LR-N07-0005, One Time License Change Request LCR S07-01 Steam Generator Alternate Repair Criteria (17 Inch Inspection Distance)

One Time License Change Request LCR S07-01 Steam Generator Alternate Repair Criteria (17 Inch Inspection Distance)

ML070240296
Person / Time
Site:	Salem
Issue date:	01/18/2007
From:	Joyce T Public Service Electric & Gas Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LCR S07-01, LR-N07-0005
Download: ML070240296 (35)

Text

PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236 10 CFR 50.90 January 18, 2007 PSE G LR-N07-0005 Nuclear LLC United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 SALEM GENERATING STATION - UNIT 1 FACILITY OPERATING LICENSE NOS. DPR-70 NRC DOCKET NO. 50-272

Subject:

ONE TIME LICENSE CHANGE REQUEST LCR S07-01 STEAM GENERATOR ALTERNATE REPAIR CRITERIA (17 INCH INSPECTION DISTANCE)

References:

(1) Letter from PSEG to NRC: "License Change Request S06-011, WCAP-1 6640, Steam Generator Alternate Repair Criteria (H*B*

Methodology), Salem Nuclear Generating Station, Unit 1, Facility Operating License DPR-70, Docket No. 50-272", dated October 2, 2006 In accordance with the provisions of 10 CFR 50.90, PSEG Nuclear, LLC (PSEG) previously transmitted a request for amendment of the Technical Specifications (TS) for Salem Generating Station Unit 1 (Reference 1). The proposed amendment requested modification of the Salem Unit 1 Technical Specifications by changing the scope of the steam generator (SG) tubesheet inspections required in the SG tubesheet region, using the H* / B* methodology, as defined in WCAP-16640, dated August 2006.

Following additional review and discussion with the NRC staff, PSEG proposes to supercede the October 2, 2006 submittal (Reference 1) as outlined below. Pursuant to the requirements of 10 CFR 50.91(b)(1), a copy of this amendment request modification has been sent to the State of New Jersey.

The WCAP-16640 report analysis, provided in Reference 1, supported a license amendment to eliminate, on a permanent basis, inspection of the region of the tubesheet below a bounding H* or B* distance from the top of the tubesheet. For the Salem Unit 1 SGs, a distance of 8 inches from the top of the tubesheet was justified as the inspection distance, which was the distance proposed in our October 2, 2006 submittal. In addition to this 8 inch distance, the WCAP report also supports the implementation of a more conservative 17 inch inspection length alternate repair criteria for Salem Unit 1. PSEG proposes to supercede our request for the permanent 8 inch inspection distance, to a one time change for the 17 inch inspection distance.

95-2168 REV. 7/99

Document Control Desk 2 LR-N07-0005 A similar type of Technical Specification change was approved, on a one-time basis, to limit inspections of the Wolf Creek Model F and Braidwood 2 Model D5 SGs during the spring 2005 inspection campaigns. Subsequent approvals were also obtained for use at Byron 2 and Vogtle 2 for their fall 2005 inspection campaigns. WCAP-16640 provides detailed discussion on the Westinghouse analyses and NRC staff conclusions on the applicability of the 17 inch inspection distance, for both structural integrity and joint leakage integrity. Based on the WCAP analyses, and previous NRC staff conclusions, the 17 inch inspection distance is appropriate for Salem Unit 1 on a one time basis.

With regards to the no significant hazards determination, the change from the 8 inch distance to the more conservative 17 inch distance does not alter the conclusion provided in our October 2, 2006 submittal (Reference 1). There is no increase in the probability or consequences of the postulated limiting accident conditions because the margins inherent in the original design basis are maintained and the expected leak rate during the postulated accident is not expected to increase beyond the plant specific limit. In addition, the relocation of the pressure boundary to a more conservative distance does not create the potential for a new or departure from the previously evaluated accident events. Finally, the margins of safety inherent in the original design bases are maintained. The no significant hazards determination is appropriately revised in Attachment 2 to this letter to reflect the 17 inch inspection distance. The environmental evaluation that was submitted in Reference 1 also remains applicable for this one time change.

Based on the above discussion, PSEG Nuclear LLC will implement, on a one time basis (for Refueling Outage 18 and the subsequent operating cycle), the following repair criteria and acceptance criteria for Salem Unit 1 SGs:

• Any type or combination of tube degradation below 17 inches from the top of the tubesheet on the hot or cold leg side may be left in service.

• Degradation in tubes less than or equal to 17 inches from the top of the tubesheet on the hot leg or cold leg side must be plugged. provides an evaluation of the revised amendment request. Attachment 2 provides the revised No Significant Hazards Evaluation. Attachment 3 provides the existing TS pages marked up to show the revised changes.

PSEG requests a 60-day implementation period after amendment approval.

Approval of this change is requested by March 1, 2007 to support Salem Generating Station Unit 1 refueling outage 1 R1 8.

If you have any questions or require additional information, please do not hesitate to contact Mr. Jamie Mallon at (610) 765-5507.

Document Control Desk 3 LR-N07-0005 I declare under penalty of perjury that the foregoing is true and correct.

Executed on L-/

(D te)

Sincerely,

/~41w6dI Thomas P. Jo ce Site Vice President Salem Generating Station Attachments (3)

CC Mr. S. Collins, Administrator - Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Mr. S. Bailey, Licensing Project Manager - Salem U. S. Nuclear Regulatory Commission Mail Stop 08B1 Washington, DC 20555 Ms. F. Saba, Project Manager U. S. Nuclear Regulatory Commission Mail Stop 08B1 Washington, DC 20555 USNRC Senior Resident Inspector - (Salem X24)

Mr. K. Tosch, Manager IV Bureau of Nuclear Engineering P. O. Box 415 Trenton, NJ 08625

Document Control Desk Attachment 1 LR-N07-0005 SALEM GENERATING STATION - UNIT I DOCKET NO. 50-272 ONE TIME LICENSE CHANGE REQUEST LCR S07-01 STEAM GENERATOR ALTERNATE REPAIR CRITERIA (17 INCH INSPECTION DISTANCE)

Table of Contents

1. D E S C R IPT IO N ................................................................................................ 1

2. PRO PO S ED C HA N G E ......................................................................................... 1

3. BA C KG R O U N D ................................................................................................ 5

4. TECHNICAL ANALYSIS ................................................................................... 5

5. REGULATORY SAFETY ANALYSIS ............................................................... 5 5.1 No Significant Hazards Consideration .................................................. 5 5.2 Applicable Regulatory Requirements/Criteria ......................................... 5

6. ENVIRONMENTAL CONSIDERATION .......................................................... 7

7. R E FE R EN C ES ................................................................................................ 7

Document Control Desk Attachment 1 LR-N07-0005

1.0 DESCRIPTION

This submittal supercedes the October 2, 2006 request (Reference 7.1) for an amendment to Operating License DPR-70 for Salem Generating Station Unit 1. In the October 2, 2006 letter, PSEG Nuclear LLC (PSEG) proposed modifying the Salem Unit 1 Technical Specifications (TS) by changing the scope of the steam generator (SG) tube sheet inspections required in the SG tubesheet region, using the H* / B* methodology (as defined in WCAP-16640, August 2006). For Salem Unit 1 SGs, a distance of 8.0 inches from the top of the tubesheet was justified as the inspection distance. In addition to this 8 inch distance, the WCAP report also supports the implementation of a more conservative, bounding 17 inch inspection length alternate repair criteria for Salem Unit 1. Following additional review and discussion with the NRC staff, PSEG proposes to supercede our request for the permanent 8 inch inspection distance, to a one time change for the 17 inch inspection distance. This will be implemented for Refueling Outage 18 and the subsequent operating cycle.

The proposed change will implement the following repair criteria and acceptance criteria:

• Any type or combination of tube degradation below 17 inches from the top of the tubesheet (TTS) on the hot or cold leg side may be left in service.

" Degradation in tubes less than or equal to 17 inches from the top of the tubesheet on the hot leg or cold leg side must be plugged.

The WCAP-16640 analyses support a license amendment to eliminate inspection of the region of the tube below 17 inches from the top of the tubesheet. WCAP-1 6640 provides detailed discussion on the Westinghouse analyses and NRC staff conclusions on the applicability of the 17 inch inspection distance, for both structural integrity and joint leakage integrity. Based on the WCAP analyses, previous NRC staff conclusions and the revised No Significant Hazards Evaluation, the 17 inch inspection distance is appropriate for Salem Unit 1 on a one time basis.

A similar type of Technical Specification change was approved, on a one-time basis, to limit inspections of the Braidwood 2 and Wolf Creek SGs during the Spring 2005 inspection campaigns. Subsequent approvals were also obtained for use at Byron 2 and Vogtle 2 in their Fall 2005 inspection campaigns.

2.0 PROPOSED CHANGE

The proposed changes will revise the following Salem Unit 1 Technical Specifications on a one time basis:

TS 6.8.4.i Steam Generator (SG) Program TS 6.9.1.10 Steam Generator Tube Inspection Report 1

Document Control Desk Attachment 1 LR-N07-0005 TS B3/4.4.5 Steam Generator (SG) Tube Integrity The specific changes are discussed below.

TS 6.8.4.i Steam Generator (SG) Program TS 6.8.4.i c) currently states:

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

This criterion will be revised as follows as noted in bold type:

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

The following repair criteria are applicable only for Refueling Outage 18 and the subsequent operating cycle:

In lieu of the 40% of the nominal wall thickness repair criteria, the portion of the tube within the tubesheet of the inspected SGs shall be plugged in accordance with the following alternate repair criteria: Degradation found in the portion of the tube below 17 inches from the top of the tubesheet does not require plugging. Degradation identified in the portion of the tube from the top of the tubesheet to 17 inches below the top of the tubesheet shall be plugged on detection.

TS 6.8.4.i d) currently states:

d. "Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable repair criteria. The tube-to-tubesheet weld is not part of the tube ...........

This criterion will be revised as follows as noted in bold type:

d. "Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube from the tube-to-tubesheet weld at 2

Document Control Desk Attachment 1 LR-N07-0005 the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable repair criteria.

In lieu of the above, the following inspection criteria are applicable only for Refueling Outage 18 and the subsequent operating cycle:

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 beginning 17 inches from the top of the tubesheet on the tube hot leg side to 17 inches below the top of the tubesheet on the tube cold leg side.

The tube-to-tubesheet weld is not part of the tube ............

TS 6.9.1.10 Steam Generator Tube Inspection Report TS 6.9.1.10 currently states:

A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator (SG) Program." The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

g. The results of condition monitoring, including results of tube pulls and in-situ testing This criterion will be revised as follows as noted in bold type:

A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator (SG) Program." The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found, 3

Document Control Desk Attachment 1 LR-N07-0005

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

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

h. The following reporting requirements are applicable only for Refueling Outage 18 and the subsequent operating cycle:

The number of indications detected in the upper 17 inches of the tubesheet thickness along with their location, measured size, orientation, and whether the indication initiated on the primary or secondary side.

i. The following report requirement is applicable only for Refueling Outage 18 and the subsequent operating cycle:

The operational primary to secondary leakage rate observed in each steam generator during the cycle preceding the inspection and the calculated accident leakage rate for each steam generator from the lowermost 4 inches of tubing (the tubesheet is nominally 21.03 inches thick) for the most limiting accident. If the calculated leak rate is less than 2 times the total observed operational leakage rate, the 180 day report should describe how the calculated leak rate is determined.

TS B 3/4.4.5 Steam Generator Tube Integrity TS B 3/4.4.5 Steam Generator Tube Integrity currently states:

In the context of this Specification, a steam generator tube is defined as the entire length of tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

This criterion will be revised as follows as noted in bold type:

In the context of this Specification, a steam generator tube is defined as the entire length of tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.

For Refueling Outage 18 and the subsequent operating cycle only, the following definition applies:

4

Document Control Desk Attachment 1 LR-N07-0005 A SG tube is defined as the length of the tube beginning 17 inches from the top of the tubesheet on the tube hot leg side to 17 inches below the top of the tubesheet on the tube cold leg side as defined in LCR S07-01 (including WCAP-16640-P).

The tube-to-tubesheet weld is not considered part of the tube.

3.0 BACKGROUND

WCAP-16640, August 2006, "Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet at Salem Unit 1," provides the background information supporting this proposed TS change. WCAP-16640 was previously submitted by Reference 7.1. Supplemental information is provided in the No Significant Hazards Consideration included with this submittal (Attachment 2).

4.0 TECHNICAL ANALYSIS

WCAP-1 6640, August 2006, "Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet at Salem Unit 1," provides the technical analyses supporting this proposed TS change. WCAP-16640 was previously submitted by Reference 7.1. Supplemental information is provided in the No Significant Hazards Consideration included with this submittal (Attachment 2).

5.0 REGULATORY SAFETY ANALYSIS 5.1 No Significant Hazards Consideration , Westinghouse EVAL-07-03 SHC, "Significant Hazards Consideration (SHC), Salem Unit 1," provides the No Significant Hazards Evaluation supporting this proposed TS change. PSEG Nuclear LLC concludes that the changes proposed by this License Amendment Request satisfy the no significant hazards consideration standards of 10 CFR 50.92(c), and accordingly a no significant hazards finding is justified.

5.2 Applicable Regulatory Requirements/Criteria The regulatory requirements associated with SG tube inspections include the following:

10 CFR 50 Appendix A Criterion 14 - Reactor Coolant Pressure Boundary -

The reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and gross rupture.

10 CFR 50 Appendix A Criterion 15 - Reactor Coolant System Design - The reactor coolant system and associated auxiliary, control, and protection 5

Document Control Desk Attachment 1 LR-N07-0005 systems shall be designed with sufficient margin to assure that the design conditions of the reactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operational occurrences.

10 CFR 50 Appendix A Criterion30 - Quality of Reactor Coolant System Pressure Boundary - Components which are part of the reactor coolant pressure boundary shall be designed, fabricated, erected, and tested to the highest quality standards practical. Means shall be provided for detecting and, to the extent practical, identifying the location of the source of reactor coolant leakage.

10 CFR 50 Appendix A Criterion31 - Fracture Prevention of Reactor Coolant Pressure Boundary - The reactor coolant pressure boundary shall be designed with sufficient margin to assure that when stressed under operating, maintenance, testing, and postulated accident conditions (1) the boundary behaves in a nonbrittle manner, and (2) the probability of rapidly propagating fracture is minimized. The design shall reflect consideration of service temperatures and other conditions of the boundary material under operating, maintenance, testing, and postulated accident conditions and the uncertainties in determining (1) material properties, (2) the effects of irradiation on material properties, (3) residual steady state and transient stresses, and (4) size of flaws.

10 CFR 50 Appendix A Criterion32 - Inspection of Reactor Coolant Pressure Boundary - Components that are part of the reactor coolant pressure boundary shall be designed to permit periodic inspection and testing of important areas and features to assess their structural and leak tight integrity, and an appropriate material surveillance program for the reactor pressure vessel.

Regulatory Guide 1.83, Revision 1 - Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes.

Regulatory Guide 1.121, Revision 0 - Bases for Plugging Degraded Pressurized Water Reactor (PWR) Steam Generator Tubes.

PSEG's amendment application revises Salem Unit 1 TS to clearly delineate the scope of the SG inspection required in the tubesheet region. PSEG continues to comply with applicable regulatory requirements listed above.

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.

6

Document Control Desk Attachment 1 LR-N07-0005

6.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment relates to changes in a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR Part 20, or relates to changes in an inspection or surveillance requirement. 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 50.22(b),

no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7.0 REFERENCES

7.1 Letter from PSEG to NRC: "License Change Request S06-011, WCAP-16640, Steam Generator Alternate Repair Criteria (H*B* Methodology),

Salem Nuclear Generating Station, Unit 1, Facility Operating License DPR-70, Docket No. 50-272", dated October 2, 2006 7.2 WCAP-1 6640, August 2006, (proprietary), "Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet at Salem Unit 1."

7.3 WCAP-16640, August 2006, (non-proprietary), "Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet at Salem Unit 1."

7.4 Westinghouse EVAL-07-03 SHC, "Significant Hazards Consideration (SHC), Salem Unit 1" 7

Document Control Desk Attachment 2 LR-N07-0005 EVAL-07-03 SHC, "Significant Hazards Consideration (SHC),

Salem Unit 1" Note 1: Section 3.0 of the attached No Significant Hazards Consideration report provides proposed changes to the Salem Unit 1 Technical Specifications.

Additional administrative changes have been made to the proposed changes; these are reflected in Attachments 1 and 3 of this submittal.

Note 2: On Page 16 of 17 of this report, a numerical transposition error was detected. The accident induced leakage was incorrectly stated as 0.187 gpm; the correct value is 0.179 gpm, as documented in WCAP-16640. This transposition error has no impact on the analysis or the purpose of the report.

EVAL-07-3 SHC Page I of 17 Customer Reference No(s).

Westinghouse Reference No(s).

EVAL-07-3 WESTINGHOUSE NUCLEAR SAFETY SIGNIFICANT HAZARDS CONSIDERATION (SHC)

1) NUCLEAR PLANT(S): Salem Unit 1

2)

SUBJECT:

Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet

3) TECHNICAL SPECIFICATIONS CHANGED: 6.8.4.i Steam Generator (SG) Program, 133/4.4.5 Steam Generator Tube Integrity, 6.9.1.10 Steam Generator Tube Inspection Repor

4) A written analysis of the significant hazards consideration, in accordance with the three factor test of 10 CFR 50.92, of a proposed license amendment to implement the subject change has been prepared and is attached. On the basis of the analysis the checklist below has been completed.

Will operation of the plant in accordance with the proposed amendment:

4.1) Yes_ No X Involve a significant increase in the probability or consequences of an accident previously evaluated; 4.2) Yes_ No X Create the possibility of a new or different kind of accident from any accident previously evaluated; 4.3) Yes_ No X Involve a significant reduction in a margin of safety.

5) REFERENCE DOCUMENT:

1. WCAP-16640-P, "Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet at Salem Unit 1," August 2006

6) Comments: None

7) APPROVAL LADDER:

7.1) Prepared by: /

Ii 4W

.W. Whitem h ,te/,,/o 7.2) Reviewed by: l1y/,(07 Date:

R. ýYaylor EVAL-07-3SIIC-1/1 1/07-11:57 AM

EVAL-07-3 SHC Page 2 of 17 Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet for Salem Unit 1 10 CFR 50.92 Significant Hazards Consideration Evaluation

1.0 BACKGROUND

Indications of inner diameter (ID) cracking were reported based on the results from the nondestructive, eddy current examination of the steam generator (SG) tubes during the fall 2004 outage at the Catawba 2 nuclear power plant operated by the Duke Power Company. The tube indications at Catawba were reported about 7.6 inches from the top of the tubesheet in one tube, and just above the tube-to-tubesheet welds in a region of the tube known as the tack expansion (TE) in several other tubes. Finally, indications were also reported in the tube end welds (TEWs), also known as tube-to-tubesheet welds, joining the tube to the tubesheet. The Catawba 2 plant has Westinghouse designed, Model D5 SGs fabricated with Alloy 600TT (thermally treated) tubes. There is the potential for additional tube indications similar to those already reported at Catawba 2 within the tubesheet region to be reported during future inspections.

It was subsequently noted that an indication was reported in SG tubes at the Vogtle Unit 1 plant operated by the Southern Nuclear Operating Company. The Vogtle SGs are of the Westinghouse Model F design with slightly smaller, diameter and thickness, A600TT tubes.

Note: No indications of this type were found during the planned inspections of the Braidwood 2 SG (Model D5 SGs) tubes in April 2005, a somewhat similar inspection of the tubes in two SGs at Wolf Creek (Model F SGs) in April 2005, or an inspection of the tubes at Comanche Peak 2 (Model D5 SGs) in the spring of 2005. Also, no indications of this type were found during similar inspections at Byron 2 (Model D5 SGs) and Vogtle 2 (Model F SGs) in the fall of 2005. Additionally, 1054 bulges were examined in 2 SGs at Millstone Unit 3 in the fall of 2005 with no crack indications identified.

The SGs for all four Model D5 plant sites were fabricated in the 1978 to 1980 timeframe using similar manufacturing processes with a few exceptions. For example, the fabrication technique used for the installation of the SG tubes at Braidwood 2 would be expected to lead to a much lower likelihood for crack-like indications to be present in the region known as the tack expansion relative to Catawba 2 because a lower stress urethane expansion process for effecting the tack expansions was adopted prior to the time of the fabrication of the Braidwood 2 SGs. The tack expansions in the steam generator tubes at Salem Unit 1 were completed by a urethane expansion process (similar to Braidwood Unit 2) as they were shipped in 1983.

EVAL-07-3SHC-l/1 1/07-2:15 PM

EVAL-07-3 SHC Page 3 of 17 The findings in the Catawba 2 and Vogtle 1 SG tubes present three distinct issues with regard to future inspections of Alloy 600TT SG tubes which have been hydraulically expanded into the tubesheet:

1) indications in internal bulges within the tubesheet,

2) indications at the elevation of the tack expansion transition, and

3) indications in the tube-to-tubesheet welds, including some extending into the tube.

2.0 DESCRIPTION

As a result of the discussion in Section 1.0, an evaluation has been performed for Salem Unit 1 that considers the requirements of the ASME Code, Regulatory Guides, NRC Generic Letters, NRC Information Notices, the Code of Federal Regulations, NEI 97-06, and additional industry requirements (Reference 1). The conclusion of the technical evaluation is that:

1) the structural integrity of the primary-to-secondary pressure boundary is unaffected by tube degradation of any magnitude below a tube location-specific depth ranging from 2.25 to 7.05 inches, designated as H*

(considering both hot and cold leg H* values), and,

2) that the accident condition leak rate can be bounded by twice the normal operation leak rate from degradation below 17 inches from the top of the 21.03 inch thick tubesheet, including degradation of the tube end welds.

These results follow from finite element analyses demonstrating that the tube-to-tubesheet hydraulic joints make it extremely unlikely that any operating or faulted condition loads are transmitted below the H* elevation, and the contact leak rate resistance increases below a certain elevation within the tubesheet. Internal tube bulges within the tubesheet are created in a number of tubes as an artifact of the manufacturing process. The analyses results support a license amendment to eliminate inspection of the region of the tube below 17 inches from the top of the tubesheet. For the Salem Unit 1 SGs, a conservative distance of 17.0 inches from the top of the tubesheet is justified as the inspection distance. Such an amendment is interpreted to constitute a redefinition of the primary-to-secondary pressure boundary relative to the original design of the SG and requires the approval of the NRC staff through a license amendment. Potential degradation regions excluded from examination would be limited to below 17 inches from the top of the tubesheet in the nominally 21.03 inch thick tubesheet, which is well below the mid-plane of the tubesheet.

A similar type of Technical Specification change was approved, on a one-time basis, to limit inspections of the Braidwood 2 and Wolf Creek SGs during the spring 2005 inspection campaigns to a distance 17 inches from the top of the tubesheet. Subsequent approvals were also obtained for use at Byron 2 and Vogtle 2 in their fall 2005 inspection campaigns for this same inspection distance.

EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 4 of 17 The development of the H* criteria involved consideration of the performance criteria for the operation of the SG tubes as delineated in NEI 97-06, Revision 2. The bases for the performance criteria are the demonstration of both structural and leakage integrity during normal operation and postulated accident conditions. The structural model was based on standard analysis techniques and finite element models as used for the original design of the SGs and documented in numerous submittals for the application of criteria to deal with tube indications within the tubesheet of other models of Westinghouse designed SGs with tube-to-tubesheet joints fabricated by other techniques, e.g., explosive expansion.

All full depth expanded tube-to-tubesheet joints in Westinghouse-designed SGs have a residual radial preload between the tube and the tubesheet. Early vintage SGs involved hard rolling which resulted in the largest magnitude of the residual interface pressure.

Hard rolling was replaced by explosive expansion which resulted in a reduced magnitude of the residual interface pressure. Finally, hydraulic expansion replaced explosive expansion for the installation of SG tubes, resulting in a further reduction in the residual interface pressure. In general, it was found that the leak rate through the joints in hard rolled tubes, if any, is insignificant. Testing demonstrated that the leak rate resistance of explosively expanded tubes was not as great and prediction methods based on empirical data to support theoretical models were developed to deal with the potential for leakage.

The same approach was followed to develop a prediction methodology for hydraulically expanded tubes. However, the model has been under review by Westinghouse since its inception, with the intent of verifying its accuracy because it involved analytically combining the results from independent tests of leak rate through cracks with the leak rate through the tube-to-tubesheet crevice. The review of the H* model for leak rate could be time consuming since it's accuracy has already been questioned by the NRC staff and identified as an issue. An alternative approach was developed for application at Salem Unit 1 from engineering expectations of the relative leak rate between normal operation and postulated accident conditions based on a first principles engineering approach.

PSEG Nuclear LLC plans to implement the following repair criteria and acceptance criteria.

• Any type or combination of tube degradation below 17 inches from the top of the tubesheet on the hot or cold leg side may be left in service.

• Degradation in tubes less than or equal to 17 inches from the top of the tubesheet on the hot leg or cold leg side must be plugged.

EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 5 of 17 3.0 PROPOSED TECHNICAL SPECIFICATION CHANGES Specifically, the proposed changes will revise the following Technical Specifications and are applicable only for Refueling Outage 18 and the subsequent operating cycle:

TS 6.8.4.i Steam Generator (SG) Program TS 6.9.1.10 Steam Generator Tube Inspection Report TS B3/4.4.5 Steam Generator (SG) Tube Integrity The proposed changes clearly delineate the scope of the steam generator inspection required in the tube joint region of the Salem Unit 1 steam generators. The specific changes are discussed below.

TS 6.8.4.i Steam Generator (SG) Program TS 6.8.4.i c) currently states:

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

This criterion will be revised as follows as noted in bold type:

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

The following repair criteria are applicable only for Refueling Outage 18 and the subsequent operating cycle:

In lieu of the 40% of the nominal wall thickness repair criteria, the portion of the tube within the tubesheet of the inspected SGs shall be plugged in accordance with the alternate repair criteria defined in LCR S06-011 (including WCAP-16640-P, "Steam Generator Alternate Repair Criteria for the Tube Portion within the Tubesheet at Salem Unit 1.") Degradation found in the portion of the tube below 17 inches from the top of the tubesheet does not require plugging. Degradation identified in the portion of the tube from the top of the tubesheet to 17 inches below the top of the tubesheet shall be plugged on detection.

TS 6.8.4.i d) currently states:

d. "Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 6 of 17 tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable repair criteria. The tube-to-tubesheet weld is not part of the tube ............

This criterion will be revised as follows as noted in bold type:

d. "Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable repair criteria.

In lieu of the above, the following inspection criteria are applicable only for Refueling Outage 18 and the subsequent operating cycle:

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 beginning 17 inches from the top of the tubesheet on the tube hot leg side to 17 inches below the top of the tubesheet on the tube cold leg side as defined in LCR S06-011 (including WCAP-16640-P).

The tube-to-tubesheet weld is not part of the tube ............

TS 6.9.1.10 Steam Generator Tube Inspection Report TS 6.9.1.10 currently states:

A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator (SG) Program." The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

g. The results of condition monitoring, including results of tube pulls and in-situ testing EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 7 of 17 This criterion will be revised as follows as noted in bold type:

A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator (SG) Program." The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

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

h. The following reporting requirements are applicable only for Refueling Outage 18 and the subsequent operating cycle:

The number of indications detected in the upper 17 inches of the tubesheet thickness along with their location, measured size, orientation, and whether the indication initiated on the primary or secondary side.

i. The following reporting requirement is applicable only for Refueling Outage 18 and the subsequent operating cycle:

The operational primary to secondary leakage rate observed in each steam generator during the cycle preceding the inspection and the calculated accident leakage rate for each steam generator from the lowermost 4 inches of tubing (the tubesheet is nominally 21.03 inches thick) for the most limiting accident. If the calculated leak rate is less than 2 times the total observed operational leakage rate, the 180 day report should describe how the calculated leak rate is determined.

TS B 3/4.4.5 Steam Generator Tube Integrity TS B 3/4.4.5 Steam Generator Tube Integrity currently states:

In the context of this Specification, a steam generator tube is defined as the entire length of tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

This criterion will be revised as follows as noted in bold type:

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EVAL-07-3 SHC Page 8 of 17 In the context of this Specification, a steam generator tube is defined as the entire length of tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet beginning 17 inches from the top of the tubesheet on the tube hot leg side and extending to 17 inches below the top of the tubesheet on the tube cold leg side.

For Refueling Outage 18 and the subsequent operating cycle only, the following definition applies:

A SG tube is defined as the length of the tube beginning 17 inches from the top of the tubesheet on the tube hot leg side to 17 inches below the top of the tubesheet on the tube cold leg side as defined in LCR S06-011 (including WCAP-16640-P).

The tube-to-tubesheet weld is not considered part of the tube.

4.0 TECHNICAL ANALYSIS

Evaluations were performed in Reference 1 to assess the need for special purpose NDE probe examinations of the SG tubes region within the tubesheet at the Salem Unit 1 power plant. The conclusions from the evaluation are that any such inspections can be limited in each SG to a depth of 17 inches from the top of the tubesheet. Tube inspection and plugging will be completed as defined in the plant Technical Specifications.

It is noted that the above inspection does not include the region of the tube referred to as the tack expansion, the tack expansion transition, and the tube end weld location. It is concluded that there is no need to inspect either the tack expansion, its transition, or the tube-to tubesheet welds for degradation. The results from the evaluations performed as described herein demonstrate that the inspection of the weld or the tube near the tube-to-tubesheet weld is not necessary to demonstrate structural adequacy of the SG during normal operation or during postulated faulted conditions or compliance with leak rate limits during postulated faulted events.

4.1 Structural Analysis The tube end weld was originally designed as a pressure boundary structural element in accordance with the requirements of Section IiI of the ASME (American Society of Mechanical Engineers) Boiler and Pressure Vessel Code. The construction code for the Salem Unit 1 SGs is the 1971 Edition through the Summer 1973 Addenda. There were no strength considerations made with regard to the expansion joint between the tube and the tubesheet, including the tack expansion regardless of whether it was achieved by rolling or Poisson expansion of a urethane plug.

An extensive empirical and analytical evaluation of the structural capability of the as-installed tube-to-tubesheet joints based on considering the weld to be absent was performed specifically for the Salem Unit 1 SGs and the results are reported in Reference EVAL-07-3SH-IC-I/1 1/07-2:15 PM

EVAL-07-3 SHC Page 9 of 17

1. Typical Model F hydraulic expansion joints with lengths comparable to those being considered for limiting RPC examination were tested for pullout resistance strength at temperatures ranging from 70 to 600'F. The results of the tests were coupled with results from finite element evaluations of the effects of temperature and primary-to-secondary pressure on the tube-to-tubesheet interface loads. The combined results were used to demonstrate that engagement lengths of 2.25 to 7.05 inches (herein referred to as the H*

distance) were sufficient to equilibrate the axial loads resulting from consideration of three times the normal operating pressure difference and 1.4 times the limiting accident condition pressure difference. The required engagement length is a function of tube location (i.e., row and column numbers), and decreases away from the center of the SG.

The tubesheet bows upward from the primary-to-secondary pressure difference and results in the tube holes becoming dilated above the neutral plane of the tubesheet, a little below the center because of the effect of the tensile membrane stress from the pressure loading. The amount of dilation is a maximum very near the center of the tubesheet and diminishes radially outward. Moreover, the tube-to-tubesheet joint becomes tighter below the neutral axis and is a maximum at the bottom of the tubesheet. In conclusion, the need for the weld is obviated by the interference fit between the tube and the tubesheet. Axial loads are not transmitted to the portion of the tube below the structural distance during operation or faulted conditions, with factors of safety of at least 3 and 1.4 respectively.

Inspection of the tube below the structural distance including the tube-to-tubesheet weld is not technically necessary. If the expansion joint were not present, there would no effect on the strength of the weld from axial cracks, and tubes with circumferential cracks up to about 1800 in azimuthal extent by 100% deep would have sufficient strength to meet the nominal ASME Code structural requirements, based on the margins of safety reported in Reference 1 and the requirements of RG 1.121.

4.2 Leak Rate Analysis of Cracked Tube-to Tubesheet Joints A discussion of the leak rate expectations from axial and circumferential cracking confined to the tube-to-tubesheet joint region, including the tack expansion region, the tube-to-tubesheet welds and areas where degradation may eventually occur due to bulges and over expansions within the tube is provided below.

From an engineering expectation standpoint, if there is no meaningful primary-to-secondary leakage during normal operation, there should likewise be no meaningful leakage during postulated accident conditions from indications located below the mid-plane of the tubesheet. The rationale for this is based on consideration of the deflection of the tubesheet with attendant dilation and diminution (expansion and contraction) of the tubesheet holes. In effect, the leakage flow area depends on the contact pressure between the tube and tubesheet and would be expected to decrease during postulated accident conditions below some distance from the top of the tubesheet. The primary-to-secondary pressure difference during normal operation is on the order of 1200 to 1500 psid, while that during a postulated accident, e.g., steam line and feed line break, is on the order of 2560 to 2650 psid. 1 Above the neutral plane of the tubesheet the tube holes tend to 1

The differential pressure could be on the order of 2405 psi if it is demonstrated that the power operated relief valves will be functional.

EVAL-07-3S-IC-1/11/07-2:15 PM

EVAL-07-3 SHC Page 10of 17 experience a dilation due to pressure induced bow of the tubesheet. This means that the contact pressure between the tubes and the tubesheet would diminish above the neutral plane in the central region of the tubesheet at the same time as the driving potential would increase. Therefore, if there was leakage through the tube-to-tubesheet crevice during normal operation from a through-wall tube indication, that leak rate could be expected to increase during postulated accident conditions. Based on early NRC staff queries regarding the leak rate modeling code associated with calculating the expected leak rate, it was expected that efforts to license criteria based on estimating the actual leak rate as a function of the contact pressure during faulted conditions on a generic basis would be problematic.

As noted, the tube holes diminish in size below the neutral plane of the tubesheet because of the upward bending and the contact pressure between the tube and the tubesheet increases. When the differential pressure increases during a postulated faulted event the increased bow of the tubesheet leads to an increase in the tube-to-tubesheet contact pressure, increasing the resistance to flow. Thus, while the dilation of the tube holes above the neutral plane of the tubesheet presents additional analytical problems in estimating the leak rate for indications above the neutral plane, the diminution of the holes below the neutral plane presents definitive statements to be made with regard to the trend of the leak rate, hence, the bellwether principle. Independent consideration of the effect of the tube-to-tubesheet contact pressure leads to similar conclusions with regard to the opening area of the cracks in the tubes, thus further restricting the leak rate beyond that through the interface between the tube and the tubesheet.

In order to accept the concept of normal operation being a bellwether for the postulated accident leak rate for indications above the neutral plane of the tubesheet, the change in leak rate had to be quantified using a somewhat complex, physically sound model of the thermal-hydraulics of the leak rate phenomenon. This is not necessarily the case for cracks considered to be present below the neutral plane of the tubesheet. This is because a diminution of the holes takes place during postulated accident conditions below the neutral plane relative to normal operation. For example, at a radius of approximately 30.19 inches from the center of the SG at the bottom of the tubesheet, the contact pressure during normal operation is calculated to be 2886.85 to 2759.66 psi2 , while the contact pressure during a postulated steam line break would be on the order of 4501.46 psi near the bottom of the tubesheet, The analytical model for the flow through the crevice, the Darcy equation for flow through porous media, indicates that flow would be expected to be proportional to the differential pressure. Thus, a doubling of the leak rate could be predicted if the change in contact pressure between the tube and the tubesheet were ignored. Examination of the nominal correlation in Reference 1 indicates that the resistance to flow (the loss coefficient) would increase during a.postulated SLB event.

The leak rate from a crack located within the tubesheet is governed by the crack opening area, the resistance to flow through the crack, and the resistance to flow provided by the tube-to-tubesheet joint. The path through the tube-to-tubesheet joint is also frequently 2 The change occurs as a result of considering various hot and cold leg operating temperatures.

EVAL-07-3SHC-1/11/07-2:15 PM

EVAL-07-3 SHC Page I Iof 17 referred to as a crevice, but is not to be confused with the crevice left at the top of the tubesheet from the expansion process. The presence of the joint makes the flow from cracks within the tubesheet much different from the flow to be expected from cracks outside of the tubesheet. The tubesheet prevents outward deflection of the flanks of cracks, a more significant effect for axial than for circumferential cracks, which is a significant contributor to the opening area presented to the flow. In addition, the restriction provided by the tubesheet greatly restrains crack opening in the direction perpendicular to the flanks regardless of the orientation of the cracks. The net effect is a large, almost complete restriction of the leak rate when the tube cracks are within the tubesheet.

The leak path through the crack and the crevice is very tortuous. The flow must go through many turns within the crack in order to pass through the tube wall, even though the tube wall thickness is relatively small. The flow within the crevice must constantly change direction in order to follow a path that is formed between the points of hard contact between the tube and the tubesheet as a result of the differential thermal expansion and the internal pressure in the tube. There is both mechanical dispersion and molecular diffusion taking place. The net result is that the flow is best described as primary-to-secondary weepage. At its base, the expression used to predict the leak rate from tube cracks through the tube-to-tubesheet crevice is the Darcy expression for flow rate, Q, through porous media, i.e.,

1 dP K.t dz where ýt is the viscosity of the fluid, P is the driving pressure, z is the physical dimension in the direction of the flow, and K is the "loss coefficient" which can also be termed the flow resistance if the other terms are taken together as the driving potential. The loss coefficient is found from a series of experimental tests involving the geometry of the particular tube-to-tubesheet crevice being analyzed, including factors such as surface finish, and then applied to the cracked tube situation.

If the leak rate during normal operation was 0.05 gpm (75 gpd), the postulated accident condition leak rate would be on the order of 0.1 gpm if only the change in differential pressure were considered; however, the estimate would be reduced when the increase in contact pressure between the tube and the tubesheet was included during a postulated steam line break event. An examination of the contact pressures as a function of depth in the tubesheet from the finite element analyses of the tubesheet shows that the bellwether principle applies to a significant extent to all indications below the neutral plane of the tubesheet. At the neutral plane of the tubesheet, the increase in contact pressure shown is more on the order of 33% relative to that during normal operation for all tubes regardless of radius. Still, the fact that the contact pressure increases means that the leak rate would be expected to be bounded by a factor of two relative to normal operation.

A comparison of the contact pressure during postulated SLB conditions relative to that during normal operation (NOp) is also provided for depths of 16.9, 10.515 and 6.0 inches below the top of the tubesheet. The observations are discussed in the following.

EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 12 of 17

" At the bottom of the tubesheet, the contact pressure increases by 1700 psi near the center of the tubesheet and exhibits no change at a radius of about 55 inches.

• At 16.9 inches below the top of the tubesheet (a little over 4.1 inches from the bottom) the tubesheet the contact pressure increases by about 1200 psi at the center to a minimum of about 200 psi at a radius of 57 inches. The contact pressure during a SLB is everywhere greater than that during NOp. The influence of the channelhead and shell at the periphery causes the deformation to become non-uniform near the periphery.

• At roughly the neutral surface, about 10.5 inches from the top of the tubesheet, the contact pressure during SLB is uniformly greater than that during normal operation by about 500 psi.

" At a depth of 6.00 inches from the TTS, the contact pressure stays constant near the center of the TS and increases by about 500 psi near the periphery.

A comparison of the curves in Section 8.0 of Reference 1 at the various elevations leads to the conclusion that for a length of 6.4 inches upward from an elevation of 4.1 inches from the bottom of the tubesheet (i.e., at the neutral plane) there is always an increase in the contact pressure in going from normal operating conditions to postulated SLB conditions. Hence, it is reasonable to omit any consideration of inspection of bulges or other artifacts below a depth of 17 inches from the top of the tubesheet. Therefore, applying a very conservative inspection sampling length of 17 inches downward from the top of the tubesheet during the Salem Unit Refueling Outage 18 provides a high level of confidence that the potential leak rate from indications below the lower bound inspection elevation during a postulated SLB will be bounded by twice the normal operation primary-to-secondary leak rate (which is limited to 150 gpd through the proposed license amendment).

The leak rate from any indication is determined by the total resistance of the crevice from the elevation of the indication to the top of the tubesheet. Thus, it would not be sufficient to simply use the depth of 7.05 inches (H* depth) and suppose that the leak rate would be relatively unchanged even if the pressure difference were the same. However, the fact that the contact pressure generally increases below that elevation indicates that the leak rate would be relatively unaffected for indications a little deeper in the tubesheet. For example, it would be expected that the leak rate would not increase meaningfully from any indications below the mid-plane of the tubesheet.

The trend is consistent at radii where the contact pressure decreases or the increase is not as great near the bottom of the tubesheet, the increase in contact pressure at higher elevations would be expected to compensate. For example, referring to Reference 1, the contact pressures show a decrease beyond a radius of approximately 55 inches at the bottom of the tubesheet, however, the increase at 4.1 inches above the bottom of the tubesheet is significant. For the outboard tubes the increase in contact pressure extends all the way to the top of the tubesheet.

EVAL-07-3SHC-I/1 1/07-2:15 PM

EVAL-07-3 SHC Page 13 of 17 A comparison of various elevations leads to the conclusion that for at least a length of 6 inches upward from an elevation of 17 inches below the top of the tubesheet there is, for the most part, always an increase in the contact pressure in going from normal operating conditions to postulated SLB conditions. Hence, it is reasonable to omit any consideration of inspection of the tube, tube end, weld, bulges or other artifacts below a depth of 17 inches from the top of the tubesheet. Therefore, applying a very conservative inspection sampling length of 17 inches downward from the top of the tubesheet provides a high level of confidence that the potential leak rate from indications below the lower bound inspection elevation during a postulated SLB event would be bounded by twice the primary-to-secondary normal operating condition leak rate.

Based on the information summarized above, no inspection of the tube-to-tubesheet welds, tack roll region or bulges below the distance determined to have the potential for safety significance as determined in Reference 1 is necessary to assure compliance with the structural and primary-to-secondary leak rate requirements for the SGs (i.e., tube pullout is precluded with a non-degraded length of hydraulic expansion within 17 inches from the top of the tubesheet and SLB leakage will remain within accident analysis assumptions through primary-to-secondary leakage monitoring).

EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 14 of 17

5.0 REGULATORY ANALYSIS

SG tube inspection and repair limits are specified in Section 6.8.4.1, "Steam Generator (SG) Program of the Salem Unit 1 Technical Specifications. The current TS require that flawed tubes be repaired if the depths of the flaws are greater than or equal to 40 percent through wall. The TS repair limits ensure that tubes accepted for continued service will retain adequate structural and leakage integrity during normal operating, transient, and postulated accident conditions, consistent with General Design Criteria (GDC) 14, 15, 30, 31, and 32 of 10 CFR 50, Appendix A. Structural integrity refers to maintaining adequate margins against gross failure, rupture, and collapse of the steam generator tubing. Leakage integrity refers to limiting primary to secondary leakage to within acceptable limits.

At normal operating pressures, leakage from primary to secondary cracking (PWSCC) below the 17 inch inspection depth is limited by both the tube-to-tubesheet crevice and the limited crack opening permitted by the tube constraint. Consequently, negligible normal operating leakage is expected from cracks within the tubesheet region.

Primary-to-secondary leakage flow due to a postulated steam generator tube rupture (SGTR) is not affected since the tubesheet enhances the tube integrity in the region of the hydraulic 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. SLB leakage is limited to a value less than the leakage occurring during normal operating conditions. The limited inspection depth of 17 inches maintains the NEI 97-06, Rev. 2 and Regulatory Guide 1.121 margins against leakage for both normal and postulated accident conditions.

For design basis events, the required structural marghins of steam generator tubes will be maintained by the presence of the tubesheet. Tube rupture is precluded for cracks in the hydraulic region due to the constraint provided by the tubesheet. The limited inspection depth of 17 inches from the top of the tubesheet, provides the necessary resistive force to preclude loads which could result in tube pullout under normal operating and accident conditions. Additionally, SLB leakage will remain within accident analysis assumptions (and the applicable 97-06, Rev. 2 performance criteria) through primary-to-secondary leakage monitoring.

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.

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EVAL-07-3 SHC Page 15 of 17 6.0 NO SIGNIFICANT HAZARDS CONSIDERATION PSEG Nuclear has evaluated the no significant hazards considerations involved with the proposed amendment, focusing on the three standards set forth in 10 CFR 50.92(c):

"The commission may make a final determination, pursuant to the procedures in paragraph 50.91, that a proposed amendment to an operating license for a facility licensed under paragraph 50.21 (b) or paragraph 50.22 or for a testing facility involves no significant hazards considerations, if operation of the facility in accordance with the proposed amendment would not:

(1) Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety."

The following evaluation is provided for the no significant hazards considerations.

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

Of the accidents previously evaluated, the proposed changes only affect 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 F steam generators has shown that axial loading of the tubes is negligible during an SSE.

At normal operating pressures, leakage from primary water stress corrosion cracking (PWSCC) below 17 inches from the top of the tubesheet 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.

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 hydraulic expansion region due to the constraint provided by the tubesheet. Therefore, the performance criteria of NEI 97-06, Rev. 2, "Steam Generator Program Guidelines" and the Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," margins against burst are maintained during normal and postulated accident conditions. The limited inspection length of 17 inches supplies the necessary EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 16 of 17 resistive force to preclude pullout loads under both normal operating and accident conditions. The contact pressure results from the hydraulic expansion process, thermal expansion mismatch between the tube and tubesheet and from the differential pressure between the primary and secondary side. Therefore, the proposed change does not result in a significant increase in the probability or consequence of a SGTR.

The probability of a SLB is unaffected by the potential failure of a SG tube as the failure of a tube is not an initiator for a SLB event. 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 leak rate during postulated accident conditions would be expected to be less than twice that during normal operation for indications near the bottom of the tubesheet (including indications in the tube end welds) based on the observation that while the driving pressure increases by about a factor of two, the flow resistance increases with an increase in the tube-to-tubesheet contact pressure. While such a decrease is rationally expected, the postulated accident leak rate is bounded by twice the normal operating leak rate if the increase in contact pressure is ignored. Since normal operating leakage is limited to 0.10 gpm (150 gpd), the attendant accident condition leak rate, assuming all leakage to be from indications below 17 inches from the top of the tubesheet would be bounded by 0.187 gpm. This value is bounded by the 0.35 gpm leak rate assumed in Section 15.4.2, "Major Secondary System Pipe Rupture" of the Salem Unit 1 Updated FSAR.

Based on the above, the performance criteria of NEI-97-06, Rev. 2 and draft RG 1.121 continue to be met and the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

The proposed change does not introduce any changes or mechanisms that create the possibility of a new or different kind of accident. Tube bundle integrity is expected to be maintained for all plant conditions upon implementation of the limited tubesheet inspection depth methodology. 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, based on the above evaluation, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

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

The proposed change maintains the required structural margins of the steam generator tubes for both normal and accident conditions. NEI 97-06, Rev. 2 and RG 1.121 are used as the basis in the development of the limited tubesheet inspection depth methodology for determining that steam generator tube integrity considerations are maintained within EVAL-07-3SHC-1/1 1/07-2:15 PM

EVAL-07-3 SHC Page 17 of 17 acceptable limits. RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14, 15, 31, and 32 by reducing the probability and consequences of an SGTR. RG 1.121 concludes that by determining 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, the probability and consequences of a SGTR are reduced. This RG uses safety factors on loads for tube burst that are consistent with the requirements of Section III of the ASME Code.

For axially oriented cracking located within the tubesheet, tube burst is precluded due to the presence of the tubesheet. For circumferentially oriented cracking, Reference 1 defines a length of non-degraded expanded tube in the tubesheet that provides the necessary resistance to tube pullout due to the pressure induced forces (with applicable safety factors applied). Application of the limited tubesheet inspection depth criteria will not result in unacceptable primary-to-secondary leakage during all plant conditions.

Plugging of the steam generator tubes reduces the reactor coolant flow margin for core cooling. Implementation of the 17 inch inspection length at Salem Unit 1 will result in maintaining the margin of flow that may have otherwise been reduced by tube plugging.

Based on the above, it is concluded that the proposed changes do not result in any reduction of margin with respect to plant safety as defined in the Final Safety Analysis Report Update or bases of the plant Technical Specifications.

7.0 CONCLUSION

Based on the above, PSEG Nuclear LLC concludes that the changes proposed by this License Amendment Request satisfy the no significant hazards consideration standards of 10 CFR 50.92(c), and accordingly a no significant hazards finding is justified.

8.0 PRECEDENTS The following precedents represent similar amendments recently approved by the NRC:

1) Braidwood Station, Units 1 and 2, - Issuance of Exigent Amendments RE:

Revision of Scope of Steam Generator Inspections for Unit 2 Refueling Outage 11 - (TAC Nos. MC6689 and MC6757), dated April 25, 2005.

2) Wolf Creek Generating Station - Issuance of Exigent Amendment RE: Steam Generator (SG) Tube Surveillance Program (TAC No. MC6757), dated April 28, 2005.

3) Byron Station, Unit 2 - Issuance of Amendment (TAC No. MC7219), dated September 19, 2005.

4) Vogtle Electric Generating Plant, Units 1 and 2 RE: Issuance of Amendments Regarding the Steam Generator Tube Surveillance Program (TAC Nos.

MC8078 and MC8079), dated September 21, 2005.

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Document Control Desk Attachment 3 LR-N07-0005 TECHNICAL SPECIFICATION PAGES WITH PROPOSED CHANGES The following Technical Specifications for Salem Unit 1 Facility Operating License DPR-70 are affected by this change request:

Technical Specification Page TS 6.8.4.i, "Steam Generator (SG) Program" 6-19c TS 6.9.1.10, "Steam Generator Tube Inspection Report" 6-24a TS B3/4.4.5, "Steam Generator (SG) Tube Integrity" B 3/4 4-2

ADMINISTRATIVE CONTROLS outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

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

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

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

Leakage is not to exceed 1 gallon per minute per SG.

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

c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40%

INSERTA of the nominal tube wall thickness shall be plugged.

HERE *

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-INSERT B to-tubesheet weld at the tube outlet, and that may satisfy the HERE applicable tube repair criteria.

The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.l, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, SALEM - UNIT I 6-19c Amendment No.268

INSERT A The following repair criteria are applicable only for Refueling Outage 18 and the subsequent operating cycle:

In lieu of the 40% of the nominal wall thickness repair criteria, the portion of the tube within the tubesheet of the inspected SGs shall be plugged in accordance with the following alternate repair criteria: Degradation found in the portion of the tube below 17 inches from the top of the tubesheet does not require plugging. Degradation identified in the portion of the tube from the top of the tubesheet to 17 inches below the top of the tubesheet shall be plugged on detection.

INSERT B In lieu of the above, the following inspection criteria are applicable only for Refueling Outage 18 and the subsequent operating cycle:

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 beginning 17 inches from the top of the tubesheet on the tube hot leg side to 17 inches below the top of the tubesheet on the tube cold leg side.

ADMINISTRATIVE CONTROLS

2. WCAP-8385, Power Distribution Control and Load Following Procedures - Topical Report, September 1974 (W Proprietary)

Methodology for Specification 3/4.2.1 Axial Flux Difference.

Approved by Safety Evaluation dated January 31, 1978.

3. WCAP-10054-P-A, Rev. 1, Westinghouse Small Break ECCS Evaluation Model Using NOTRUMP Code, August 1985 (W Proprietary), Methodology for Specification 3/4.2.2 Heat Flux Hot Channel Factor. Approved for Salem by NRC letter dated August 25, 1993.

4. WCAP-10266-P-A, Rev. 2, The 1981 Version of Westinghouse Evaluation Model Using BASH Code, Rev. 2. March 1987 (W Proprietary) Methodology for Specification 3/4.2.2 Heat Flux Hot Channel Factor. Approved by Safety Evaluation dated November 13, 1986.

5. WCAP-12472-P-A, BEACON - Core Monitoring and Operations Support System, Revision 0, (W Proprietary). Approved February 1994.

6. CENPD-397-P-A, Rev. 1, Improved Flow Measurement Accuracy Using Crossflow Ultrasonic Flow Measurement Technology, May 2000.

c. The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d. The COLR, including any mid-cycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

6.9.1.10 STEAM GENERATOR TUBE INSPECTION REPORT A report shall be submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator (SG) Program." The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

f. Total number and percentage of tubes plugged to date, and IlNSERT C HEREC g. The results of condition monitoring, including the results of tube HERE pulls and in-situ testing.

SALEM - UNIT 1 6-24a Amendment No.268

INSERT C

h. The following reporting requirements are applicable only for Refueling Outage 18 and the subsequent operating cycle:

The number of indications detected in the upper 17 inches of the tubesheet thickness along with their location, measured size, orientation, and whether the indication initiated on the primary or secondary side.

The following report requirement is applicable only for Refueling Outage 18 and the subsequent operating cycle:

The operational primary to secondary leakage rate observed in each steam generator during the cycle preceding the inspection and the calculated accident leakage rate for each steam generator from the lowermost 4 inches of tubing (the tubesheet is nominally 21.03 inches thick) for the most limiting accident. If the calculated leak rate is less than 2 times the total observed operational leakage rate, the 180 day report should describe how the calculated leak rate is determined.

For Refueling Outage 18 and the subsequent operating cycle only, the following definition applies:

SG tube is defined as the length of the tube beginning 17 REACTOR COOLANT SYSTEM inches from the top of the tubesheet on the tube hot leg side to 17 inches below the top of the tubesheet on the tube cold BASES leg side as defined in LCR S07-01 (including WCAP-16640-P).

3/4.4.4 PRESSURIZER The limit on the maximum water volume in the pressurizer assures that the parameter is maintained within the normal steady-state envelope of operation assumed in the SAR. The limit is consistent with the initial SAR assumptions. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> periodic surveillance is sufficient to assure that the parameter is restored to within its limit following expected transient operation. The maximum water volume also ensures that a steam bubble is formed and thus the RCS is not a hydraulically solid system. The requirement that a minimum number of pressurizer heaters be OPERABLE assures that the plant will be able to establish natural circulation.

3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.

The tube-to-tubesheet weld is not considered part of the tube.

A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 6.8.4.i, "Steam Generator (SG) Program," and describe acceptable SG tube performance.

The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational leakage. Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation." Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads that significantly affect burst or collapse. In that context, the term "significant" is defined as, "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." The determination of whether thermal loads are primary or secondary loads is based on the ASME definition SALEM - UNIT 1 B 3/4 4-2 TSBC SCN 05-048