghouse recommended H* value in Reference 13 is based on the population of just one SG, the staff finds that the 17.28-inch H* value proposed by the licensee conservatively bounds an H* value based on probabilistic estimates performed at a 95 percent confidence level for the entire tube population (Le., for all SGs) at the plant, as discussed in section 4.2.1.7 below.

4.2.1.7 Probabilistic Analyses Sensitivity studies were conducted 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 13) for residual contact pressure associated with the tube hydraulic expansion process", 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 the staffs review of the analysis models and its engineering judgment, the 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 residual contact pressure during the reference H* analyses (Reference 13).

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. 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 staff's review relies primarily on the Monte Carlo analysis which provides the more realistic treatment of uncertainties.

The staff reviewed the implementation of probabilistic analyses in the reference analyses (Reference 13) and questioned whether the H* influence curves had been conservatively treated. The staff concluded that the reference analysis was insufficient to support the amendment request. To address this concern, the licensee submitted new H* analyses as documented in Reference 2. The analysis in Reference 2 made direct use of the H* influence curves in a manner the staff finds to be acceptable. To show that the proposed H* value in the subject LAR is conservative, the new analyses eliminated some of the conservatisms in the reference analyses as follows:

1. The reference analyses assumed that all tubes were located at the location in the tube bundle where the mean value estimate of H* was at its maximum value. The new analyses divided the tubes by sector location within the tube bundle and all tubes were 2 Residual contact pressures are sensitive to other input parameters.

- 15 assumed to be at the location in their respective sectors where the mean value estimate of H* 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 staff concludes the sector approach in the new analyses to result in a more realistic, but still conservative H* estimate.

2. As discussed previously in section 4.2.1.3, the new analyses used an updated tubesheet temperature distribution.

3. The reference analyses take no credit for residual contact pressure due to hydraulic expansion of the tubes against the respective tubesheet bores during SG manufacture.

The new analyses include consideration of recently completed pullout tests and analyses. The licensee stated that the tests confirmed a significant level of residual contact pressure exists, and showed that within a small degree of slippage, the forces required to continue moving the tube exceeded the maximum pullout forces that could be generated under very conservative assumptions. The licensee finds that crediting this latest information, in conjunction with the sector analysis discussed in item 1, and the updated tubesheet temperature distribution discussed in item 2, leads to a further, significant reduction in the calculated H* value relative to values calculated in items 1 and 2. This information, includinq the latest pullout test data, has not been reviewed in detail by the staff. However, the staff concludes that H* estimates that include no credit for residual contact pressure (e.g., the estimates in items 1 and 2 above) are very conservative, as evidenced by the high pullout forces needed to overcome the residual contact pressure.

The new analyses, items 1, 2, and 3 above, also address a question posed by the staff in Reference 6 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. The staff concludes that this approach addresses the staffs question in a realistic fashion and is acceptable.

Based on item 1 above, and considering the significant conservatism associated with the assumption of zero residual contact pressure, the staff concludes that the proposed H* distance of 17.28 inches for Turkey Point Units 3 and 4 ensures that all tubes will have acceptable pullout resistance for normal operating and DBAs, even with the conservative assumption that all tubes are severed at the H* distance.

In addition, the licensee has committed to monitor for tube slippage as part of the SG inspection program. Under the proposed license amendment, TS 6.9.1.8.j will require that the results of slippage monitoring be included as part of the 180-day report required by TS 6.9.1.8. TS 6.9.1.8.j will also require that should slippage be discovered, the implications of the discovery and corrective action shall be included in the report. The staff finds that slippage is not expected to occur for the reasons discussed previously. In the unexpected event it should occur, it will be

- 16 important to understand why it occurred so that the need for corrective action can be evaluated.

The staff concludes the commitment to monitor for slippage and the accompanying reporting requirements are acceptable.

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 the coefficients of thermal expansion (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. In Reference 8, the staff highlighted the need to develop a rigorous technical basis for the CTE values, and their potential variability, to be employed in future H* analyses.

In response, Westinghouse had a subcontractor review the CTE data in question, determine the cause of the variance from the ASME Code CTE values, and provide a summary report (Reference 17). 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 degrees Fahrenheit (OF) to 1300 of. The polynomial fit chosen resulted in mean CTE values that were significantly different from the ASME Code values from 75 of to about 300 of. When the raw data was reanalyzed using the locally weighted least squares regression 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 a 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 of, which changed the microstructure and the CTE of the steel during decreasing temperature conditions. As a result of the altered microstructure, the CTE test data generated in the second test, conducted in air, was also invalidated. As a result of the large "dead band" region and the altered microstructure, both data sets were excluded from the final CTE values obtained from the CTE testing program.

The test program included multiple material heats to analyze chemistry influence on CTE values and repeat tests on the same samples were performed to analyze for test apparatus influence.

Because the tubes are strain hardened when they are expanded into the tubesheet, strain hardened samples were also measured to check for strain hardening influence on CTE values.

The data from the test program were combined with the ANL data that were found by the licensee to be acceptable, and with 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

- 17 was only present at low temperature. The CTE report is included as Appendix A to Reference 13.

The testing showed that the nominal ASME Code values for Alloy 600 and SA-50B 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-50B 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 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 staff concludes that the CTE values used in the H* analyses are fully responsive to the concerns stated in Reference 6 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 limiting condition for operation limits in TS 3/4.4.6, "RCS [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.B.4.j.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

-18 coefficient is constant with contact pressure such that the ratio is equal to 1. The staff agrees that this is a conservative assumption, provided there is a positive contact pressure for both conditions along the entire H* distance and provided that contact pressure increases at each axial location along the H* distance when going from normal operating to accident conditions.

Both assumptions were confirmed to be valid in the H* analyses.

Leakage factors were calculated for DBAs exhibiting a significant increase in primary-to secondary pressure differential, including MSLB, locked rotor, and control rod ejection. The design-basis MSLB transient was found to exhibit the highest leakage factor, 1.82, meaning that it is the transient expected to result in the largest increase in leakage relative to normal operating conditions.

The licensee provided the following commitment in Reference 2 that describes how the leakage factor will be used to satisfy TS 6.8.4.j.a for condition monitoring and TS 6.8.4.j.b.2 regarding performance criteria for accident induced leakage:

FPL commits that for the Turkey Point Units 3 and 4 Condition Monitoring assessment, the component of operational leakage from the prior cycle from below the H* distance will be multiplied by a factor of 1.82 and added to the total accident leakage from any other source and compared to the allowable accident induced leakage limit. For the Operational Assessment, the difference between the allowable accident induced leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 1.82 and compared to the observed operational leakage. An administrative operational leakage limit will be established to not exceed the calculated value.

The staff finds this license commitment acceptable, since it provides 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. The staff finds that the leakage factor of 1.82 conservatively bounds the increase in leakage from locations below the H* distance that may be induced by accident conditions relative to leakage from the same locations under normal operating conditions.

4.2.3 Proposed Change to TS 6.9.1.8, "Steam Generator (SG) Tube Inspection Report" The staff has reviewed the proposed revised reporting requirements and finds that they, in conjunction with existing reporting requirements, are sufficient to allow the staff to monitor the condition of the SG tubing as part of its review of the 180-day inspection reports, which are generally completed within 18 months after the reports are submitted. Based on this conclusion, the staff finds that the proposed revised reporting requirements are in accordance with 10 CFR 50.36(c)(5) and 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 will 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

- 19 corrosion cracking below the H* distance. In addition, the proposed H* distance conservatively takes no credit for residual contact pressure associated with the tube hydraulic expansion process.

As discussed in section 4.2.1.3, the staff does not have sufficient information to determine whether the tubesheet bore displacement eccentricity has been addressed in a conservative fashion. Thus, in spite of the significant conservatisms embodied in the proposed H* distance, the 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. However, the licensee is now requesting an interim amendment that is applicable to Unit 3 through Refueling Outage 25 (fall 2010) and the next operating cycle, and to Unit 4 during Refueling Outage 25 (fall 2009) and the subsequent operating cycles until the next scheduled inspection, rather than an amendment that is applicable to the remaining life of the plants. The staff finds that assuming all tubes will be severed at the H* distance over the next operating cycle(s) to be unrealistic and that the proposed H* distance is conservative for the next operating cycle(s) for the reasons cited below.

From a fleet-wide perspective (for all Westinghouse plants with tubes fabricated from thermally treated Alloy 600), the 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 1-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 staff's judgment, based on experience, that cracking in the fleet will continue to be limited to a small percentage of tubes, mostly near the tube ends. The staff's observations are based on the review of SG tube inspection reports from throughout the PWR fleet. These reports are reviewed and the staff's conclusions are documented generally within 18 months of each SG tube inspection.

References 18 and 19 provide recent examples of such reviews for Turkey Point Units 3 and 4 by the staff.

For Turkey Point Units 3 and 4, no inspections were performed in the bottom 4 inches of SG tubing during the most recent 2006 and 2007 inspections (References 20 and 21), and cracks in this region are a possibility, based on experience at other units. The SGs at Surry Units 1 and 2 are of similar design, operating time, and operating temperature, and inspections in the bottom 4 inches of SG tubing in Unit 1 and 2 were performed in 2009 and 2008, respectively. The results of the inspections showed that of the 24,725 tube ends inspected, 216 flaw indications were found within 1-inch of the tube ends. However, no indications of cracking were found at other locations relatively susceptible to stress corrosion cracking (e.g., at tube expansion transition locations or at other tube geometry discontinuity locations) at the Turkey Point and Surry units such as has been observed at other units in the fleet (Reference 22).

The licensee stated that the operating conditions for the Turkey Point Unit 3 and 4 SGs are less severe than those discussed in References 23 and 24, and therefore, the level of degradation in the SGs is also expected to be very limited. The staff agrees, noting that although the Turkey Point and Surry units have accumulated slightly more operating time than other units in the fleet

- 20 (in terms of effective full power years), these units operate at a relatively low hot leg temperature such that crack activity is expected to be within the envelope of fleet experience. The staff finds that this is confirmed by the absence of observed crack indications outside the lowermost 4-inch zone of tubing. The licensee also stated in Reference 2 that no primary-to-secondary SG tube leakage has been reported during the current operating cycles. Given the absence of detectable cracking outside the lowermost 4-inch zone of tubing at Turkey Point Units 3 and 4, and given the limited scope of cracking experienced in similar units, the staff concludes that the extent and severity of cracking at Turkey Point Units 3 and 4 to be limited and within the envelope of industry experience with similar units.

The staff concludes that there is sufficient conservatism embodied in the proposed H* distances to ensure acceptable margins against tube pullout for the reasons discussed above. The staff also concludes there is reasonable assurance that any potential accident induced leakage will not exceed the technical specification performance criteria for accident induced leakage. This 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 staff's 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 even should there be a loss of TrrS contact near the top of the tubesheet due to tubesheet bore eccentricity effects.

5.0 COMMITMENT FPL commits that for the Turkey Point Units 3 and 4 Condition Monitoring assessment, the component of operational leakage from the prior cycle from below the H* distance will be multiplied by a factor of 1.82 and added to the total accident leakage from any other source and compared to the allowable accident induced leakage limit. For the Operational Assessment, the difference between the allowable accident induced leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 1.82 and compared to the observed operational leakage. An administrative operational leakage limit will be established to not exceed the calculated value.

6.0

SUMMARY

The staff finds that the proposed amendment request acceptably addresses all issues identified by the staff in Reference 6 relating to H* amendment requests submitted prior to 2008 (which were subsequently withdrawn or modified). However, the staff does not have sufficient information to determine whether the tubesheet bore displacement eccentricity has been addressed in a conservative fashion and, thus, the staff does not have an adequate basis to approve a permanent H* amendment. Accordingly, the licensee modified its amendment request on September 30,2009 to be an interim amendment request, applicable only to Turkey Point Unit 3 through Refueling Outage 25 (fall 2010) and the subsequent operating cycle, and to Unit 4 during Refueling Outage 25 (fall 2009) and the subsequent operating cycles until the next scheduled inspection.

Notwithstanding any potential non-conservatism in the calculated H* distance which may be associated with the eccentricity issue, the staff concludes that, given the current state of the tubes, there is sufficient conservatism embodied in the proposed H* distances to ensure, for the

- 21 subsequent operating cycles until the next scheduled inspection, 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. Based on this finding, the staff further concludes that the proposed amendment is acceptable.

7.0 STATE CONSULTATION

Based upon a letter dated May 2,2003, from Michael N. Stephens of the Florida Department of Health, Bureau of Radiation Control, to Brenda L. Mozafari, Senior Project Manager, U.S. Nuclear Regulatory Commission, the State of Florida does not desire notification of issuance of license amendments.

8.0 ENVIRONMENTAL CONSIDERATION

These amendments involve a change in the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (74 FR 44405). Accordingly, these amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22( c)(9).

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

9.0 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 amendments will not be inimical to the common defense and security or to the health and safety of the public.

10. REFERENCES

1. Florida Power and Light Company (FPL), letter L-2009-151, "License Amendment Request No. 197 for H*: Alternate Repair Criteria for Steam Generator Tubesheet Expansion Region," July 23, 2009, NRC Agencywide Documents Access and Management System (ADAMS) Accession No. ML092300059. This letter also transmitted Reference 12.

2. FPL letter L-2009-209, September 30, 2009, responding to Turkey Point Units 3 and 4 RAls and amending its H* application to be a one-time change. This letter also transmitted WEC letter, LTR-SGMP-09-108-P (Proprietary) and LTR-SGMP-09-100-NP (Non-Proprietary) "Response to NRC Request for Additional Information on H*; Model 44F and 5'1 F Steam Generators," August 27,2009, NRC ADAMS Accession No. ML092800222.

- 22

3. FPL letter L-2009-241, October 26, 2009, amending its H* application to apply to only one operating cycle for Turkey Point Unit 3. NRC ADAMS Accession No. ML093010125.

4. Wolf Creek Nuclear Operating Corporation, Letter ET-06-004, "Revision to Technical Specification 5.5.9, "Steam Generator Tube Surveillance Program,"" February 21,2006, NRC ADAMS Accession No. ML060600456.

5. Wolf Creek Nuclear Operating Corporation, letter ET-08-0010, "Withdrawal of License Amendment Request for a Permanent Alternate Repair Criteria in Technical Speci'f1cation (TS) 5.5.9, "Steam Generator (SG) Program" February 14, 2008, NRC ADAMS Accession No. ML080580201.

6. 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, NRC ADAMS Accession No. ML080450185.

7. FPL letter L-2006-092, "Turkey Point Units 3 and 4, License Amendment Request for Steam Generator Alternate Repair Criteria for Tube Portion within the Tubesheet," April 27,2006, NRC ADAMS Accession No. ML061310089.

8. FPL letter L-2006-228, "Turkey Point Units 3 and 4, Revision to Proposed License Amendment Request Steam Generator Alternate Repair Criteria For Tube Portion within the Tubesheet," October 3,2006, NRC ADAMS Accession No. ML062920100.

9. NRC letter to FPL, Turkey Point Plant, Units 3 and 4 - Issuance of Amendments Regarding Steam Generator Alternate Repair Criteria, November 1, 2006, NRC ADAMS Accession No. ML062990169.

10. NRC Meeting minutes, "Summary of the October 29 and 30, 2008, Category 2 Public Meeting with the Nuclear Energy Institute (NEI) and Industry to Discuss Modeling Issues Pertaining to the Steam Generator Tube-to-tubesheet Joints," NRC ADAMS Accession No. ML083300422.

11. NRC Meeting minutes, "Summary of the January 9, 2009, Category 2 Public Meeting with the U.S. Nuclear Industry Representatives to Discuss Steam Generator H*/B* Issues,"

NRC ADAMS Accession No. ML090370945.

12. NRC Meeting minutes, "Summary of the April 3, 2009, Category 2 Public Meeting with the U.S. Nuclear Industry Representatives to Discuss Steam Generator H* Issues," April 30, 2009, NRC ADAMS Accession No. ML091210437.

13. Westinghouse Electric Company report, WCAP-17091-P (Proprietary) and WCAP-17091-NP (Non-Proprietary), Rev. 0, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 44F)," June 2009, NRC ADAMS Accession No. ML092300060.

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, NRC ADAMS Accession No. ML031070113.

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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.

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

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

dated June 6,2009, NRC ADAMS Accession No. ML082100097.

18. NRC letter to FPL, "Turkey Point Unit 3 - Summary of NRC's Review of the 2007 Steam Generator Tube Inspections," March 5, 2009, NRC ADAMS Accession No. ML090430253.

19. NRC letter to FPL, "Summary of Review of Reports for Turkey Point Unit 4 - 2006 Refueling Outage Steam Generator Tube Inspection," March 25, 2008, NRC ADAMS Accession No. ML080840499.

20. FPL letter L-2008-041, "Turkey Point Unit 3 Steam Generator Tube Inspection Report,"

April 03, 2008, NRC ADAMS Accession No. ML081050248.

21. FPL letter L-2007-036, "Turkey Point Unit 4 Inservice Inspection Report," March 08, 2007, NRC ADAMS Accession No. ML070710304.

22. Virginia Electric and Power Company letter 09-455B, "Surry Power Station Units 1 and 2, Proposed License Amendment Request, One-Time Alternate Repair Criteria for Steam Generator Tube Inspection/Repair for Units 1 and 2," September 30, 2009, NRC ADAMS Accession No. ML092800358.

23. NRC Information Notice 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds," April 7, 2005.

24. NRC Information Notice 2008-07, "Cracking Indications in Thermally Treated Alloy 600 Steam Generator Tubes," April 24, 2008.

Principal Contributor: E. Murphy A. Johnson Date: October 30, 2009

October 30,2009 Mr. Mano Nazar Senior Vice President, Nuclear and Chief Nuclear Officer Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420

SUBJECT:

TURKEY POINT UNITS 3 AND 4 - ISSUANCE OF AMENDMENTS REGARDING H*: ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBESHEET EXPANSION REGION (TAC NOS. ME1754 AND ME1755)

Dear Mr. Nazar:

The U.S. Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No. 241 to Renewed Facility Operating License No. DPR-31 and Amendment No. 236 to Renewed Facility Operating License No. DPR-41 for the Turkey Point Plant, Units Nos. 3 and 4, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated July 23, 2009, as supplemented by letters dated September 30 and October 26, 2009.

The amendments revise the inspection scope and repair requirments of TS 6.8.4.j, "Steam Generator (SG) Program," and to the reporting requirements of TS 6.9.1.8, "Steam Generator (SG) Tube Inspection Report."

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

Sincerely, IRAI Jason C. Paige, Project Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-250 and 50-251

Enclosures:

1. Amendment No. 241 to DPR-31

2. Amendment No. 236 to DPR-41

3. Safety Evaluation cc w/enclosures: Distribution via Listserv Distribution:

PUBLIC LPL2-2 RIF RidsNrrDorlLpl2-2 RidsNrrLABClayton (Hard copy) RidsOgcRp RidsAcrsAcnw_MailCTR RidsNrrDirsltsb RidsNrrDorlDpr RidsRgn2MailCenter RidsNrrPMTurkeyPoint RidsNrrDciCsgb ADAMS Accession No. ML092990489 *Memo dated NRR-058 OFFICE LPL2-2/PM LPL2-2/LA ITSB/BC CSGB/BC(A) OGC LPL2-2/BC NAME ~'Paige BClayton (CSola RElliott MGavrilas BHarris TBoyce for) (CSchulten (NLO wi for) comments)

DATE 10/28/09 10/28/09 10/30109 10/22/09* 10/29/09 10/30109 OFFICIAL RECORD COpy