L-10-063, License Amendment Request No. 09-005, Revised Steam Generator Inspection Scope

License Amendment Request No.09-005, Revised Steam Generator Inspection Scope

ML100630422
Person / Time
Site:	Beaver Valley
Issue date:	02/26/2010
From:	Harden P FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-10-063, LAR 09-005
Download: ML100630422 (42)

Text

FENOC Beaver Valley Power Station P.O. Box 4 FirstEnergyNuclear OperatingCompany Shippingport, PA 15077 PaulA. Harden 724-682-5234 Site Vice President Fax: 724-643-8069 February 26, 2010 L-10-063 10 CFR 50.90 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Beaver Valley Power Station, Unit No. 2 Docket No. 50-412, License No. NPF-73 License Amendment Request No.09-005, Revised Steam Generator Inspection Scope Pursuant to 10 CFR 50.90, FirstEnergy Nuclear Operating Company (FENOC) hereby requests to amend the Beaver Valley Power Station, Unit No. 2 (BVPS-2) Technical Specifications to revise the scope of the steam generator cold-leg tube-sheet inspections using the F* methodology.

The FENOC evaluation of the proposed change is provided in the enclosure. The enclosure contains the proposed Technical Specification changes in Attachment 1, and retyped Technical Specification pages (incorporating the proposed changes) in Attachment 2.

FENOC requests approval of the proposed amendment by March 4, 2011, to support implementation of the proposed changes for the BVPS-2 refueling outage scheduled for the spring of 2011. Once approved, the amendment shall be implemented within 60 days.

lip" Beaver Valley Power Station, Unit No. 2 L-1 0-063 Page 2 There are no regulatory commitments contained in this letter. If there are any questions or if additional information is required, please contact Mr. Thomas A. Lentz, Manager-Fleet Licensing, at 330-761-6071.

I declare under penalty of perjury that the foregoing is true and correct. Executed on February .2o' , 2010.

Paul A. Harden

Enclosure:

FENOC Evaluation of the Proposed Change cc: NRC Region I Administrator NRC Senior Resident Inspector NRC Project Manager Director BRP/DEP Site BRP/DEP Representative

Beaver Valley Power Station, Unit No. 2 License Amendment Request No.09-005 FENOC Evaluation of the Proposed Change

Subject:

Unit 2 F* (F Star) Inspection Methodology for Steam Generator Cold-Leg Table of Contents Section Title Page 1.0

SUMMARY

DESCRIPTION ....................................................................... 1 2.0 DETAILED DESCRIPTION ....................................................................... 2

3.0 TECHNICAL EVALUATION

....................................................................... 3

4.0 REGULATORY EVALUATION

................................................................. 19 4.1 Significant Hazards Consideration ............................................................ 19 4.2 Applicable Regulatory Requirements/Criteria .......................................... 21 4 .3 P re ced e nt ................................................................................................ . . 22 4 .4 C o nclusio ns ........................................................................................... . . 22

5.0 ENVIRONMENTAL CONSIDERATION

................................................... 23 6 .0 R E F E R E NC E S ........................................................................................ . . 23 Attachments Number Title 1 Proposed Technical Specification Changes 2 Retyped Technical Specification Pages

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 1 of 24 1.0

SUMMARY

DESCRIPTION FirstEnergy Nuclear Operating Company (FENOC) requests amendment of Operating License NPF-73 for Beaver Valley Power Station Unit No. 2 (BVPS-2). The proposed amendment would revise the Technical Specifications by expanding the scope of the steam generator tubesheet inspections using the F* inspection methodology to the steam generator (SG) cold-leg tubesheet region.

Background

On April 11, 2005 FENOC requested approval to use the F* inspection methodology for the hot-leg region of the tubesheet (Reference 1). By letter dated September 27, 2006 (Reference 2), the Nuclear Regulatory Commission (NRC) issued Amendment No. 160 to the Facility Operating License for BVPS-2 approving the request.

Reference 1 contained markups to Technical Specification 3/4.4.5, "Steam Generators," which was the version of the SG Technical Specification at the time of the submittal. Reference 1 also submitted WCAP-16385-P, Revision 1, "F* Tube Plugging Criterion for Tubes with Degradation in the Tubesheet Roll Expansion Region of Beaver Valley Unit 2 Steam Generators," dated March 2005. Since WCAP-16385-P, Revision 1, has been previously submitted to the NRC, it is not included with this submittal, although it is referenced throughout.

On November 7, 2005 FENOC requested approval to incorporate Technical Specification Task Force (TSTF) Change Traveler TSTF-449, "Steam Generator Tube Integrity," Revision 4, into the BVPS-2 Technical Specifications. By letter dated September 7, 2006 (Reference 3), the NRC issued Amendment No. 158 to the Facility Operating License for BVPS-2 approving the request. The license amendment request (LAR) for this amendment contained markups to Technical Specification 3/4.4.5, "Steam Generators," which was the version of the SG Technical Specification at the time of the submittal. Amendment 158 created Technical Specification 3/4.4.5, "Steam Generator (SG) Tube Integrity," Specification 6.9.7, "Steam Generator Tube Inspection Report," and Specification 6.19, "Steam Generator (SG) Program."

Implementation of Amendment 158 resulted in steam generator inspection, repair and reporting requirements being relocated to the Administrative Control Section of the Technical Specifications. Amendments 158 and 160 were both implemented on October 20, 2006 which resulted in the changes associated with SG inspection, repair and reporting requirements that were proposed in the LAR for Amendment 160 appearing in the Administrative Control Section of the Technical Specifications, namely Specifications 6.9.7 and 6.19.

On February 25, 2005 FENOC requested approval to convert the Beaver Valley Power Station Technical Specifications to the Improved Technical Specifications. By letter dated February 21, 2007 (Reference 4), the NRC issued Amendment No. 161 to the Facility Operating License for BVPS-2 approving the request. Amendment 161 not only converted the Beaver Valley Power Station Technical Specifications to the Improved Technical Specifications, it also resulted in common Technical Specifications for both of the Beaver Valley Power Station units. Amendment 161 also renumbered

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 2 of 24 the Administrative Control Section of the Technical Specifications to 5.0. Amendment 161 was implemented on June 23, 2007.

The approval and implementation of Amendments 158, 160 and 161 results in the changes proposed in this LAR being made to Specification 5.5.5.2, "Unit 2 Steam Generator Program," and Specification 5.6.6.2, "Unit 2 SG Tube Inspection Report,"

since the Administrative Control Section of the Technical Specifications is where SG inspection, repair and reporting requirements are contained.

By letter dated October 10, 2008, (Reference 5), FENOC requested an amendment to the operating license for BVPS-2 that would modify the Technical Specifications to allow an additional method of repair for steam generator tubes involving the use of Westinghouse leak limiting Alloy 800 sleeves. The proposed amendment would also clarify an existing reporting requirement concerning steam generator tube inspection.

By letter dated July 14, 2009, (Reference 6), FENOC submitted revisions to the proposed changes to the Technical Specification submitted in Reference 5 in order to satisfy a commitment made in the responses to an NRC request for additional information dated May 19, 2009. As a result, the Technical Specification changes submitted in Reference 6 supersede those submitted in Reference 5.

Amendment No. 170 (Accession No. ML092590189, dated September 30, 2009) was issued in response to Reference 6. This amendment revised Technical Specification 5.5.5.2, "Unit 2 Steam Generator Program," and Specification 5.6.6.2, "Unit 2 Steam Generator Tube Inspection Report," to allow an additional method of repair for steam generator tubes and to clarify a steam generator tube inspection reporting requirement.

2.0 DETAILED DESCRIPTION The proposed Technical Specification changes, which are submitted for NRC review and approval, are provided in Attachment 1. Retyped Technical Specification replacement pages are provided in Attachment 2. The retyped replacement pages are provided to show the Technical Specification pages after the proposed changes have been incorporated. There are no associated changes to the Technical Specification Bases or the Licensing Requirements Manual.

The proposed changes to the Technical Specifications have been prepared electronically. Deletions are shown with a strike-through, insertions are shown underlined, and revision bars identifying the changed lines of text are shown in the right page margin. This presentation allows the reviewer to readily identify the information that has been deleted and added. To meet format requirements the Technical Specifications pages will be repaginated as necessary to reflect the changes being proposed in this LAR.

Specifically, the proposed changes will revise Specifications 5.5.5.2, "Unit 2 Steam Generator Program," and Specification 5.6.6.2, "Unit 2 Steam Generator Tube Inspection Report."

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 3 of 24 Specifications 5.5.5.2.d will be revised adding a new Specification 5.5.5.2.d.6 that specifies when the F* methodology shall be implemented to the cold-leg tubesheet region. This new specification will result in the renumbering of Specification 5.5.5.2.d.6. The first paragraph of Specification 5.5.5.2.d will also be revised to reflect the addition of the new Specification 5.5.5.2.d.6.

Specifications 5.5.5.2.c.5, 5.5.5.2.c.5.a and 5.5.5.2.c.5.b will be revised to show that the F* methodology also applies to the cold-leg tubesheet region. Specification 5.5.5.2.c.5.a will also be revised by changing 2.2 inches to 2.22 inches.

Specification 5.6.6.2.4 will be revised to also require that a 90 day report be submitted when the F* methodology was applied to the cold-leg tubesheet region.

3.0 TECHNICAL EVALUATION

BVPS-2 SG Description The SGs at BVPS-2 are Westinghouse Model 51M with a U-tube configuration. Each tube is secured in the tubesheet above the lower plenum of the SG by a mechanical roll process. The mechanical roll process expands each tube over its entire length within the tubesheet and forms an interference fit between the tube and tubesheet.

This interference fit structurally supports the tube and provides a leak-tight boundary between the primary and secondary systems at each end of the SG tube. The tube is also welded to the tubesheet at each end. The region at the top-of-tubesheet where a tube transitions between its expanded diameter and its nominal diameter is referred to as the roll expansion transition region.

A tube inspection criterion, referred to as F*, has been developed by Westinghouse Electric Company LLC (Westinghouse) to permit tubes with observed and/or postulated degradation in the mechanical roll tubesheet expansions below the F*

distance to remain in service. The F* analysis defines an undegraded F* length that assures adequate strength is available to resist the axial pullout loads experienced within the tubesheet and ensure leakage integrity. The current hot-leg SG tube inspection scope excludes the length of tubing below the F* distance or 3.00 inches below the top-of-tube sheet, whichever is greater. The change being proposed would also exclude this tubing from the cold leg SG tube inspection scope.

Technical Justification WCAP-1 6385-P (Reference 8) describes the application of the F* methodology for BVPS-2 and includes a statement that SG outlet temperatures were used for the calculation of the F* values. The calculation documenting the F* analysis for BVPS-2 includes calculation output for a temperature differential (AT) of 471°F with a normal operating pressure differential of 1476 pounds per square inch (psi) and a faulted condition pressure differential of 2650 psi. The calculation determines the F* value to be 1.766 inches from the top-of-tubesheet under normal conditions, and 1.967 inches from the top-of-tubesheet under faulted conditions. These values were rounded to 1.77 inches and 1.97 inches in Table 2-4 of WCAP-1 6385-P. Therefore, the F* values

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 4 of 24 provided in WCAP-16385-P are calculated for conditions consistent with the cold leg as the applied AT of 471'F is developed for a temperature of 541°F minus 70°F (ambient). The calculation also includes a pressure sensitivity case where a AT of 471'F and a normal condition pressure differential of 1550 psi were used. The normal condition F* value for the top-of-tubesheet from the pressure sensitivity case was determined to be 1.81 inches, which is bounded by the faulted condition F* value of 1.97 inches. To assess temperature sensitivity, a normal pressure differential of 1550 psi and a AT of 465°F were input to the calculation that was used for the original analysis. The F* values determined for this case are unchanged from the F* values determined by the pressure sensitivity case. Therefore, WCAP-16385-P can be used to support this license amendment request for expansion of the F* methodology to the cold-leg tubesheet region of the BVPS- 2 steam generators.

The following definitions associated with inspection of the hot-leg tubesheet region are also applicable to the cold-leg tubesheet region.

Definitions:

BRT - Bottom of the roll transition and is defined in WCAP-1 6385-P, Section 3.0, as a nominal 0.28 inches from the top of the hot-leg or cold-leg tubesheet.

F* Length - The maximum length of tubing below the BRT which must be demonstrated to be non-degraded and is defined in WCAP-16385-P, Section 2.2.3, as 1.97 inches below the BRT.

F* distance - The distance from the top of the tubesheet to the bottom of the F* length, including the distance to the BRT and non-destructive examination (NDE) uncertainties. Uncertainties are defined in WCAP-16385-P, Section 2.5, as 0.25 inch.

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 5 of 24 Sketch of F* Distance in BVPS-2 Hot-leg or Cold-leg Tubesheet t

AL 1/2ffi SECONDA TTS - 0.28" F* Distance (= F* length +

distance to BRT + NDE measurement uncertainties)

RPC inspection depth (Top-of-Tubesheet - 3.0")

OR F* Distance, whichever is greater.

All service induced degradation observed in this region will be repaired TUBESHEET or plugged upon detection.

THICKNESS = 21.00" All service induced degradation observed in this region is acceptable for continued operation.

& B PRIMARY SDE FENOC's proposed change revises the tube inspection definition with respect to the cold-leg tubesheet region. In this region, tube inspection would include only the portion of the tube within the F* distance or 3.00 inches below the top-of-tubesheet, whichever is greater. Tube inspection would not include the tube-to-tubesheet weld:

The proposed change adds a requirement that tubes with service-induced degradation identified in the F* distance or less than or equal to 3.00 inches below the top-of-tubesheet, whichever is deeper into the tubesheet, shall be repaired or removed from service upon detection. Service induced degradation below this region in the tubesheet would be acceptable for continued operation. The proposed change is based on methodology described in WCAP-1 6385-P that was developed by Westinghouse Electric Company LLC. WCAP-1 6385-P was developed to demonstrate the applicability of the methodology documented in WCAP-1 1306, Revision 2 (Reference 9) to the BVPS-2 steam generators. WCAP-1 1306 documented the F* alternate repair criteria methodology and analysis that was approved by the NRC for the Farley Unit 2 steam generators, which accounted for the reinforcing effect that the tubesheet has on the external surface of the SG tube within

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 6 of 24 the tubesheet region. This analysis showed that tube integrity and leakage below the F* length remained within the existing design limits. WCAP-1 1306 was approved by the Nuclear Regulatory Commission for Farley Unit 2 in License Amendment 64.

[Operating License No. NPF-8, Docket No. 50-364, ML013130645]

Using BVPS-2 operating conditions, WCAP-1 6385-P defines the maximum F* length for pullout resistance as 1.97 inches below the bottom of the roll transition. This value is increased to 2.22 inches by an allowance for NDE uncertainties. The maximum NDE uncertainty on the F* length in WCAP-16385-P is 0.25 inches. The required inspection distance below the top-of-tubesheet is then 2.50 inches which includes a 0.28 inch distance from the top-of-tubesheet to the bottom of the roll transition. The 0.28 inch distance represents the lower 9 9th percentile BRT value for the cold legs of the BVPS-2 steam generators as determined using eddy current data for all active tubes obtained during the ninth refueling outage. The BRT information is used to ensure that all cold leg tubes are inspected to a distance which satisfies the F* length.

The F* analysis detailed in WCAP-1 1306 provides the basis for tubes with any form of degradation below the F* length to remain in service. The presence of the surrounding tubesheet prevents tube rupture and provides resistance against axial pullout loads during normal and accident conditions. In addition, primary-to-secondary leakage from tube degradation below the F* length is not expected for postulated steam line break (SLB) event conditions and will not affect offsite dose calculations and, therefore, can be neglected. A complete circumferential separation below the inspection distance would not be expected to result in primary-to-secondary leakage at SLB conditions.

Consequently, any tube degradation that may go undetected in the area below the inspection distance would not affect structural or leakage integrity. An inspection distance of 3.0 inches (rather than 2.5 inches) below the top-of-tubesheet is included in the current Technical Specifications for conservatism.

Currently, BVPS-2 SG inspection fulfills Specification 5.5.5.2.d.5 requirements for inspecting SG tubing by performing 100 percent full-length inspection of each tube using a bobbin coil probe. To reduce the probability and consequences of SG tube rupture or tube failure, BVPS-2 performs rotating pancake coil (RPC) probe inspections in critical regions for crack-like indications that would not be easily identified with the bobbin coil probe. These critical regions are based on a degradation assessment that defines where potential and existing degradation is expected in SG tubes that could challenge structural and/or leakage integrity if the tubes were not repaired or removed from service.

The critical region of the tubes in the tube-to-tubesheet expansion in Westinghouse Model 51 M SGs with mechanical roll expansions is defined as the F* length. The F*

length is defined for BVPS-2 in WCAP-16385-P considering the most stringent loads associated with plant operation, including transients, and accident conditions. Below the F* distance (F* length + distance to BRT + NDE measurement uncertainties), any degradation is acceptable.

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 7 of 24 FENOC does not propose to use WCAP-1 6385-P as an alternate repair criterion to leave tubes degraded within the F* distance in service. Instead, the proposed amendment would use WCAP-1 6385-P as the basis for defining the length of tubing in the cold-leg tubesheet region that would be inspected using a qualified inspection technique. The F* requirements for the hot-leg tubesheet region have been incorporated into the Technical Specifications by Amendment 160. Tubes with service-induced degradation identified in the F* distance or less than or equal to 3.00 inches below the top-of-tubesheet, whichever is greater, are repaired or removed from service upon detection. Service induced degradation below this region in the tubesheet is acceptable for continued operation.

Tube burst is precluded for cracks within the tubesheet by the constraint provided by the tubesheet. Thus, structural criterion is satisfied by the tubesheet constraint.

However, a 360-degree circumferential crack could permit severing of the tube and tube pullout from the tubesheet under the axial forces on the tube from primary to secondary pressure differentials. Section 4 of WCAP-16385-P describes the testing that was performed to define the length of non-degraded tubing that is sufficient to compensate for the axial forces on the tube and thus prevent pullout. WCAP-16385-P details the effects of the differences in operating conditions utilized in WCAP-1 1306 for Farley Unit 2 and the operating conditions defined for BVPS-2 on the F* engagement length.

Operating experience has demonstrated negligible normal operating leakage from primary water stress corrosion cracking (PWSCC) for 100 percent through wall (TW) conditions in roll transitions. PWSCC in roll expansions in the tubesheet region would be leakage limited by the tight tube-to-tubesheet crevice, increased material property strength values due to cold working, the limited crack opening permitted by the tubesheet constraint, and the limited flaw length, which is controlled by the stress field due to the expansion process. Operating experience from French pressurized water reactors, which use a roll expansion process, indicates that some plants have thousands of PWSCC flaws at the expansion transition with little observed primary-to-secondary leakage at normal operating conditions. Steam line break conditions provide the most severe radiological consequences for postulated accidents involving loss of pressure or fluid in the secondary system. WCAP-1 1306 describes the methodology for calculating leakage for cracks left in service and the justification for neglecting the total contribution of leakage through cracks below the F* length to steam line break consequences. Therefore, inspection of the area below the F*

distance is not necessary to preclude normal operating or accident induced leakage.

Shotpeening of the hot and cold leg tube-in-tubesheet regions was performed prior to operation at BVPS-2. This has effectively limited the initiation of PWSCC. Only three tubes have been affected by PWSCC, all at the hot leg expansion transition, to date at BVPS-2. The first occurrence of hot leg PWSCC was reported at the 2R09 (Spring 2009) outage (11.13 effective full power years (EFPY)), and is far later in the plant's operating history compared to similar plants which did not shotpeen prior to operation.

FENOC has also performed supplemental RPC testing of hot and cold leg tubesheet bulges and overexpansions during the 2R1 1 (Spring 2005), 2R1 2 (Fall 2006), 2R1 3

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 8 of 24 (Spring 2008), and 2R14 (Fall 2009) outages below the F* inspection distance; no degradation was identified. This supplemental testing further supports the conclusion that shotpeening prior to operation effectively limits the initiation of PWSCC.

Shotpeening does not affect outside diameter stress corrosion cracking (ODSCC) initiation, and BVPS-2 has reported ODSCC at the hot leg top-of-tubesheet and sludge pile region. A 20 percent sample of the B steam generator cold leg top-of-tubesheet was performed during the 2R1 1 outage; no degradation was identified. A 20 percent sample of the A steam generator cold leg top-of-tubesheet region was performed during the 2R14 (Fall 2009) outage, and again, no degradation was identified.

Additional Technical Information Reference 2 issued Amendment 160 that approved the use of the F* methodology for the SG hot-leg tubesheet region for BVPS-2. Amendment 160 was based on a FENOC application dated April 11, 2005 (Reference 1) as supplemented December 2, 2005 (Reference 10), January 27, 2006 (Reference 11), April 14, 2006 (Reference 12),

August 16, 2006 (Reference 13) and September 1,2006 (Reference 14).

References 11 and 14 submitted revisions to the Technical Specifications changes submitted by Reference 2 and are not discussed further in this submittal since all of the F* methodology associated Technical Specifications changes proposed by References 2, 11 and 14 have been incorporated into the Technical Specifications with the implementation of Amendments 158, 160 and 161. However, the remaining submittals provided additional technical information supporting approval of the F*

methodology. For completeness, the additional technical information, submitted as responses to the NRC requests for additional information (RAI), is provided in the following sections. The additional technical information is considered applicable to the cold-leg tubesheet region. The information previously submitted has been updated and clarified where appropriate. References to F* distance in the RAI responses that refer to F* length as defined in this letter are noted.

The response to RAI Item 1 (page 1 of 10) provided by Reference. 10 states that BVPS has and will continue to utilize properly qualified eddy current techniques available with regards to SG tube inspections. The probe design referenced in the original F* LAR submittal (Reference 1) reflected the recommendation contained within WCAP-16385-P, specifically the use of a rotating pancake coil for inspection of the hot-leg tubesheet F* distance. In the response submitted by Reference 10, FENOC agreed with the NRC's opinion that stating the use of a specific probe design would limit the ability to take advantage of advances in eddy current probe technology. Therefore, the current Technical Specifications do not identify a specific probe design for inspection of the hot-leg tubesheet F* distance. As a result, the proposed Technical Specifications changes also do not identify a specific probe design for inspection of the F* distance in the cold-leg tubesheet.

The response to RAI Item 2 (page 2 of 10) provided by Reference 10 states that, per WCAP-16385-P, the SG tube inspection extent is 100 percent of the inservice hot-leg tubes for the entire F* distance. For implementation of the cold-leg F* methodology, the initial sample population shall be at least a 20 percent random sample of the

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 9 of 24 inservice tubes (for the entire F* distance) in the SG being inspected. Expansion of the initial population shall be as defined in the degradation assessment.

The response to RAI Item 3 (pages 2 and 3 of 10) provided by Reference 10 states that all tubes will be tested to an adequate length to ensure pullout resistance. The selection of the 3.00 inch inspection distance was chosen to conservatively bound F*;

and this length includes an allowance for the [nominal] BRT elevation. The minimum inspection length below the BRT is specified in WCAP-1 6385-P as 1.97 inches.

FENOC has specified the inspection distance to be a minimum of 3.00 inches below the top-of-tubesheet for all tubes except any identified with BRTs greater than or equal to 0.75 inch. Tubes with BRTs greater than or equal to 0.75 inch will be inspected to a distance 2.22 inches below the BRT which satisfies the F* requirement. Thus all tubes will be adequately inspected. A degradation assessment defines those tubes that must be inspected to distances greater than 3.00 inches below the top-of-tubesheet.

This requirement is carried forward for all future degradation assessments. As part of the implementation of the amendment being requested by this submittal, the BVPS-2 SG Examination Guidelines are revised to include a table that lists the individual tube locations for the tubes with BRTs greater than or equal to 0.75 inch below the cold leg top-of-tubesheet and the minimum required inspection distance into the tubesheet region.

The response to RAI Item 4 (pages 3 and 4 of 10) provided by Reference 10 states that the original qualification specimens included a thermal soak after expanding the tube into the tubesheet that simulated the temperature associated with heat treatment of the tubesheet to stub barrel weld. This temperature far exceeds any operating or accident condition temperature and addresses the thermal soak issue. The effect of thermal cycling is not expected to adversely affect the anchorage capabilities of the tube in the cold-leg tubesheet region. Typical operating temperatures are not sufficient to cause a relieving of residual stresses inherent to the tube expansion process, nor are they sufficient to cause a relieving of residual preload associated with the expansion process itself.

The response to RAI Item 5 (page 4 of 10) provided by Reference 10 states that the F* distance [referred to as F* length in this letter] of 1.97 inches remains valid for the 4 percent, 8 percent and 22 percent plugging limits. The comparison between 4 percent and 8 percent plugging was included to show that the F* value is virtually unaffected for this change. Reference 8 includes a calculation of F* at a steam pressure of 700 pounds per square inch atmospheric (psia), which bounds the calculated steam pressure for 22 percent plugging conditions of 733 psia at the SG outlet and shows that the faulted case F* distance [referred to as F* length in this letter] remains bounding for the assumed 700 psia steam pressure case. The 700 psia steam pressure case was included to address the postulated condition of greater than anticipated plugging at an outage that results in the post outage plugging exceeding 8 percent. Tube plugging will be managed with the intention of keeping the planned average tube plugging to less than 8 percent, including plug removal and installation of tube sleeves.

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 10 of 24 The response to RAI Item 6 (pages 4 through 7 of 10) provided by Reference 10 included the following discussion of the methodology used in WCAP-1 1306 for determining the amount of accident induced leakage as a result of implementing the F*

criterion. WCAP-1 1306 does not describe a methodology for calculating leakage for cracks left in service. [FENOC implementation of the F* criterion requires identified degradation to be repaired by plugging or sleeving.] WCAP-1 1306 states that leakage from indications below F* is not anticipated and also states that any postulated leakage would be bounded by the leakage associated with free-span axial cracks of equal length. The applied F* distance [referred to as F* length in this letter] of 1.97 inches plus non-destructive examination (NDE) uncertainty is judged to be sufficiently robust that no leakage is expected during a postulated steam line break (SLB) event.

For sound roll expansion lengths of approximately 0.50 inch, measurable leakage is not anticipated at SLB conditions. As the applied F* distance [referred to as F* length in this letter] plus NDE uncertainty is greater than 1.97 inches, it is expected that no leakage will originate from postulated degradation below the F* [distance]. Test data contained within WCAP-16385-P indicate that the average tube outside diameter (OD) post roll with the collar removed is approximately 1.5 mils larger than the tubesheet hole in which the tube was installed. The RAI response also indicates that the combined positive effects of residual process expansion, thermal expansion, and pressure expansion are greater than the negative effect of tubesheet bow due to SLB conditions at 2.0 inches below the top-of-tubesheet. Thus, the tube and tubesheet will remain in contact for all plant conditions. The contact pressure associated with restraining the tube OD growth at 2 inches below the top-of-tubesheet is expected to far exceed the driving pressure that may exist within the crevice at the crack face, and thus no primary to secondary leakage is anticipated.

The tubesheet combined hole dilation value is calculated for the minimum tube location radius used for the tubesheet of 2.06 inches. At the largest radius location used in the analysis, 60.8 inches (i.e., near the tubesheet periphery), the bowed shape of the tubesheet results in a contraction of the tubesheet hole [at the top of tube sheet]. For the 33 inch radius location the tubesheet hole dilation effects due to bow alone are neutral. That is, for a radius of less than 33 inches the bow effects cause the hole to enlarge while for a radius of greater than 33 inches the bow effects cause the hole to contract. Note that the tube OD expansion due to only pressure and temperature effects is constant for all elevations within the tubesheet and for all tube locations. The above discussion presents a basis for establishing a no leak condition for F* tubes where the flaw elevation is below the F* distance. This basis, however, does not address the impact of tubesheet hole roughness which, depending upon the severity of surface roughness, could represent a condition where leakage at SLB conditions could be postulated even for cases where contact pressures exceed the leakage driving pressure. Recent evaluations performed for similar programs have concluded that leakage at SLB conditions would not exceed twice the normal operating conditions leakage. Additional resistance to leakage would be afforded due to interaction of the tube and tubesheet in a bowed condition. As the tubesheet bows, the horizontal plane distance at a constant elevation is decreased, even though the hole diameter along the bowed plane increases. As the tube will conform to the tubesheet and experience a radial growth due to thermal and pressure effects, the

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 11 of 24 contact pressures along the horizontal, or unbowed plane, should increase, effectively wedging the tube into the tubesheet hole.

Additionally, leakage can only be associated with indications that have progressed to a 100 percent TW condition for substantial length, either circumferentially or axially.

Revision 3 of the EPRI, "In Situ Pressure Test Guideline," [latest revision] defines a flaw amplitude threshold of 3.07 volts by Plus Point for indications located at the expansion transition. Thus any Plus Point flaw amplitude less than this amplitude would not be associated with leakage at SLB conditions. This flaw amplitude is unlikely to be experienced at BVPS-2 due to the application of shot peening prior to operation. If a 100 percent TW flaw of significant length were to develop, a small amount of primary to secondary leakage could be realized due to roughness of the tubesheet hole surface. For such cases the expected leakage is judged to be so small that no impact to offsite doses would be realized. During development of the L*

alternate repair criteria (WCAP-1469,7, "L*Tube Plugging Criteria for Tubes with Degradation in the Tubesheet Roll Expansion Region of the Farley Unit 2 SGs")

elevated temperature leakage testing was performed using sixteen tubes with twelve 0.0625 inch diameter holes drilled through the tube wall of each. These holes were located at a constant elevation and equally spaced around the tube. The tube was then roll expanded in a tubesheet simulant collar above the elevation of the holes, thus a gap of several mils between the tube and collar at the elevation of the holes was provided. In essence this configuration models a circumferential separation of the tube as the entire tube circumference at the bottom of the roll expansion was exposed to the flow from the holes. Roll lengths of 0.25 to 2.0 inches above the hole elevation were tested. Examination of the data shows that 3 of the 16 test specimens leaked at a pressure differential of 2250 psi, while 14 of the 16 test specimens leaked at a pressure differential of 2650 psi. Leak rates were decreased with increasing roll expanded length. Since the contact pressure at the tube OD surface exceeds the driving pressure the leakage [exhibited by test specimens] can be associated with roughness of the tubesheet hole. A total of 2 specimens, each with roll expanded lengths of 1 and 2 inches, were leak tested at a pressure differential of 2650 psi. Of these 4 specimens, 3 leaked with an average leak rate of 3.1 x 10-5 gallons per minute (gpm) and a maximum leak rate of 1.1 x 10-4 gpm. Although no leakage is anticipated from true PWSCC indications below the F* distance, the maximum observed leak rate of 1.1 x 10-4 gpm can conservatively be applied to any observed PWSCC degradation below F* that has a Plus Point amplitude greater than 3 volts in the 300 kHz analysis channel. This leakage contribution will be combined with all other postulated leakage sources evaluated in the operational assessment. Taking into consideration the in-situ pressure test results which focus on the expansion transition location, and the inherent conservatism associated with application of a leakage allowance for flaws below F*,

this option for leakage consideration is judged conservative.

The response to RAI Item 7 (pages 7 and 8 of 10) provided by Reference 10 states that the application of the F* methodology is a function of the tube elevation considered and has been applied to plants with both full and partial depth roll expansions. For similar plants that differ only in the depth of the tubesheet expansion, the plants with partial depth expansions have F* values less than plants with full depth

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 12 of 24 roll expansions. This is due to the tubesheet bow effects below the mid-plane of the tubesheet that result in contraction of the tubesheet hole which increases the contact pressures between the tube and tubesheet and thus reduces the F* distance [referred to as F* length in this letter]. The F* methodology with re-rolling has also been applied to plants with partial depth roll expansions where the F* distance [referred to as F*

length in this letter] is applied to the re-rolled sections of tube above the original roll.

Thus, it is acceptable to apply an F* value developed for the top-of-tubesheet to the tube length immediately below a sleeved tube as the lower end of the sleeve exists at approximately the mid-plane elevation of the tubesheet. At this elevation, the tubesheet bow effects are essentially neutral. Thus calculation of an F* value that uses top-of-tubesheet bow effects is conservative. In practice, if sleeves are installed, the parent tube will be inspected for a distance of 3.00 inches below the end of the sleeve, and the tube to tubesheet weld will not be inspected.

The response to RAI Item 8 (pages 8 and 9 of 10) provided by Reference 10 included the following discussion of how the BVPS-2 operating parameters will always be bounded by the conditions for which the F* distance [referred to as F* length in this letter] was determined in WCAP-16385-P and what controls are in place to ensure BVPS-2 will not operate outside the bounds of this analysis. FENOC has chosen to administratively control steam generator tube plugging to a maximum of 8 percent by tube sleeving. Both laser welded and tungsten inert gas (TIG) welded sleeving repairs are licensed at BVPS-2. However, these tube repair methods are no longer supported by Westinghouse. Inspection transients or observation of a new degradation mechanism at future outages could potentially result in a.condition when the steam generator tube plugging prior to an outage is well below 8 percent but greater than 8 percent after the outage. In this case the time periods involved for mobilization of sleeving equipment, preparation of procedures, training of personnel, etc, could result in a significant extension to the outage length. Therefore, the F* distance [referred to as F* length in this letter] was evaluated at a bounding primary to secondary pressure differential of 1550 psi (700 psia steam pressure) to address temporary conditions where steam generator tube plugging could exceed 8 percent. The normal operation F* distance [referred to as F* length in this letter] for this condition was calculated to be 1.81 inches, which remains bounded by the faulted condition F* distance [referred to as F* length in this letter] of 1.97 inches. Therefore, temporary conditions where steam generator tube plugging exceeds 8 percent do not invalidate the 1.97 inch F*

value, provided the primary to secondary pressure differential does not exceed 1550 psi. For an average reactor coolant system temperature of 576.2°F with 22 percent steam generator tube plugging, the expected steam pressure at the SG outlet nozzle is 733 psia. Calculation of the F* value with 4 percent steam generator tube plugging results in a value of 1.77 inches, which is bounded by the faulted condition value of 1.97 inches.

The response to RAI Item 9 (page 9 of 10) provided by Reference 10 included the following discussion of expected condition of the tube-to-tubesheet joint. FENOC routinely performs sludge lancing and visual inspections of the secondary face of the tubesheet. No conditions of corrosion have been observed or reported (at the tube-to-tubesheet interface) that would adversely affect the implementation of F*. Sludge

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 13 of 24 mapping is performed each outage to track the height and range of sludge build-up.

Average sludge height for those tubes with reportable sludge heights from bobbin analysis varies from 0.50 inch to approximately 3.50 inches. Approximately 250 tubes per SG have reportable sludge heights. The majority of these tubes are located in the center portion of the tubesheet grid, below the flow distribution baffle cutout region. An advanced scale conditioning agent (ASCA) process was applied during the BVPS-2 outage (2R13) in an effort to remove the semi-soft sludge deposits from the secondary face of the tubesheet.

The response to RAI Item 10 (page 10 of 10) provided by Reference 10 included the following discussion of structurally significant or leakage significant flaws within the F*

distance and the applicable reporting requirements. Qualified eddy current techniques are applied in all areas of the tube bundle. Industry experience has demonstrated that repeated applications of qualified inspection technology (for this case, in the region of the tubesheet) has minimized the likelihood of finding structurally significant or leakage significant indications within the F* distance. Since indications below the F* distance will not contribute to leakage during a postulated SLB event and indications observed within the inspection depth (into the tubesheet) will be [repaired following Amendment 170 or] plugged upon detection, the projected end-of-cycle accident-induced leakage is considered to be zero. This zero leakage value will be combined with the postulated end-of-cycle accident-induced leakage from all other sources. The current version of Specification 5.6.6.2.4 lists the reporting requirements applicable to F* inspection of the hot-leg tubesheet region. One of the changes proposed by this submittal modifies Specification 5.6.6.2.4 by extending the reporting requirements to F* inspection of the cold-leg tubesheet region.

The response to RAI Item 1 (page 2) provided by Reference 12 included the following discussion of how leakage from tubes degraded within the tubesheet will be addressed. Proposed Specification 5.5.5.2.c.5 describes plugging or repair limits for tubes to which the F* methodology would be applied. Tubes required by these criteria to be plugged or repaired would have no leakage assessed. For a tube that is acceptable for continued operation per the proposed repair limits, with indication amplitude greater than 3 volts by Plus Point (300 kHz), a leakage allowance of 1.1 x 10-4 gpm will be applied to that tube in the condition monitoring report. If the postulated indication amplitude at the end of the next operating cycle is projected to exceed 3 volts, a leakage allowance of 1.1 x 104 gpm will be applied to the operational assessment. If the Plus Point amplitude of the flaw is less than 3 volts, no leakage allowance will be applied.

The response to RAI Item 2 (pages 2 and 3) provided by Reference 12 included the following discussion of the basis for using a linear relationship between contact pressure and leakage flow. Although WCAP-14697 applied a simple linear relationship, more recent finite element modeling shows that reduction in contact pressure due to bowing in a Model 51 SG (7/8 inch diameter tube) is less than or equal to a Model D SG (3/4 inch diameter tube). Therefore, the 20 percent greater leakage that a linear relationship would predict for 7/8 inch diameter tubes is unnecessary and conservative. Tubesheet bow analyses associated with

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 14 of 24 WCAP-14697 used a simple conservative perforated plate model intended to overestimate the amount of tubesheet bow and the attendant reduction in contact pressure associated with SLB versus normal operating conditions. Contact pressures for Model D and Model 51 rolled joints prior to adjustment for tubesheet bow are essentially equal. Finite element modeling of tubesheet deflections have been performed since the initial F* analyses were performed. Results of the finite element analyses show that the Model 51 tubesheet is at least as stiff as the Model D tubesheet. Thus, the reduction in contact pressure due to tubesheet bow for a Model 51 SG is less than for the Model D SG. Therefore, the 1.2 factor applied in the simpler WCAP-14697 model is conservative. The suggested leakage allowance of 1.1 x 10-4 gpm for identified indications is based on conservative roll joint leakage rate test data for 3/4 inch diameter tubes. A conservative 3/4 inch diameter leak rate value based on testing was scaled up proportionately to reflect greater available leakage flow cross-sectional area of a 7/8 inch diameter tube. In addition, the factor of 1.2 was applied to arrive at the 7/8 inch diameter leakage allowance. Therefore, 1.1 x 10-4 gpm is a conservative value. The suggested leakage allowance for BVPS-2 is conservative when compared to W* leakage test data when equivalent contact pressures are considered.

The response to RAI Item 3 (page 3) provided by Reference 12 included the following discussion of bounding hole dilation. Contact pressures developed from finite element modeling of a Model 51 SG tubesheet at several elevations within the tubesheet including the mid-plane region of the tubesheet, which is the approximate elevation of tube-sleeve hardroll joints, indicate that hole dilations near the top-of-tubesheet bound dilations in the mid-plane region.

The response to RAI Item I (pages 1 through 5 of 7) provided by Reference 13 included the following discussion of the methodology for assessing accident induced leakage for the region of the tube that will not be required to be inspected. The applied roll torques used for the leakage specimens of WCAP-14697 were adjusted to account for reduction in contact pressure due to tubesheet bow, thus the effects of tubesheet bow are reflected in the leak test data. The final torque values were selected to provide equivalent contact pressures during normal operation and postulated SLB conditions. Appendix B of WCAP-14697 makes reference to the use of adjusted torque values.

The following establishes that leakage potential from 100 percent through-wall indications located greater than 3 inches below the top-of-tubesheet is negligible or nil.

Since contact pressures far exceed the maximum driving pressure for potential leakage during an SLB, leakage from flaws that go undetected below the proposed inspection extent would be negligible. Leakage potential of expanded tubes is influenced by tube OD growth due to thermal expansion and internal pressurization, residual effects of the expansion process, and tubesheet bow effects. For the top-of-tubesheet elevation the combined effect of these contributors results in positive contact force between the tube and tubesheet during all plant conditions. At 3 inches below the top-of-tubesheet, neglecting residual effects of the roll expansion, the tubesheet bow contact pressure reduction is slightly overcome by the thermal and pressure growth for all tube locations (see Figure 1).

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 15 of 24 Contact Pressure as a Function of Tubesheet Radius at SLB Conditions (no residual expansion preload)

-4 inches below TTS -B-2 inches below TTS . STTS 3 inches below TTS estimated 7 2500 2000 1500 1000-

• 500*

0 0 0-0 40 50 60 0

-500

-1000

-1500 Tubesheet Radius (inch)

Figure 1 Thus, when the residual expansion process effects are considered, all tubes will retain contact pressure equal to or greater than the contact pressure associated with the expansion process, or approximately 3800 to 4000 psi. This comparison considers the limiting radial location on the tubesheet. At this contact pressure primary to secondary leakage at SLB conditions is not anticipated; thus, there is no basis to assume postulated indications below the F* inspection distance would contribute to leakage.

From the figure it can be seen at the 30 inch radius location and 3 inches below the top-of-tubesheet, that when the residual expansion process contact pressure is included, the total tube to tubesheet contact pressure is approximately 4000 to 4500 psi which far exceeds the SLB condition maximum driving pressure of 2560 psi.

About 75 percent of the tubes reside outside of the 30 inch radial location. Additional margin against postulated leakage is inherently included via the eddy current data acquisition process, which ensures that an excess of data is collected to prevent retesting due to incomplete acquisition.

While all tubes in tubesheet expansion processes are designed to close the tube to tubesheet gap, the post expansion condition with regard to residual contact forces and resistance to postulated leakage vary greatly depending upon the applied process.

Observed conditions from leakage testing of explosive or hydraulically expanded tube in tubesheet conditions cannot be applied generally to mechanical roll expansion. The leakage potential is dependent upon the tube to tubesheet interaction forces and

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 16 of 24 tubesheet hole surface conditions at specific elevations within the tubesheet. At 3 inches below the top-of-tubesheet the minimum integrated (sum of all forces and effects) contact pressure between the tube and tubesheet is about 4000 psi. In comparison, at a contact pressure of 4000 psi in a WEXTEX tube, the location within the tubesheet is approximately 15 inches below the top-of-tubesheet. The constrained crack leak rate data of the W* program shows that for contact pressures >2500 psi leak rates are reduced compared to lesser contact pressure values and approach zero leakage with only slight increases in contact pressure. Note that the constrained crack leak data examined the effect of contact pressure on leakage potential for essentially zero expanded tube lengths. The additional resistance to leakage afforded by expanded tube length between the indication and the top-of-tubesheet was not present in these tests.

Additionally, the expansion process particulars must be considered. Explosive and hydraulic expansion processes affect the expanded length simultaneously and result in little if no additional (after contact with the tubesheet) wall thinning due to applied process forces. Springback of the tube OD surface could result in a lesser resistance to leakage. In roll expansion the large residual radial forces due to thinning of the tube wall after contact with the tubesheet greatly increases the resistance to leakage and likely will result in the tube OD surface conforming to tubesheet hole imperfections.

Thus, when thermal and pressure expansion are introduced, the resistance to leakage is further increased as the surface forces at the tube to tubesheet interface will act in both axial and radial directions. The applied torque of roll expansion produces additional (after contact with the tubesheet) tube wall thinning of 3 to 4 percent by compression resulting in general yielding of the tube material during expansion. The forces required are large and are transferred across the tube wall. This transfer of forces will cause the tube OD surface to conform to the localized tubesheet hole surface imperfections to a much larger degree than with explosive or hydraulic expansion processes. Therefore, it may be concluded that postulated 100 percent through-wall flaws below the F* inspection distance will not contribute to leakage during a postulated SLB event.

Any attempt to estimate the number of postulated indications below the inspection distance is conjecture. Comparison of observed flaws from BVPS-2 and other units is used to establish that this number is minimal. The BVPS-2 SG tubes were shotpeened through the entire tubesheet thickness prior to operation. This has effectively reduced the stress corrosion cracking (SCC) potential. To date (>18 effective full power years (EFPY)) only three tubes have been reported with primary water stress corrosion cracking (PWSCC) in the tubesheet region. All have been located in the top-of-tubesheet expansion transition. EPRI Steam Generator Degradation Database (SODD) data from plants with full depth roll expanded tubes that were not shotpeened prior to operation shows many PWSCC indications per plant for similar accumulated EFPY. Prior to replacement approximately 1359 PWSCC indications were reported at Farley 2. At McGuire 1, approximately 2671 PWSCC indications were reported. In both cases the degradation was predominantly axially oriented. Previous data submitted to the NRC as part of W* license amendments has shown the PWSCC initiation potential is decreased with increasing depth below the

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 17 of 24 top-of-tubesheet. As BVPS-2 has not reported PWSCC below the expansion transition and the potential for initiation is reduced with increasing depth below the top-of-tubesheet, there is essentially no potential for flaw development below the F*

inspection distance.

As a precautionary measure, bulge and overexpansion signals below the F* distance have been inspected with a Plus Point coil for BVPS-2 outages 2R1 1 (hot leg only),

2R12 (hot leg and cold leg), 2R13 (hot leg only) and 2R14 (hot leg only). No degradation has been identified. Thus, there is no basis to assume that a large number of tubes will contain degradation below the F* inspection distance. Further evidence as to the effectiveness of shotpeening prior to operation is found in inspection data from a plant with Model D4 SGs, which have been replaced. Similar to BVPS-2, these SGs used full depth roll expansion and were shotpeened prior to operation. The reporting plant with Model D4 SGs had accumulated 13.12 EFPY at the last eddy current inspection prior to replacement. The reporting plant also operated at 620'F. The difference in hot-leg operating temperature between BVPS-2 and the reporting plant suggests a PWSCC initiation potential 1.6 times that of BVPS-2. About 10 tubes have been reported with PWSCC in the F* distance at the reporting plant. The reporting plant also contained approximately 1900 tubes that were expanded using the WEXTEX explosive expansion process. At the last outage prior to SG replacement for the reporting plant, all WEXTEX tubes were inspected with the Plus Point coil full depth through the tubesheet. No PWSCC degradation was reported in these tubes. Other plants with Model 51 SGs that have applied or requested application of the W* alternate repair criterion have reported PWSCC in up to 3 percent of the total tube population. Without shotpeening, this would equate to approximately 57 postulated PWSCC indications in the Model D4 plant. As no PWSCC has been reported in WEXTEX tubes with hot-leg operating temperatures of 9°F to 20'F greater than Model 51 SGs, the D4 plant experience supports the conclusion that shotpeening prior to operation has and will continue to effectively limit PWSCC potential at BVPS-2. This evidence that through-wall degradation is unlikely to develop, in addition to the discussion of contact pressures which concludes no leakage from postulated 100 percent through-wall indications below F*, provides further assurance that leakage need not be assumed.

With regard to long term application, shotpeening is a stress modification to the inside diameter (ID) surface of the tube. The impact of the shot on the ID surface produces a compressive stress, and compressive stresses are generally not associated with SCC initiation. Normal plant operating temperatures within the SG are not sufficient to result in a relaxation of this stress; therefore, there is no basis to postulate that continued operation would result in a relaxation of the compressive stresses on the tube ID.

Additionally, approximately 25 percent of the tubesheet region Plus Point tests for steam generator A from the 2R1 1 outage inspection were re-examined to determine the lowest test extent. For these tubes the average inspection depth below the top-of-tubesheet was 3.80 inches with a maximum depth of inspection of 6.41 inches.

Only one PWSCC indication was reported during the 2R1 1 outage for all SGs. This

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 18 of 24 indication was reported at the top-of-tubesheet expansion transition. As no degradation was reported at depths other than the top-of-tubesheet expansion transition, and actual tests exceeded 3 inches below the top-of-tubesheet, the BVPS-2 data is consistent with other plant experiences that indicate a reduced PWSCC potential for deeper depths below the top-of-tubesheet. In addition, prior F*

applications at numerous other units have assumed no leakage from postulated indications below the F* inspection distance. For purposes of leakage assessment the finite element analysis results were applied.

The response to RAI Item 2 (page 5 of 7) provided by Reference 13 included the following summary of leak test data that is based on a total of five specimens of 1 and 2 inch roll expansion lengths tested at a pressure differential of 2650 psi. As shown in Table 2-2 of WCAP-14697, samples L3, L7, and L18 used a roll expansion length of 1 inch and samples L4 and L8 used a roll expansion length of 2 inches. The leak rates, in terms of drops per minute, are also described in Table 2-2 of WCAP-14697.

The leakage allowance proposed for degradation permitted to remain in service via application of F* was developed using a factor of 72,000 drops per gallon.

The response to RAI Item 3 (page 6 of 7) provided by Reference 13 included the following discussion on plugging and repair limits. Amendment 158 (Reference 3) approved Technical Specification requirements that require plugging of tubes with a flaw in a tube to sleeve joint that occurs in the sleeve or in the original tube wall.

The response to RAI Item 4 (page 6 of 7) provided by Reference 13 included the following discussion on assessing leakage within the F* distance. All observed degradation within the F* distance will be evaluated for leakage potential, and if it is judged that the indication depth is 100 percent through-wall, any postulated leakage at SLB conditions will be considered in the condition monitoring report. All degradation observed within the F*,distance will be [repaired following Amendment 170 or] plugged upon detection. If observed flaw occurrence rate data suggest a potential for new occurrences of 100 percent through-wall degradation within the F* distance by the end of the next operating cycle, any postulated leakage will be addressed in the operational assessment.

The response to RAI Item 5 (pages 6 and 7 of 7) provided by Reference 13 included the following discussion on tubesheet hole dilation near the neutral plane of the tubesheet. The design of TIG welded sleeves described in topical report CEN-629-P, "Repair of Westinghouse Series 44 and 51 Steam Generator Tubes Using Leak Tight Sleeves" (Reference 15), locates the lower (hardroll) joint of non-full length sleeves in the mid-plane region of the tubesheet. The sleeve installation tooling includes a hard stop which controls sleeve elevation within the tubesheet. This stop places the tube to sleeve hardroll joint at the approximate mid-plane elevation, where tubesheet bow effects are essentially neutral. The design of full length sleeves described in CEN-629-P locates the lower end of the sleeve at the bottom of the tubesheet. In tubes sleeved in the tubesheet region, F* can only be applied to the original tube wall below the sleeve. Therefore, F* cannot be applied to tubes with full length TIG welded sleeves because the original tube does not extend below the lower end of the sleeve.

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 19 of 24 Laser welded sleeves described in topical report WCAP-1 3483, "BVPS Units 1 & 2, Westinghouse Series 51 SG Sleeving Report - Laser Welded Sleeves," are flared at the lower end, ensuring that the end of the sleeve is always at the bottom of the tubesheet. For the same reason as full length TIG welded sleeves, F* cannot be applied to tubes with laser welded sleeves. While laser welded sleeving is permitted by the Technical Specification, none are installed at BVPS-2, and Westinghouse no longer supports this product.

4.0 REGULATORY EVALUATION

FirstEnergy Nuclear Operating Company (FENOC) requests amendment of Operating License NPF-73 for Beaver Valley Power Station Unit No. 2 (BVPS-2). The proposed amendment would revise the Technical Specifications by expanding the scope of the steam generator tubesheet inspections using the F* inspection methodology to the steam generator (SG) cold-leg tubesheet region.

4.1 Significant Hazards Consideration FENOC has evaluated whether or not a significant hazards consideration is involved with the proposed amendments by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

No. The proposed change modifies the BVPS-2 Technical Specifications to expand the scope of steam generator tubesheet inspections using the F*

inspection methodology to the steam generator cold-leg tubesheet region based on WCAP-16385-P, Revision 1. Of the various accidents previously evaluated in the BVPS-2 Updated Final Safety Analysis Report (UFSAR), the proposed change only affects the steam generator tube rupture (SGTR) event evaluation and the postulated steam line break (SLB) accident evaluation. Loss-of-coolant accident (LOCA) conditions cause a compressive axial load to act on the tube. Therefore, since the LOCA tends to force the tube into the tubesheet rather than pull it out, it is not a factor in this amendment request. Another faulted load consideration is a safe shutdown earthquake (SSE); however, the seismic analysis of Model 51M SGs has shown that axial loading of the tubes is negligible during an SSE.

For the SGTR event, the required structural margins of the steam generator tubes will be maintained by the presence of the tubesheet. Tube rupture is precluded for cracks in the tube expansion region due to the constraint provided by the tubesheet. Therefore, Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," margins against burst are maintained for both normal and postulated accident conditions.

The F* length supplies the necessary resistive force to preclude pullout loads under both normal operating and accident conditions. The contact pressure results from the tube expansion process used during manufacturing and from the differential

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 20 of 24 pressure between the primary and secondary side. The proposed changes do not affect other systems, structures, components or operational features. Therefore, the proposed change results in no significant increase in the probability of the occurrence of an SGTR or SLB accident.

The consequences of an SGTR event are affected by the primary-to-secondary leakage flow during the event. Primary-to-secondary leakage flow through a postulated broken tube is not affected by the proposed change since the tubesheet enhances the tube integrity in the region of the expansion by precluding tube deformation beyond its initial expanded outside diameter. The resistance to both tube rupture and collapse is strengthened by the tubesheet in that region. At normal operating pressures, leakage from primary water stress corrosion cracking (PWSCC) below the F* distance is limited by both the tube-to-tubesheet crevice and the limited crack opening permitted by the tubesheet constraint.

Consequently, negligible normal operating leakage is expected from cracks within the tubesheet region.

SLB leakage is limited by leakage flow restrictions resulting from the crack and tube-to-tubesheet contact pressures that provide a restricted leakage path above the indications and also limit the degree of crack face opening compared to free span indications. The total leakage (i. e., the combined leakage for all such tubes) meets the industry performance criterion, plus the combined leakage developed by any other alternate repair criteria, and will be maintained below the maximum allowable SLB leak rate limit, such that off-site doses are maintained less than 10 CFR 100 guideline values and the limits evaluated in the BVPS-2 UFSAR.

Therefore, based on the above evaluation, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

No. The proposed changes do not introduce any changes or mechanisms that create the possibility of a new or different kind of accident. Tube bundle integrity will continue to be maintained for all plant conditions upon implementation of the F*

methodology to the cold-leg tubesheet region.

The proposed changes do not introduce any new equipment or any change to existing equipment. No new effects on existing equipment are created nor are any new malfunctions introduced.

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

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 21 of 24

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

No. The proposed changes maintain the required structural margins of the steam generator tubes for both normal and accident conditions. NRC Regulatory Guide (RG) 1.121 is used as the basis in the development of the F* methodology for determining that steam generator tube integrity considerations are maintained within acceptable limits. Regulatory Guide 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14, 15, 31, and 32. Regulatory Guide 1.121 describes the limiting safe conditions of tube wall degradation beyond which tubes with unacceptable cracking, as established by inservice inspection, should be removed from service or repaired. This RG uses safety factors on loads for tube burst that are consistent with the requirements of Section III of the American Society of Mechanical Engineers (ASME) Code.

For primarily axially oriented cracking located within the tubesheet, tube burst is precluded due to the presence of the tubesheet. WCAP-1 6385-P, Revision 1, defines a length, F*, of degradation-free expanded tubing that provides the necessary resistance to tube pullout due to the pressure-induced forces (with applicable safety factors applied). Expansion of the application of the F* criteria to the cold-leg tubesheet region will preclude unacceptable primary-to-secondary leakage during all plant conditions. The methodology for determining leakage provides for large margins between calculated and actual leakage values in the F*

criteria.

Plugging of the steam generator tubes reduces the reactor coolant flow margin for core cooling. Expansion of the F* methodology to the cold-leg tubesheet region at BVPS-2 will result in maintaining the margin of flow that may have otherwise been reduced by tube plugging.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, FENOC concludes that the proposed amendments present no significant hazards consideration under the standards set forth in 10CFR50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

4.2 Applicable Regulatory Requirements/Criteria A review of 10 CFR 50, Appendix A, "General Design Criteria (GDC) for Nuclear Power Plants," was conducted to assess the potential impact associated with the proposed changes. The following table lists the criterion potentially impacted, and an assessment of the need for a modification to the UFSAR description of BVPS-2 design conformance to the criterion.

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 22 of 24 General Design Criteria Impact 14 Reactor coolant pressure boundary None 15 Reactor coolant system design None 16 Reactor containment design None 31 Fracture prevention of reactor coolant pressure boundary None 32 Inspection of reactor coolant pressure boundary None The reactor coolant pressure boundary, containment boundary and tube-bundle integrity will not be adversely affected by expansion of the implementation of the F*

tube inspection scope to the cold-leg tubesheet region. Steam Generator tube burst or collapse cannot occur within the confines of the tubesheet; therefore, the tube burst and collapse criteria of Regulatory Guide (RG) 1.121 are inherently met. Any degradation below the F* length is shown by analyses and test results to be acceptable, thereby precluding an event with consequences similar to a postulated tube rupture event. Steam generator tube surveillance requirements continue to ensure that degraded tubes will be repaired or removed from service upon detection.

Therefore, conformance with all applicable GDCs remain valid.

In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the 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.

4.3 Precedent The F* methodology has been approved by the NRC for Farley Unit 2 in License Amendment 64 and BVPS-2 in License Amendment 160. The Farley amendment was supported by WCAP-1 1306, Revision 2 (Reference 9) and the BVPS-2 amendment was supported by WCAP-16385-P, Revision 1 (Reference 8). The BVPS-2 amendment limited the F* methodology to the hot-leg tubesheet regions. The Farley approved Technical Specifications do not contain a similar limitation.

Submittals requesting approval to use the W* Alternate Repair Criteria at Diablo Canyon Unit 1 and 2 and Sequoyah Unit 2 have been made. The Diablo Canyon Unit 1 and 2 request was approved by Amendments 182 (Unit 1) and 184 (Unit 2) issued on October 28, 2005 (Reference 16). The Sequoyah Unit 2 request was approved by Amendment 318 issued on October 19, 2009 (Reference 17). Although the submittals for Diablo Canyon and Sequoyah requested a different SG tube inspection methodology than is being requested for BVPS-2, each requested use of the methodology to limit the inspection depth into the cold-leg tubesheet.

4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 23 of 24 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.

5.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1. FENOC Letter L-05-061, "License Amendment Request No. 183 Revised Steam Generator Inspection Scope," dated April 11, 2005 (Agency Documents Access and Management System (ADAMS) Accession No. ML051040080)

2. NRC Letter dated September 27, 2006, "Beaver Valley Power Station, Unit No. 2

- Issuance of Amendment RE: Revised Steam Generator Inspection and Repair Scope Using the F* Methodology (TAC No. MC6768)," Amendment 160 (ADAMS Accession No. ML062580419)

3. NRC Letter dated September 7, 2006, "Beaver Valley Power Station, Unit Nos. 1 and 2 (BVPS-1 and BVPS-2) - Issuance of Amendments RE: Steam Generator Tube Integrity (TAC Nos. MC8861 and MC8862)," Amendment 158 (ADAMS Accession No. ML062260011)

4. NRC Letter dated February 21, 2007, "Beaver Valley Power Station, Unit Nos. 1 and 2 - Issuance of Amendment RE: The Conversion to the Improved Technical Specifications with Beyond-Scope Issues (TAC Nos. MC6285, MC6286, MC6579 - MC6612, MC6614 - MC6626, and MC6783 - MC6792)," Amendment 161 (ADAMS Accession No. ML070160593)

5. FENOC Letter L-08-307, "License Amendment Request No.07-007, Alloy 800 Steam Generator Tube Sleeving," dated October 10, 2008 (ADAMS Accession No. ML082890823)

6. FENOC Letter L-09-172, "License Amendment Request No.07-007, Alloy 800 Steam Generator Tube Sleeving, Supplement (TAC No. MD9969)," dated July 14, 2009

7. Westinghouse Electric Company WCAP-1 6385-NP, Revision 1, "F* Tube Plugging Criterion for Tubes with Degradation in the Tubesheet Roll Expansion Region of the Beaver Valley Unit 2 Steam Generators," March 2005.

(Non-proprietary) (ADAMS Accession No. ML051040084)

Beaver Valley Power Station Unit No. 2 License Amendment Request No.09-005 Page 24 of 24

8. Westinghouse Electric Company WCAP-16385-P, Revision 1, "F* Tube Plugging Criterion for Tubes with Degradation in the Tubesheet Roll Expansion Region of the Beaver Valley Unit 2 Steam Generators," March 2005. (Proprietary)

9. Westinghouse Electric Company WCAP-1 1306, Revision 2, "Tubesheet Region Plugging Criterion for the Alabama Power Company, Farley Nuclear Station, Unit 2 Steam Generators," April 1987

10. FENOC Letter L-05-190, "Response to Request for Additional Information on License Amendment Request regarding Revised Steam Generator Inspection Scope (TAC No. 6768)," dated December 2, 2005 (ADAMS Accession No. ML053420343)

11. FENOC Letter L-06-013, "Supplement to License Amendment Request No. 183 Revised Steam Generator Inspection Scope (TAC No. 6768)," dated January 27, 2006 (ADAMS Accession No. ML060330258)

12. FENOC Letter L-06-041, "Response to Request for Additional Information on License Amendment Request 183 (TAC No. 6768)," dated April 14, 2006 (ADAMS Accession No. ML061100182)

13. FENOC Letter L-06-095, "Response to Request for Additional Information in Support of License Amendment Request No. 183," dated August 16, 2006 (ADAMS Accession No. ML062300027)

14. FENOC Letter L-06-132, "Supplement to License Amendment Request No. 183 -

Submittal of Final Proposed Technical Specification Changes," dated September 1, 2006 (ADAMS Accession No. ML062490200)

15. Combustion Engineering, Inc. Report CEN-629-P, "Repair of Westinghouse Series 44 and 51 Steam Generator Tubes Using Leak Tight Sleeves," dated January 1997

16. NRC Letter dated October 28, 2005, "Diablo Canyon Power Plant, Unit Nos. 1 and 2 - Issuance of Amendment RE: Approval of Permanent Use of the W*

Alternate Repair Criteria for Steam Generator Tubes (TAC NOS. MC6409 and MC6410)," Amendments 182 and 184 (ADAMS Accession No. ML052970178)

17. NRC Letter dated October 19, 2009, "Sequoyah Nuclear Plant, Unit 2 - Issuance of Amendment to Allow Use of the W* Alternate Repair Criteria for Steam Generator Tubes (TS-09-02)(TAC No. ME1343)," Amendment 318 (ADAMS Accession No. ML092810333)

Attachment 1 Beaver Valley Power Station, Unit No. 2 Proposed Technical Specification Changes License Amendment Request No.09-005 The following is a list of the affected pages.

5.5 - 6*

5.5 - 7*

5.5 - 8*

5.5 - 9*

5.5- 10 5.5-11 5.5- 12" 5.6-5*

5.6-6

• No Change. Page provided for context only.

Programs and Manuals No change. Page included for context only. 5.5 5.5 Programs and Manuals 5.5.5.1 Unit 1 Steam Generator (SG) Program (continued)

2. Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. During each period inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three intervals between refueling outages (whichever is less) without being inspected.

3. If crack indications are found in any SG tube, 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 interval between refueling outages (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE 5.5.5.2 Unit 2 Steam Generator 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 or repair of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected, plugged, or repaired to confirm that the performance criteria are being met.

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

1. Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes Beaver Valley Units 1 and 2 5.5 -6 Amendments 278 / 161

Programs and Manuals No change. Page included for context only. 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued) retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential and, except for flaws addressed through application of the alternate repair criteria discussed in Specification 5.5.5.2.c.4, 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.

When alternate repair criteria discussed in Specification 5.5.5.2.c.4 are applied to axially oriented outside diameter stress corrosion cracking indications at tube support plate locations, the probability that one or more of these indications in a SG will burst under postulated main steam line break conditions shall be less than lx1 0-2.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Except during a SG tube rupture, leakage from all sources excluding the leakage attributed to the degradation described in Specification 5.5.5.2.c.4 is also not to exceed 1 gpm per SG.

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational Leakage."

c.' Provisions for SG Tube Repair Criteria

1. Tubes found by inservice inspection to contain a flaw in a non-sleeved region with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired except if permitted to remain in service through application of the alternate repair criteria discussed in Specification 5.5.5.2.c.4 or 5.5.5.2.c.5.

Beaver Valley Units 1 and 2 5.5-7 Amendments 278 / 161

Programs and Manuals No change. Page included for context only. 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued)

2. Tubes found by inservice inspection to contain a flaw in a sleeve (excluding the sleeve to tube joint) with a depth equal to or exceeding the following percentages of the nominal sleeve wall thickness shall be plugged:

ABB Combustion Engineering TIG welded sleeves 27%

Westinghouse laser welded sleeves 25%

Westinghouse leak limiting Alloy 800 sleeves Any flaw

3. Tubes with a flaw in a sleeve to tube joint shall be plugged.

4. Tube support plate voltage-based repair criteria may be applied as an alternative to the 40% depth based criteria of Specification 5.5.5.2.c.1.

Tube Support Plate Plugging Limit is used for the disposition of an Alloy 600 steam generator tube for continued service that is experiencing predominantly axially oriented outside diameter stress corrosion cracking confined within the thickness of the tube support plates. At tube support plate intersections, the plugging (repair) limit is described below:

a) Steam generator tubes, with degradation attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with bobbin voltages less than or equal to 2.0 volts will be allowed to remain in service.

b) Steam generator tubes, with degradation attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than 2.0 volts will be repaired or plugged, except as noted in 5.5.5.2.c.4.c below.

c) Steam generator tubes, with indications of potential degradation attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than 2.0 volts but less than or equal to the upper voltage repair limit (calculated according to the methodology in Generic Letter 95-05 as supplemented) may remain in service if a rotating pancake coil or acceptable alternative inspection does not detect degradation.

d) Steam generator tubes, with indications of potential degradation attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than the upper voltage repair limit (calculated according to the methodology in Generic Letter 95-05 as supplemented) will be plugged or repaired.

Beaver Valley Units 1 and 2 5.5 -8 Amendments 278 / 170

Programs and Manuals No change. Page included for context only. 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Proqram (continued) e) If an unscheduled mid-cycle inspection is performed, the following mid-cycle repair limits apply instead of the limits specified in 5.5.5.2.c.4.a through 5.5.5.2.c.4.d.

The mid-cycle repair limits are determined from the following equations:

VS v - SL MURL 1.0+NDE+Gr (CLAt CL VLRL)( CL )

VMLRL VMURL -(VURL where:

VURL = upper voltage repair limit VLRL = lower voltage repair limit VMURL = mid-cycle upper voltage repair limit based on time into cycle VMLRL = mid-cycle lower voltage repair limit based on VMURL and time into cycle At = length of time since last scheduled inspection during which VURL and VLRL were implemented CL = cycle length (the time between two scheduled steam generator inspections)

VSL = structural limit voltage Gr = average growth rate per cycle length NDE = 95-percent cumulative probability allowance for nondestructive examination uncertainty (i.e., a value of 20-percent has been approved by NRC). The NDE is the value provided by the NRC in GL 95-05 as supplemented.

Implementation of these mid-cycle repair limits should follow the same approach as in Specifications 5.5.5.2.c.4.a through 5.5.5.2.c.4.d.

Beaver Valley Units 1 and 2 5.5 -9 Amendments 278 / 161

Programs and Manuals 5.5.

5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued)

5. The F* methodology, as described below, may be applied to the expanded portion of the tube in the hot-leg or cold-leg tubesheet region as an alternative to the 40% depth based criteria of Specification 5.5.5.2.c.1:

a) Tubes with no portion of a lower sleeve joint in the hot-leg or cold-leg tubesheet region shall be repaired or plugged upon detection of any flaw identified within 3.0 inches below the top of the tubesheet or within 2.22 inches below the bottom of roll transition, whichever elevation is lower. Flaws located below this elevation may remain in service regardless of size.

b) Tubes which have any portion of a sleeve joint in the hot-leg or cold-leq tubesheet region shall be plugged upon detection of any flaw identified within 3.0 inches below the lower end of the lower sleeve joint. Flaws located greater than 3.0 inches below the lower end of the lower sleeve joint may remain in service regardless of size.

d. Provisions for SG Tube Inspections

-NOTE-The requirement for methods of inspection 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 does not apply to the portion of the original tube wall adjacent to the nickel band (the lower half) of the lower joint for the repair process that is discussed in Specification 5.5.5.2.f.3. However, the method of inspection in this area shall be a rotating plus point (or equivalent) coil. The SG tube repair criterion of Specification 5.5.5.2.c.3 is applicable to flaws in this area.

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. The tube-to-tubesheet weld is not part of the tube. In tubes repaired by sleeving, the portion of the original tube wall between the sleeve's joints is not an area requiring re-inspection. In addition to meeting the requirements of d.1, d.2, d.3, d.4, d.5, d.6 and d.76 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

Beaver Valley Units 1 and 2 5.5- 10 Amendments 278 / TBID

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued)

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 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one interval between refueling outages (whichever is less) without being inspected.

3. If crack indications are found in any SG tube, 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 interval between refueling outages (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.

4. Indications left in service as a result of application of the tube support plate voltage-based repair criteria (Specification 5.5.5.2.c.4) shall be inspected by bobbin coil probe during all future refueling outages.

Implementation of the steam generator tube-to-tube support plate repair criteria requires a 100-percent bobbin coil inspection for hot-leg and cold-leg tube support plate intersections down to the lowest cold-leg tube support plate with known outside diameter stress corrosion cracking (ODSCC) indications. The determination of the lowest cold-leg tube support plate intersections having ODSCC indications shall be based on the performance of at least a 20-percent random sampling of tubes inspected over their full length.

5. When the F* methodology has been implemented, inspect 100% of the inservice tubes in the hot-leg tubesheet region with the objective of detecting flaws that may satisfy the applicable tube repair criteria of Specification 5.5.5.2.c.5 every 24 effective full power months or one interval between refueling outages (whichever is less).

6. The F* methodology shall be implemented whenever an inspection of the cold-leg tubesheet region is required. The initial sample population shall be at least a 20% random sample of the in-service tubes (for the entire F* distance) in the SG being inspected. Expansion of the initial population shall be as defined in the degradation assessment.

76. For Alloy 800 sleeves: The parent tube, in the area where the sleeve-to-tube hard roll joint (lower joint) and the sleeve-to-tube hydraulic expansion joint (upper joint) will be established, shall be inspected prior to installation of the sleeve. Sleeve installation may proceed only if the inspection finds these regions free from service induced indications.

e. Provisions for monitoring operational primary to secondary LEAKAGE Beaver Valley Units 1 and 2 5.5-11 Amendments 278 / TBID

Programs and Manuals No change. Page included for context only.

5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued)

f. Provisions for SG Tube Repair Methods Steam generator tube repair methods shall provide the means to reestablish the RCS pressure boundary integrity of SG tubes without removing the tube from service. For the purposes of these Specifications, tube plugging is not a repair. All acceptable tube repair methods are listed below.

1. ABB Combustion Engineering TIG welded sleeves, CEN-629-P, Revision 02 and CEN-629-P Addendum 1.

2. Westinghouse laser welded sleeves, WCAP-13483, Revision 2.

3. Westinghouse leak-limiting Alloy 800 sleeves, WCAP-15919-P, Revision 2. All Alloy 800 sleeves shall be removed from service by the spring of 2017 Unit 2 refueling outage (2R19).

5.5.6 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables,

b. Identification of the procedures used to measure the values of the critical variables,

c. Identification of process sampling points,

d. Procedures for the recording and management of data,

e. Procedures defining corrective actions for all off control point chemistry conditions, and

f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

Beaver Valley Units 1 and 2 5.5- 12 Amendments 278 /170

Reporting Requirements No change. Page included for context only. 5.6 5.6 Reporting Requirements 5.6.6 Steam Generator Tube Inspection Report (continued) 5.6.6.2 Unit 2 SG Tube Inspection Report

1. A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.5.2, Unit 2 Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

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

h. The effective plugging percentage for all plugging and tube repairs in each SG, and

i. Repair method utilized and the number of tubes repaired by each repair method.

2. A report shall be submitted within 90 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.5.2, Unit 2 Steam Generator Program, when voltage-based alternate -repair criteria have been applied. The report shall include information described in Section 6.b of Attachment 1 to Generic Letter 95-05, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking."

3. For implementation of the voltage-based repair criteria to tube support plate intersections, notify the Commission prior to returning the steam generators to service (MODE 4) should any of the following conditions arise:

a. If circumferential crack-like indications are detected at the tube support plate intersections.

Beaver Valley Units 1 and 2 5.6 -5. Amendments 278 / 161

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.6.2 Unit 2 Steam Generator Tube Inspection Report (continued) b., If indications are identified that extend beyond the confines of the tube support plate.

c. If indications are identified at the tube support plate elevations that are attributable to primary water stress corrosion cracking.

4. A report shall be submitted within 90 days after the initial entry into MODE 4 following an outage in which the F* methodology was applied.

As applicable, tThe report shall include the following hot-leg and cold-leg tubesheet region inspection results associated with the application of F*:

a. Total number of indications, location of each indication, orientation of each indication, severity of each indication, and whether the indications initiated from the inside or outside surface.

b. The cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet.

c. The projected end-of-cycle accident-induced leakage from tubesheet indications.

Beaver Valley Units 1 and 2 5.6 - 6 Amendments 278 / TBD

Attachment 2 Beaver Valley Power Station, Unit No. 2 Retyped Technical Specification Pages License Amendment Request No.09-005 The following is a list of the affected pages.

5.5- 10 5.5-11 5.5- 12 5.6-6

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued)

5. The F* methodology, as described below, may be applied to the expanded portion of the tube in the hot-leg or cold-leg tubesheet region as an alternative to the 40% depth based criteria of Specification 5.5.5.2.c.1:

a) Tubes with no portion of a lower sleeve joint in the hot-leg or cold-leg tubesheet region shall be repaired or plugged upon detection of any flaw identified within 3.0 inches below the top of the tubesheet or within 2.22 inches below the bottom of roll transition, whichever elevation is lower. Flaws located below this elevation may remain in service regardless of size.

b) Tubes which have any portion of a sleeve joint in the hot-leg or cold-leg tubesheet region shall be plugged upon detection of any flaw identified within 3.0 inches below the lower end of the lower sleeve joint. Flaws located greater than 3.0 inches below the lower end of the lower sleeve joint may remain in service regardless of size.

d. Provisions for SG Tube Inspections

-NOTE-The requirement for methods of inspection 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 does not apply to the portion of the original tube wall adjacent to the nickel band (the lower half) of the lower joint for the repair process that is discussed in Specification 5.5.5.2.f.3. However, the method of inspection in this area shall be a rotating plus point (or equivalent) coil. The SG tube repair criterion of Specification 5.5.5.2.c.3 is applicable to flaws in this area.

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. The tube-to-tubesheet weld is not part of the tube. In tubes repaired by sleeving, the portion of the original tube wall between the sleeve's joints is not an area requiring re-inspection. In addition to meeting the requirements of d.1, d.2, d.3, d.4, d.5, d.6 and d.7 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and Beaver Valley Units 1 and 2 5.5 -10 Amendments 278 / TBID

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued) location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

2. Inspect 100% of the tubes at sequential periods of 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one interval between refueling outages (whichever is less) without being inspected.

3: If crack indications are found in any SG tube, 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 interval between refueling outages (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.

4. Indications left in service as a result of application of the tube support plate voltage-based repair criteria (Specification 5.5.5.2.c.4) shall be inspected by bobbin coil probe during all future refueling outages.

Implementation of the steam generator tube-to-tube support plate repair criteria requires a 100-percent bobbin coil inspection for hot-leg and cold-leg tube support plate intersections down to the lowest cold-leg tube support plate with known outside diameter stress corrosion cracking (ODSCC) indications. The determination of the lowest cold-leg tube support plate intersections having ODSCC indications shall be based on the performance of at least a 20-percent random sampling of tubes inspected over their full length.

5. When the F* methodology has been implemented, inspect 100% of the inservice tubes in the hot-leg tubesheet region with the objective of detecting flaws that may satisfy the applicable tube repair criteria of Specification 5.5.5.2.c.5 every 24 effective full power months or one interval between refueling outages (whichever is less).

6. The F* methodology shall be implemented whenever an inspection of the cold-leg tubesheet region is required. The initial sample population shall be at least a 20% random sample of the in-service tubes (for the entire F* distance) in the SG being inspected. Expansion of the initial population shall be as defined in the degradation assessment.

Beaver Valley Units 1 and 2 5.5- 11 Amendments 278 / TBD

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.5.2 Unit 2 Steam Generator (SG) Program (continued)

7. For Alloy 800 sleeves: The parent tube, in the area where the sleeve-to-tube hard roll joint (lower joint) and the sleeve-to-tube hydraulic expansion joint (upper joint) will be established, shall be inspected prior to installation of the sleeve. Sleeve installation may proceed only if the inspection finds these regions free from service induced indications.

e. Provisions for monitoring operational primary to secondary LEAKAGE

f. Provisions for SG Tube Repair Methods Steam generator tube repair methods shall provide the means to reestablish the RCS pressure boundary integrity of SG tubes without removing the tube from service. For the purposes of these Specifications, tube plugging is not a repair. All acceptable tube repair methods are listed below.

1. ABB Combustion Engineering TIG welded sleeves, CEN-629-P, Revision 02 and CEN-629-P Addendum 1.

2. Westinghouse laser welded sleeves, WCAP-13483, Revision 2.

3. Westinghouse leak-limiting Alloy 800 sleeves, WCAP-15919-P, Revision 2. All Alloy 800 sleeves shall be removed from service by the spring of 2017 Unit 2 refueling outage (2R19).

5.5.6 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables,

b. Identification of the procedures used to measure the values of the critical variables,

c. Identification of process sampling points,

d. Procedures for the recording and management of data,

e. Procedures defining corrective actions for all off control point chemistry conditions, and

f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

Beaver Valley Units 1 and 2 5.5 - 12 Amendments 278 / TBD

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.6.2 Unit 2 Steam Generator Tube Inspection Report (continued)

b. If indications are identified that extend beyond the confines of the tube support plate.

c. If indications are identified at the tube support plate elevations that are attributable to primary water stress corrosion cracking.

4. A report shall be submitted within 90 days after the initial entry into MODE 4 following an outage in which the F* methodology was applied. As applicable, the report shall include the following hot-leg and cold-leg tubesheet region inspection results associated with the application of F*:

a. Total number of indications, location of each indication, orientation of each indication, severity of each indication, and whether the indications initiated from the inside or outside surface.

b. The cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet.

c. The projected end-of-cycle accident-induced leakage from tubesheet indications.

Beaver Valley Units 1 and 2 5.6- 6 Amendments 278 / TBD