ML072820018

License Amendment, Issuance of Amendment Regarding Technical Specification 5.5.9 Steam Generator Tube Surveillance Program

ML072820018
Person / Time
Site:	Catawba
Issue date:	10/31/2007
From:	Stang J NRC/NRR/ADRO/DORL/LPLII-1
To:	Morris J Duke Power Co
Stang J, NRR/DORL, 415-1345
Shared Package
ML072820013	List: ML072820018 ML073090413
References
TAC MD5554
Download: ML072820018 (15)

Text

October 31, 2007 Mr. J. R. Morris Site Vice President Catawba Nuclear Station Duke Power Company LLC 4800 Concord Road York, SC 29745

SUBJECT:

CATAWBA NUCLEAR STATION, UNIT 2, ISSUANCE OF AMENDMENT REGARDING TECHNICAL SPECIFICATION 5.5.9 STEAM GENERATOR TUBE SURVEILLANCE PROGRAM (TAC NO. MD5554)

Dear Mr. Morris:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 233 to Renewed Facility Operating License NPF-52 for the Catawba Nuclear Station, Unit 2 (Catawba Unit 2).

The amendments consist of changes to the Renewed Operating License and the Renewed Technical Specifications (TSs) in response to your application dated April 30, 2007.

The amendment revises TS 5.5.9, Steam Generator (SG) Tube Surveillance Program, regarding the required SG inspection scope for Catawba Unit 2 during the End of Cycle 15 Refueling Outage and Operating Cycle 16. The changes modify the tube repair criteria for portions of the SG tubes within the hot leg tubesheet region of the SGs.

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

Sincerely,

/RA/

John Stang, Senior Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-413 and 50-414

Enclosures:

1. Amendment No. 233 to NPF-52

2. Safety Evaluation cc w/encls: See next page

October 31, 2007 Mr. J. R. Morris Vice President Catawba Nuclear Station Duke Power Company LLC 4800 Concord Road York, SC 29745

SUBJECT:

CATAWBA NUCLEAR STATION, UNIT 2, ISSUANCE OF AMENDMENT REGARDING TECHNICAL SPECIFICATION 5.5.9 STEAM GENERATOR TUBE SURVEILLANCE PROGRAM (TAC NO. MD5554)

Dear Mr. Morris:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 233 to Renewed Facility Operating License NPF-52 for the Catawba Nuclear Station, Unit 2 (Catawba Unit 2).

The amendments consist of changes to the Renewed Operating License and the Renewed Technical Specifications (TSs) in response to your application dated April 30, 2007.

The amendment revises TS 5.5.9, Steam Generator (SG) Tube Surveillance Program, regarding the required SG inspection scope for Catawba Unit 2 during the End of Cycle 15 Refueling Outage and Operating Cycle 16. The changes modify the tube repair criteria for portions of the SG tubes within the hot leg tubesheet region of the SGs.

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

Sincerely,

/RA/

John Stang, Senior Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-414

Enclosures:

1. Amendment No. 233 to NPF-52

2. Safety Evaluation cc w/encls: See next page DISTRIBUTION:

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Package No.: ML072820013 Amendment No.: ML072820018 Tech Spec No.: ML073090413 *SE transmitted by memo dated OFFICE NRR/LPL2-1/PE NRR/LPL2-1/PM NRR/LPL2-1/LA NRR/CSGB/BC OGC NRR/LPL2-1/BC NAME DWright JStang MOBrien AHiser LSubin NLO EMarinos DATE 10/31/07 10/31/07 10/31/07 9/10/07 10/24/07 10/31/07 OFFICIAL RECORD COPY

DUKE POWER COMPANY LLC NORTH CAROLINA MUNICIPAL POWER AGENCY NO. 1 PIEDMONT MUNICIPAL POWER AGENCY DOCKET NO. 50-414 CATAWBA NUCLEAR STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 233 Renewed License No. NPF-52

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

A. The application for amendment to the Catawba Nuclear Station, Unit 2 (the facility) Renewed Facility Operating License No. NPF-52 filed by the Duke Power Company LLC, acting for itself, North Carolina Municipal Power Agency No. 1 and Piedmont Municipal Power Agency (licensees), dated April 30, 2007, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (I) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-52 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 233, which are attached hereto, are hereby incorporated into this license. Duke Power Company LLC shall operate the facility in accordance with the Technical Specifications.

3. Further, Renewed Facility Operating License No. NPF-52 is hereby amended by changes to a Condition on page 2 in Appendix B of the license to read as follows:

This amendment requires the licensee to use administrative controls, as described in the licensees letter of April 30, 2007, and evaluated in the Staffs Safety Evaluation dated October 31, 2007, to restrict the primary to secondary leakage through any one steam generator to 75 gallons per day and through all steam generators to 300 gallons per day (in lieu of the limits in TS Sections 3.4.13d. and 5.5.9b.3.), for Cycle 16 operation.

4. This license amendment is effective as of its date of issuance and shall be implemented within 30 days of issuance. The above license condition will be applicable only for the duration of Catawba Unit 2 Cycle 16 operation.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Evangelos C. Marinos, Chief Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to License No. NPF-52 and the Technical Specifications Date of Issuance: October 31, 2007

ATTACHMENT TO LICENSE AMENDMENT NO. 233 RENEWED FACILITY OPERATING LICENSE NO. NPF-52 DOCKET NO. 50-414 Replace the following pages of the Renewed Facility Operating License with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Unit 2 Remove Insert Page 4 Page 4 Page 5 Page 5 Appendix B, Page 2 Appendix B, Page 2 Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert 5.5-7a 5.5-7a

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 233 TO RENEWED FACILITY OPERATING LICENSE NPF-52 DUKE POWER COMPANY LLC CATAWBA NUCLEAR STATION, UNIT 2 DOCKET NO. 50-414

1.0 INTRODUCTION

By application dated April 30, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML071280284), Duke Power Company LLC (Duke, the license),

requested changes to the Technical Specifications (TSs) for the Catawba Nuclear Station, Unit 2 (Catawba Unit 2).

The requested changes would modify the required steam generator (SG) tube repair criteria for Catawba Unit 2 during Refueling Outage (RFO) 15 and Operating Cycle 16. In addition, the proposed amendment includes a license condition to require a reduction in the allowable normal operating primary-to-secondary leakage rate from the TS value of 150 gallons-per-day (TS 3.4.13.d) to 75 gallons-per-day through any one SG and from 600 gallons-per-day to 300 gallons-per-day through all SGs. The proposed license condition will be applicable only for the duration of Catawba Unit 2 Operating Cycle 16 operation. The license for Catawba Unit 1 is affected only due to the fact that Unit 1 and Unit 2 use common TSs.

The requested changes are identical in nature to the changes approved by the U.S. Nuclear Regulatory Commission (NRC) on March 31, 2006, for Catawba Unit 2 RFO 14 and Operating Cycle 15.

Catawba Unit 2 has four Model D5 recirculating, pre-heater-type SGs designed and fabricated by Westinghouse. The thermally treated Alloy 600 SG U-tubes have an outside diameter of 0.75 inches and a nominal wall thickness of 0.043 inches. The tube support plates are 1.125-inches thick stainless steel and have quatrefoil-broached holes. The tubes are hydraulically expanded for the full depth of the tubesheet.

The licensee has been using eddy current bobbin coil probes for inspecting the length of tubing within the tubesheet. However, the bobbin probe is not capable of reliably detecting stress corrosion cracks (SCC) in the tubesheet region should such cracks be present. For this reason, the licensee has been supplementing the bobbin probe inspections with rotating pancake coil probes in a region extending from 2 inches above the top of the tubesheet (TTS) to the end of the tube at the bottom of the tubesheet. This zone includes the tube expansion

transition zone located at the TTS. The expansion transition contains significant residual stress and was considered a likely location for SCC should it ever develop. Until the fall of 2004, there had not been any reported instances of SCC affecting the tubesheet region of thermally treated Alloy 600 tubing, either at Catawba Unit 2, or elsewhere in the United States.

In the fall of 2004, crack-like indications were found in tubes in the tubesheet region of Catawba Unit 2. These crack-like indications were found in bulges (or over-expansions) in the tubesheet region, in the tack roll region, and in the tube-to-tubesheet weld. (The tack expansion is an initial 0.7-inch long expansion at each tube end and formed prior to the hydraulic expansion over the full tubesheet depth. Its purpose was to facilitate performing the tube to tubesheet weld.) The crack-like indications were found in a bulge in one tube and in the tack expansion in nine tubes. Approximately 6 of the 196 tube-to-tubesheet weld indications extended into the parent tube.

The licensee believes that any flaws located more than 17 inches below the TTS (i.e., in the bottom 4 inches of the tubesheet region, including the tack expansion region and the tubing in the vicinity of the welds) have no potential to impair tube integrity, and, thus, do not pose a safety concern. To avoid unnecessary plugging or repair of tubes, the licensee requested and the NRC staff approved (License Amendment 224, ADAMS Accession No. ML060760111) a TS change which excluded degradation in the lowermost 4 inches of the tubesheet from application of the 40% depth-based tube repair criterion during Unit 2 End of Cycle 14 Refueling Outage and Cycle 15 operation. The licensee is now proposing to extend this exclusion to the End of Cycle 15 Refueling Outage and Cycle 16 operation.

1.1 Proposed Revision to TS 5.5.9.c TS 5.5.9.c currently states, in part:

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

For the Unit 2 End of Cycle 14 Refueling Outage and Cycle 15 operation only, the 40% depth based criterion does not apply to degradation identified in the portion of the tube below 17 inches from the top of the tubesheet. If degradation is identified in the portion of the tube from the top of the tubesheet to 17 inches below the top of the tubesheet, the tube shall be removed from service. If degradation is found in the portion of the tube below 17 inches from the top of the tubesheet, the tube does not require plugging.

The proposed amendment would revise the words, ...End of Cycle 14 Refueling Outage and Cycle 15," to read, ...End of Cycle 15 Refueling Outage and Cycle 16."

1.2 Proposed Revision of License Condition As a conservative measure, License Amendment 224 included a license condition (in Appendix B of the license) to limit normal operating primary-to-secondary identified leakage through one SG and the total leakage of all SGs for the duration of Operating Cycle 15. This license

condition is as follows:

This amendment requires the licensee to use administrative controls, as described in the licensees letter of February 2, 2006, and evaluated in the Staffs Safety Evaluation dated March 31, 2006, to restrict the primary to secondary leakage through any one steam generator to 75 gallons per day and through all steam generators to 300 gallons per day (in lieu of the limits in TS Sections 3.4.13d. and 5.5.9b.3.), for Cycle 15 operation.

Implementation Date: Prior to any entry to Mode 4 during Cycle 15.

The proposed amendment revises this licenses condition to read as follows:

This amendment requires the licensee to use administrative controls, as described in the licensees letter of April 30, 2007, and evaluated in the Staffs Safety Evaluation dated , to restrict the primary to secondary leakage through any one steam generator to 75 gallons per day and through all steam generators to 300 gallons per day (in lieu of the limits in TS Sections 3.4.13d.

and 5.5.9b.3.), for Cycle 16 operation.

Implementation Date: Prior to any entry to Mode 4 during Cycle 16.

2.0 REGULATORY EVALUATION

Steam generator tubes function as an integral part of the reactor coolant pressure boundary (RCPB) and serve to isolate radiological fission products in the primary coolant from the secondary coolant and the environment. For the purposes of this safety evaluation, tube integrity means that the tubes are capable of performing these functions in accordance with the plant design and licensing basis.

Title 10 of the Code of Federal Regulations (10 CFR) establishes the fundamental regulatory requirements with respect to the integrity of the SG tubing. Specifically, the General Design Criteria (GDC) in Appendix A to 10 CFR Part 50 state that the RCPB shall have "an extremely low probability of abnormal leakage ... and gross rupture" (GDC 14), "shall be designed with sufficient margin" (GDC 15 and 31), shall be of "the highest quality standards practical" (GDC 30), and shall be designed to permit "periodic inspection and testing of important areas and features to assess their structural and leaktight integrity" (GDC 32). Section 50.55a(c)(1) specifies that components that are part of the RCPB must meet the requirements for Class 1 components in Section III of the American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code (Code). Section 50.55a(g)(3)(i) of 10 CFR requires that throughout the service life of a pressurized-water reactor (PWR) facility, ASME Code Class 1 components meet the requirements in Section XI, "Rules for Inservice Inspection [ISI] of Nuclear Power Plant Components," of the ASME Code, to the extent practical. This requirement includes the inspection and repair criteria of Section XI of the ASME Code.Section XI requirements pertaining to Inservice Inspection (ISI) of SG tubing are augmented by additional SG tube surveillance requirements in the TSs.

As part of the plant licensing basis, applicants for PWR licenses are required to analyze the consequences of postulated design-basis accidents (DBAs) such as a SG tube rupture (SGTR) and main steamline break (MSLB). These analyses consider the primary-to-secondary leakage through the tubing which may occur during these events and must show that the offsite radiological consequences do not exceed the applicable limits of the 10 CFR Part 100 guidelines for offsite doses, GDC 19 criteria for control room operator doses, or some fraction thereof as appropriate to the accident.

Under the plant TS SG program requirements, the licensee is required to monitor the condition of the SG tubing and to plug tubes as necessary. Specifically, the licensee is required to perform periodic inspections of, and to repair or remove from service by plugging, all tubes found to contain flaws with sizes exceeding the acceptance limit, termed the "plugging limit."

The tube plugging limits were developed with the intent of ensuring that degraded tubes (1) maintain factors of safety against gross rupture consistent with the plant design basis (i.e., consistent with the stress limits of the ASME Code,Section III, and (2) maintain leakage integrity consistent with the plant licensing basis while allowing for potential flaw size measurement error and flaw growth between SG inspections. The requirements for SG tube plugging are specified in TS 5.5.9, "Steam Generator (SG) Program. The subject TS amendment request concerns the portions of the tubing that are subject to the TS SG program requirements related to plugging.

The proposed license amendment would limit plugging in the 21-inch thick tubesheet region to the upper 17 inches of the tubesheet region, and is conceptually similar to permanent amendments approved by the Nuclear Regulatory Commission (NRC) staff for a number of plants. Examples include the F* Criterion approved for Westinghouse SGs where the tubes were hard-roll expanded inside the tubesheet and the W* Criterion approved for plants where the tubes were explosively expanded against the tubesheet. In the case of the F* criterion, the required inspection zone was limited to approximately the upper 1.5-inch zone below the TTS.

The W* criterion required an inspection zone extending approximately 8 inches below the TTS.

The required inspection zone for W* is larger than for F* because the explosively expanded joints do not exhibit as much residual interference fit as do hard-rolled joints. The proposed license amendment for Catawba Unit 2 follows similar license amendment requests at other plants where the tubes are hydraulically expanded against the tubesheet (Braidwood, April 25, 2005, ADAMS Accession No. ML051110573; Byron, September 19, 2005, ADAMS Accession No. ML052230016; and several other units since that time). Wolf Creek Nuclear Operating Corporation obtained a second one-cycle amendment in the NRC letter dated October 10, 2006 (ADAMS Accession No. ML062580021). The NRC staff is currently reviewing a lead plant proposal for a permanent tubesheet amendment (Wolf Creek, ADAMS Accession No. ML060600456).

3.0 TECHNICAL EVALUATION

The tube-to-tubesheet joint consists of the tube, which is hydraulically expanded against the bore of the tubesheet, the tube-to-tubesheet weld located at the tube end, and the tubesheet.

The joint was designed as a welded joint in accordance with ASME Code,Section III, and not as a friction or expansion joint. The weld itself was designed as a pressure boundary element in accordance with ASME Code,Section III. It was designed to transmit the entire end cap pressure load during normal and DBA conditions from the tube to the tubesheet with no credit taken for the friction developed between the hydraulically expanded tube and the tubesheet.

In addition, the weld serves to make the joint leak tight.

The licensee is proposing to exempt tubes with flaw indications in the lower 4-inch zone from the need to plug. This proposal, in effect, redefines the pressure boundary at the tube-to-tubesheet joint as consisting of a friction or expansion joint with the tube assumed to be hydraulically expanded against the tubesheet over the top 17 inches of the tubesheet region.

Under this proposal, no credit is taken for the lower 4 inches of the tube or the tube-to-tubesheet weld in contributing to the structural or leakage integrity of the joint. The lower 4 inches of the tube and weld are assumed not to exist.

The regulatory standard by which the NRC staff has evaluated the subject license amendment is that the amended TSs should continue to ensure that tube integrity will be maintained.

This includes maintaining structural safety margins consistent with the plant design basis as embodied in the stress limit criteria of ASME Code,Section III, as discussed in Section 3.1 below. In addition, this includes limiting the potential for accident-induced primary-to-secondary leakage to values not exceeding those assumed in the licensing basis accident analyses.

Maintaining tube integrity in this manner ensures that the amended TSs are in compliance with all applicable regulations. The NRC staffs evaluation of joint structural integrity and leakage integrity is discussed in Sections 3.1 and 3.2, respectively, of this safety evaluation.

The licensee is also proposing to plug on detection any flaw indication found in the upper 17-inch region of the tubesheet region of the tubes, irrespective of whether the flaw exceeds the TS 40-percent plugging limit (see proposed TS 5.5.9c). The NRC staff finds this acceptable since it is more conservative than the current TS 40-percent plugging limit and will provide added assurance that the length of tubing within the uppermost 17 inches of the tubesheet will be effective in resisting tube pull-out under tube end cap pressure loads and in resisting primary-to-secondary leakage between the tube and tubesheet.

The proposed license condition to limit operational primary-to-secondary leakage to one-half the value allowed in TS 3.4.13d and TS 5.5.9b.3 provides added assurance of timely plant shutdown should leakage occur and, therefore, that the structural and leakage integrity of the tube to tubesheet joints will be maintained.

3.1 Joint Structural Integrity Westinghouse has conducted analyses and testing to establish the engagement (embedment) length of hydraulically expanded tubing inside the tubesheet that is necessary to resist pullout under normal operating and DBA conditions. Pullout is the structural failure mode of interest since the tubes are radially constrained against axial fish-mouth 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. The licensees contractor, Westinghouse, determined the required engagement distance on the basis of maintaining a factor of three against pullout under normal operating conditions and a factor of 1.4 against pullout under accident conditions. Pullout was conservatively treated as tube slippage relative to the tubesheet of 0.25 inches. The NRC staff finds this to be acceptable since these safety factors are consistent with those in the structural integrity performance criteria in proposed TS 5.5.9.b.1, TSTF-449, and the design basis (i.e.,

the stress limit criteria in the ASME Code,Section III). The NRC staff also finds the 0.25-inch

slip criterion to be acceptable, since there is still pullout resistance beyond this amount of slip.

The resistance to pullout is the axial friction force developed between the expanded tube and the tubesheet over the engagement distance. The friction force is a function of the radial contact pressure between the expanded tube and the tubesheet. The radial contact pressure derives from several contributors including (1) the contact pressure associated directly with the hydraulic expansion process, (2) additional contact pressure due to differential radial thermal expansion between the tube and tubesheet under hot operating conditions, (3) additional contact pressure caused by the primary pressure inside the tube, (4) reduced contact pressure due to pressure inside the crevice between the tube and tubesheet, and (5) additional or reduced contact pressure associated with tubesheet bore dilation (distortion) caused by tubesheet bow (deflection) as a result of the primary to secondary pressure load acting on the tubesheet. Westinghouse employed a combination of pullout tests and analyses, including finite element analyses of the tubesheet, to evaluate these contributors. Based on these analyses and tests, Westinghouse initially concluded (licensees letter dated November 18, 2005, Attachment 7) that the required engagement distances to ensure the safety factor criteria against pullout vary from 3 to 8.6 inches depending on the radial location of the tube within the tube bundle, with the largest engagement distances needed toward the center of the bundle. Westinghouse refers to the required engagement distance as the H*

criterion.

More recent analyses by Westinghouse have been conducted for similar Model D5 SGs at Byron 2 and Braidwood 2 (ADAMS Accession Nos. ML070470133, ML070540421, and ML070670126). These analyses reflect more conservative assumptions regarding pressure in the crevice region between the tube and the tubesheet based on recent test results compared to the assumptions used in the Catawba analyses. These revised analyses also utilized a more refined, more realistic finite element model of the tubesheet than was used for the Catawba analyses. In addition, these analyses considered a case where the SG divider plate provided no restraint to tubesheet deflection under primary-to-secondary pressure. This case was considered to bound the worst implications of cracks at and near the divider plate to tubesheet welds. The revised analyses, including the assumption of no divider plate restraint against tubesheet deflection, shows that the tube-to-tubesheet engagement distance that is needed to provide the required margins against pullout is 6.2 to 11.5 inches, compared to 3 to 8.6 inches indicated by the original analysis. The revised engagement distances are well within the 17-inch inspection zone proposed for Catawba Unit 2.

The technical basis for the proposed 17-inch tubesheet inspection zone and associated tube repair criteria is based in part on pullout tests conducted on nine tube-to-tubesheet joint specimens. These specimens utilized cylindrical collars to simulate the actual tubesheet. The test collars were fabricated from 1018 steel rather than A508 steel from which the tubesheet is actually fabricated. When analyzing the results of the pullout tests, Westinghouse assumed that the thermal expansion coefficient (TEC) for 1018 steel was identical to that for A508 steel, consistent with the applicable nominal thermal expansion coefficients in Section II, Part D of the ASME Code. However, the recent analyses for the similar Model D5 SGs at Byron 2 and Braidwood 2 (ADAMS Accession Nos. ML070470133, ML070540421, and ML070670126) also considered a case for which the pullout test results were evaluated using a lower value of TEC published in the literature for 1018 steel. This change affects the apportionment of the measured pullout loads to that provided by the tube hydraulic expansion process versus that

provided by differential thermal expansion between the tube and tubesheet. This was found to increase the required engagement distance at the limiting tube radial location from 11.5 inches to 12.6 inches, still well within the proposed 17-inch inspection zone.

The NRC staff has not completed its review of the Westinghouse analyses and, thus, has not reached a conclusion with respect to whether 12.6 inches of engagement is adequate to ensure that the necessary safety margins against pullout are maintained. (The NRC staff is continuing to review the Westinghouse analyses in the context of a lead plant permanent amendment request for Wolf Creek (ADAMS Accession No. ML060600456)). The licensee, therefore, is proposing to extend the applicability of the current TS provision for ensuring 17 inches of engagement for one additional cycle, to the Catawba Unit 2 End of Cycle 15 Refueling Outage and Cycle 16 operation. The NRC staff finds this proposal acceptable for the following reasons:

• Pullout tests of 9 samples indicate that the radial contact pressure between the tube and tubesheet produced by the tube hydraulic expansion coupled with the contact pressure due to differential thermal expansion between the tube and tubesheet (due to a higher thermal expansion coefficient for the Alloy 600 tubing as compared to the A508 steel tubesheet) for joint temperatures ranging from room temperature to 600 EF is such as to require an engagement distance of 2 to 6.6 inches to ensure the appropriate safety margins against pullout. This 2 to 6.6 inch spread reflects very considerable scatter in the pullout data, but is well within the proposed 17-inch inspection zone. This argument is not impacted by the thermal expansion coefficient issue discussed above since it relies on the actual pullout force data rather than inferences from that data as to the relative roles of the tube hydraulic expansion and differential thermal expansion between the tube and tubesheet in resisting pullout.

• The primary pressure inside the tube exceeds the average pressure outside the tube over the length of the tube to tubesheet crevice, acting to tighten the joint relative to unpressurized conditions under which the pullout tests were performed. The pressure differential across the tube wall is reduced in the revised analysis relative to the original analysis, but remains positive when averaged over the 17-inch inspection zone.

• Tubesheet bore dilations caused by tubesheet bow under primary-to-secondary pressure can increase or decrease contact pressure depending on the tube location within the bundle and on location along the length of the tube in the tubesheet region.

The tubesheet acts as a flat, circular plate under an upward acting net pressure load.

The tubesheet is supported axially around its periphery with a partial restraint against tubesheet rotation provided by the SG shell and channel head. The SG divider plate provides a spring support against upward displacement along a diametral mid-line.

Over most of the tubesheet away from the periphery, the bending moment resulting from the applied primary-to-secondary pressure load can be expected to put the tubesheet into tension at the top and compression at the bottom. Thus, the resulting distortion of the tubesheet bore (tubesheet bore dilation) tends to be such as to loosen the tube-to-tubesheet joint at the top of the tubesheet and to tighten the joint at the bottom of the tubesheet. The amount of dilation and resulting change in joint contact pressure would be expected to vary in a linear manner from top to bottom of the tubesheet. Given the neutral axis to be at approximately the axial mid-point of the tubesheet thickness (10.5 inches below the top of the tubesheet), tubesheet bore dilation effects would be expected to further tighten the joint from 10 inches below the

TTS to 17 inches below the TTS which would be the lower limit of the proposed tubesheet region inspection zone. Combined with the effects of the joint tightening associated with differential pressure across the tube wall, contact pressure over at least a 6.5-inch distance will be significantly higher than the contact pressure simulated in the above mentioned pull out tests. A similar logic applied to the periphery of the tubesheet leads the NRC staff to conclude that at the top 10.5 inches of the tubesheet region, contact pressure should be considerably higher than the contact pressure simulated in the above mentioned pull out tests.

3.2 Joint Leakage Integrity If no credit is to be taken for the presence of the tube-to-tubesheet weld, a potential leak path between the primary-to-secondary is introduced between the hydraulically expanded tubing and the tubesheet. In addition, not inspecting the tubing in the lower 4 inches of the tubesheet region may lead to an increased potential for 100% throughwall flaws in this zone and the potential for leakage of primary coolant through the crack and up between the hydraulically expanded tubes and tubesheet to the secondary system. Operational leakage integrity is assured by monitoring primary-to-secondary leakage relative to the applicable TS limiting condition for operation (LCO) limits. However, it must also be demonstrated that the proposed TS changes do not create the potential for leakage during DBAs which may exceed values assumed in the licensing basis accident analyses. The licensee states that this is ensured by limiting primary-to-secondary leakage to 0.5 gallons per minute (gpm) in the faulted SG during an MSLB.

To support its H* criterion (discussed in Section 3.1), Westinghouse has developed a detailed leakage prediction model which considers the resistance to leakage from cracks located within the thickness of the tubesheet. The NRC staff has not reviewed or accepted this model. To support a temporary 17-inch inspection zone, Westinghouse cited a number of qualitative arguments supporting a conclusion that a minimum 17-inch engagement length ensures that leakage during an MSLB will not exceed two times the observed leakage during normal operation. Westinghouse refers to this as the bellwether approach. Thus, for a SG leaking at the TS LCO limit of 150 gallons per day (gpd) under normal operating conditions, Westinghouse estimates that leakage would not be expected to exceed 0.21 gpm (300 gpd),

significantly less than the 0.5 gpm assumed in the licensing basis accident analyses for an MSLB.

The factor of two upper bound is based on the Darcy equation for flow through a porous media where leakage rate would be proportional to differential pressure. Westinghouse considered normal operating pressure differentials between 1200 and 1400 psi and accident differential pressures on the order of 2560 to 2650 psi, essentially a factor of 2 difference. The factor of 2 as an upper bound is based on a premise that the flow resistance between the tube and tubesheet remains unchanged. Westinghouse states that the flow resistance varies as a log normal linear function of joint contact pressure. The NRC staff concurs that the factor of two upper bound appears to be reasonable, given the stated premise. The NRC staff notes that the assumed linear relationship between leak rate and differential pressure is conservative relative to alternative models such as Bernoulli or orifice models which assume leak rate to be proportional to the square root of differential pressure.

The NRC staff reviewed the qualitative arguments developed by Westinghouse regarding the

conservatism of the aforementioned premise; namely the conservatism of assuming that flow resistance between the expanded tubing and the tubesheet does not decrease under the most limiting accident relative to normal operating conditions. Most of the Westinghouse observations are based on insights derived from the finite element analyses performed to assess joint contact pressures and from test data relating leak flow resistance to joint contact pressure, neither of which have been reviewed by the NRC staff in detail. Among the Westinghouse observations is that for all tubes, there is at least an 8-inch zone in the upper 17 inches of the tubesheet where there is an increase in joint contact pressure due to higher primary pressure inside the tube and changes in tubesheet bore dilation along the length of the tubes. The revised analyses described in the licensees letters dated February 15 and 23, 2007 (and discussed in Section 3.1 of this safety evaluation), do not affect this observation. The NRC staff observed that there is at least a 6.5-inch zone over which changes in tubesheet bore dilations when going from unpressurized to pressured conditions should result in an increase in joint contact pressure. The contact pressure due to changes in tubesheet bore dilation should increase further over this 6.5-inch zone under the increased pressure loading on the tubesheet during accident conditions. Considering the higher pressure loading in the tube when going from normal operating to accident conditions, the Westinghouse estimate that contact pressures, and, thus, leak flow resistance, always increase over at least an 8-inch distance appears reasonable to the NRC staff.

Although joint contact pressures and leak flow resistance decrease over other portions of the tube length, Westinghouse expects a net increase in total leak flow resistance on the basis of its insights from leakage test data that leak flow resistance is more sensitive to changes in joint contact pressure as contact pressure increases due to the linear log normal nature of the relationship. The NRC staffs depth of review did not permit it to credit this aspect of the Westinghouse assessment. However, it is clear from the above discussion that there should be no significant reduction in leakage flow resistance when going from normal operating to accident conditions.

The NRC staff has considered that undetected cracks in the lower 4 inches are unlikely to produce leakage rates during normal operation that would approach the TS LCO operational leakage limits, thus providing additional confidence that such cracks will not result in leakage in excess of the values assumed in the accident analyses. Any axial cracks will be tightly clamped by the tubesheet, limiting the opening of the crack faces. In addition, little of the end cap pressure load should remain in the tube below 17 inches from the TTS and, thus, any circumferential cracks would be expected to remain tight. Therefore, irrespective of the flow resistance in the upper 17 inches of the tubesheet between the tube and tubesheet, the tightness of the cracks themselves should limit leakage to very small values.

4.0

SUMMARY

The NRC staff concludes that any primary-to-secondary leakage existing under normal full power operating conditions would not increase by more than a factor of 2 for DBAs such as an MSLB. Since operating leakage is limited by the LCO limit in TS 3.4.13 to 150 gpd, the maximum possible leakage from the lowermost 4 inches inside the tubesheet will not exceed the applicable acceptance criterion of 0.5 gallons per day per SG consistent with proposed TS 5.5.9.b.2 and with the current licensing basis. The NRC staff finds that the proposed license amendment, which is applicable to Catawba Unit 2 Refueling Outage 15 and subsequent

Operating Cycle 16, ensures that the structural and leakage integrity of the tube-to-tubesheet joint will be maintained during this period with structural safety margins consistent with the design basis, with leakage integrity within assumptions employed in the licensing basis accident analysis, and, thus, in accordance with the applicable regulations without undue risk to public health and safety.

6.0 STATE CONSULTATION

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

7.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of facility components 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 amendment involves no significant hazards consideration, and there has been no public comment on such finding (72 FR 45272). The amendment also relates to changes in recordkeeeping, reporting, or administrative procedures or requirements. Accordingly, the amendment meets the eligibility criteria for categorical exclusions set forth in 10 CFR 51.22(c)(9) and (c)(10). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

8.0 CONCLUSION

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

Principal Contributor: Andrew Johnson Date: October 31, 2007