ML070790070
| ML070790070 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 03/27/2007 |
| From: | Richard Ennis NRC/NRR/ADRO/DORL/LPLI-2 |
| To: | Levis W Public Service Enterprise Group |
| Ennis R, NRR/DORL, 415-1420 | |
| Shared Package | |
| ml070790081 | List: |
| References | |
| TAC MD4034 | |
| Download: ML070790070 (17) | |
Text
March 27, 2007 Mr. William Levis Senior Vice President & Chief Nuclear Officer PSEG Nuclear LLC - N09 Post Office Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNIT NO. 1, ISSUANCE OF AMENDMENT RE: STEAM GENERATOR ALTERNATE REPAIR CRITERIA (TAC NO. MD4034)
Dear Mr. Levis:
The Commission has issued the enclosed Amendment No. 279 to Facility Operating License No. DPR-70 for the Salem Nuclear Generating Station (Salem), Unit No. 1. This amendment consists of changes to the Technical Specifications (TSs) in response to your application dated January 18, 2007, as supplemented by letters dated February 23, March 9, and March 22, 2007.
The amendment approves a one-time change to the TSs regarding the steam generator (SG) tube inspection and repair required for the portion of the SG tubes passing through the tubesheet region. Specifically, for Salem Unit No. 1 refueling outage 18 (planned for spring 2007) and the subsequent operating cycle, the TS changes limit the required inspection (and repair if degradation is found) to the portions of the SG tubes passing through the upper 17 inches of the approximate 21-inch tubesheet region.
A copy of our safety evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.
Sincerely,
/ra/
Richard B. Ennis, Senior Project Manager Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-272
Enclosures:
- 1. Amendment No. 279 to License No. DPR-70
- 2. Safety Evaluation cc w/encls: See next page
March 27, 2007 Mr. William Levis Senior Vice President & Chief Nuclear Officer PSEG Nuclear LLC - N09 Post Office Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNIT NO. 1, ISSUANCE OF AMENDMENT RE: STEAM GENERATOR ALTERNATE REPAIR CRITERIA (TAC NO. MD4034)
Dear Mr. Levis:
The Commission has issued the enclosed Amendment No. 279 to Facility Operating License No. DPR-70 for the Salem Nuclear Generating Station (Salem), Unit No. 1. This amendment consists of changes to the Technical Specifications (TSs) in response to your application dated January 18, 2007, as supplemented by letters dated February 23, March 9, and March 22, 2007.
The amendment approves a one-time change to the TSs regarding the steam generator (SG) tube inspection and repair required for the portion of the SG tubes passing through the tubesheet region. Specifically, for Salem Unit No. 1 refueling outage 18 (planned for spring 2007) and the subsequent operating cycle, the TS changes limit the required inspection (and repair if degradation is found) to the portions of the SG tubes passing through the upper 17 inches of the approximate 21-inch tubesheet region.
A copy of our safety evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.
Sincerely,
/ra/
Richard B. Ennis, Senior Project Manager Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-272
Enclosures:
- 1. Amendment No. 279 to License No. DPR-70
- 2. Safety Evaluation cc w/encls: See next page DISTRIBUTION:
PUBLIC RidsOgcRp KKarwoski LPL1-2 R/F RidsAcrsAcnwMailCenter RidsNrrDorlLpl1-2 RidsNrrDirsltsb RidsNrrLASLittle RidsRgn1MailCenter RidsNrrPMREnnis GHill (2), OIS RidsNrrDorlDPR EMurphy Package Accession No.: ML070790081 Amendment Accession No: ML070790070 TS Accession No.: ML070870467 OFFICE LPL1-2/PM LPL1-2/LA CSGB/BC ITSB/BC OGC LPL1-2/BC NAME REnnis SLittle AHiser TKobetz JMartin HChernoff DATE 3/27/07 3/21/07 3/27/07 3/20/07 3/22/07 3/27/07 OFFICIAL RECORD COPY
Salem Nuclear Generating Station, Unit Nos. 1 and 2 cc:
Mr. Dennis Winchester Vice President - Nuclear Assessment PSEG Nuclear P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. Thomas P. Joyce Site Vice President - Salem PSEG Nuclear P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. George H. Gellrich Plant Support Manager PSEG Nuclear P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. Carl J. Fricker Plant Manager - Salem PSEG Nuclear - N21 P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. James Mallon Manager - Licensing 200 Exelon Way, KSA 3-E Kennett Square, PA 19348 Mr. Steven Mannon Manager - Regulatory Assurance P.O. Box 236 Hancocks Bridge, NJ 08038 Jeffrie J. Keenan, Esquire PSEG Nuclear - N21 P.O. Box 236 Hancocks Bridge, NJ 08038 Township Clerk Lower Alloways Creek Township Municipal Building, P.O. Box 157 Hancocks Bridge, NJ 08038 Mr. Paul Bauldauf, P.E., Asst. Director Radiation Protection Programs NJ Department of Environmental Protection and Energy CN 415 Trenton, NJ 08625-0415 Mr. Brian Beam Board of Public Utilities 2 Gateway Center, Tenth Floor Newark, NJ 07102 Regional Administrator, Region I U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Senior Resident Inspector Salem Nuclear Generating Station U.S. Nuclear Regulatory Commission Drawer 0509 Hancocks Bridge, NJ 08038
PSEG NUCLEAR, LLC EXELON GENERATION COMPANY, LLC DOCKET NO. 50-272 SALEM NUCLEAR GENERATING STATION, UNIT NO. 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 279 License No. DPR-70 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment filed by PSEG Nuclear LLC, acting on behalf of itself and Exelon Generation Company, LLC (the licensees) dated January 18, 2007, as supplemented by letters dated February 23, March 9, and March 22, 2007, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in Title 10 of the Code of Federal Regulations (10 CFR), Chapter I; B.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance: (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D.
The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.
2.
Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Facility Operating License No. DPR-70 is hereby amended to read as follows:
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 279, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.
3.
This license amendment is effective as of its date of issuance and shall be implemented within 60 days.
FOR THE NUCLEAR REGULATORY COMMISSION
/ra/
Harold K. Chernoff, Chief Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to the Facility Operating License and the Technical Specifications Date of Issuance: March 27, 2007
ATTACHMENT TO LICENSE AMENDMENT NO. 279 FACILITY OPERATING LICENSE NO. DPR-70 DOCKET NO. 50-272 Replace the following page of Facility Operating License No. DPR-70 with the attached revised page as indicated. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.
Remove Insert Page 4 Page 4 Replace the following pages of the Appendix A, Technical Specifications, with the attached revised pages as indicated. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.
Remove Insert 6-19c 6-19c 6-19d 6-19d 6-24b 6-24b
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 279 TO FACILITY OPERATING LICENSE NO. DPR-70 PSEG NUCLEAR, LLC EXELON GENERATION COMPANY, LLC SALEM NUCLEAR GENERATING STATION, UNIT NO. 1 DOCKET NO. 50-272
1.0 INTRODUCTION
By letter dated January 18, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML070240296), as supplemented by letters dated February 23, March 9, and March 22, 2007, PSEG Nuclear, LLC (the licensee) submitted a request for changes to the Salem Nuclear Generating Station (Salem), Unit 1, Technical Specifications (TSs). The amendment request proposes a one-time change to the TSs regarding the steam generator (SG) tube inspection and repair required for the portion of the SG tubes passing through the tubesheet region. Specifically, for Salem Unit 1 refueling outage 18 (planned for spring 2007) and the subsequent operating cycle, the proposed TS changes would limit the required inspection (and repair if degradation is found) to the portions of the SG tubes passing through the upper 17 inches of the approximate 21-inch tubesheet region. The proposed amendment would change TS 6.8.4.i, Steam Generator (SG) Program, and TS 6.9.1.10, Steam Generator Tube Inspection Report.
The subject amendment request supercedes an earlier amendment request dated October 2, 2006 (ADAMS Accession No. ML062920219) which requested similar changes, but on a permanent basis. The Nuclear Regulatory Commission (NRC or the Commission) staff has concluded that further review and evaluation is needed before the requested changes can be approved on a permanent basis. The October 2, 2006, submittal attached a technical support document, WCAP-16640, Steam Generator Alternate Repair Criteria for the Tube Portion Within the Tubesheet at Salem Unit 1, which was also reviewed by the NRC staff as part of its review of the subject amendment request.
The supplements dated February 23, March 9, and March 22, 2007, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on January 25, 2007 (72 FR 3427).
2.0 REGULATORY EVALUATION
Salem Unit 1 has four Model F SGs designed and fabricated by Westinghouse. There are 5626 tubes in each SG, each with an outside diameter of 0.688-inches and a nominal wall thickness of 0.040-inches. The tubes are hydraulically expanded for the full depth of the tubesheet at each end and are welded to the tubesheet at the bottom of each expansion. Based on recent operating experience at plants with Alloy 600 TT tubing, the Alloy 600 TT tubing at Salem Unit 1 is potentially susceptible to stress corrosion cracking (SCC) in the tubesheet region.
SG tubes function as an integral part of the reactor coolant pressure boundary (RCPB) and, in addition, serve to isolate radiological fission products in the primary coolant from the secondary coolant and the environment. For the purposes of this Safety Evaluation (SE), tube integrity means that the tubes are capable of performing these functions in accordance with the plant design and licensing basis.
Title 10 of the Code of Federal Regulations (10 CFR) establishes the fundamental regulatory requirements with respect to the integrity of the SG tubing. Specifically, the General Design Criteria (GDC) in Appendix A to 10 CFR Part 50 state that the RCPB shall have an extremely low probability of abnormal leakage...and gross rupture" (GDC 14), "shall be designed with sufficient margin" (GDC 15 and 31), shall be of "the highest quality standards possible" (GDC 30), and shall be designed to permit "periodic inspection and testing... to assess...
structural and leak tight integrity" (GDC 32). To this end, 10 CFR 50.55a specifies that components which are part of the RCPB must meet the requirements for Class 1 components in Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code). Section 50.55a further requires, in part, that throughout the service life of a pressurized-water reactor (PWR) facility, ASME Code Class 1 components meet the requirements, except design and access provisions and pre-service examination requirements, in Section XI, "Rules for Inservice Inspection [ISI] of Nuclear Power Plant Components," of the ASME Code, to the extent practical. This requirement includes the inspection and repair criteria of Section XI of the ASME Code.Section XI requirements pertaining to ISI of SG tubing are augmented by additional SG tube surveillance requirements in the TS.
As part of the plant licensing basis, applicants for PWR licenses are required to analyze the consequences of postulated design-basis accidents (DBAs) such as an SG tube rupture (SGTR) and main steamline break (MSLB). These analyses consider the primary-to-secondary leakage through the tubing which may occur during these events and must show that the radiological consequences do not exceed the applicable limits of 10 CFR 50.67 or 10 CFR Part 100 guidelines for offsite doses, GDC-19 criteria for control room operator doses, or the NRC-approved licensing basis (e.g., a small fraction of these limits).
TS 6.8.4.i. requires that an SG Program be established and implemented to ensure that SG tube integrity is maintained. Tube integrity is maintained by meeting specified performance criteria (in TS 6.8.4.i.b) for structural and leakage integrity, consistent with the plant design and licensing bases. These criteria also constitute the acceptance criteria for the subject license amendment. TS 6.8.4.i.a requires a condition monitoring assessment be performed during each outage during which the SG tubes are inspected to confirm that the performance criteria are being met. TS 6.8.4.i.d includes provisions regarding the scope, frequency, and methods of SG tube inspections. Of relevance to the subject amendment request, these provisions require that the number and portions of tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type that may be present along the length of a tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The applicable tube repair criteria specified in TS 6.8.4.i.c is that tubes found by ISI to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
The proposed license amendment (applicable during refueling outage 18 and the subsequent operating cycle) would limit the required inspections in the tubesheet region to the upper 17-inches of the 21-inch thick tubesheet. Similar (one or two cycle) amendments have been approved for several other plants with Westinghouse Model D5 and Model F SGs over the past 2 years.
3.0 TECHNICAL EVALUATION
3.1 Proposed TS Changes
TS 6.8.4.i.c provides SG tube repair criteria and currently states that:
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 proposed amendment would add the following to TS 6.8.4.i.c:
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: Tubes with flaws located below 17 inches from the top of the tubesheet may remain in service regardless of size. Tubes with flaws 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 provides provisions for SG tube inspection and currently states, in part, that:
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 tube repair criteria.
The proposed amendment would add the following to TS 6.8.4.i.d after the above paragraph:
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 below 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.
TS 6.9.1.10 specifies reporting requirements for SG tube inspections. The proposed amendment would add the following new requirements to the existing requirements:
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.
3.2 General Discussion The tube-to-tubesheet joint consists of the tube, which is hydraulically expanded against the bore of the tubesheet, the tube-to-tubesheet weld located at the tube end, and the tubesheet.
The joint was designed as a welded joint in accordance with the ASME Code,Section III, not as a friction (or expansion) joint. The weld itself was designed as a pressure boundary element in accordance with the ASME Code,Section III. It was designed to transmit the entire end cap pressure load during normal and DBA conditions from the tube to the tubesheet with no credit taken for the friction developed between the hydraulically-expanded tube and the tubesheet. In addition, the weld serves to make the joint leak tight.
The licensee, in effect, is proposing to exempt, during Refueling Outage 18 and the subsequent operating cycle, the lower 4 inches of the 21-inch deep tubesheet region from a tube inspection and to exempt tubes with flaw indications in the lower 4-inch zone from the need to plug. The latter part of this proposal (i.e., to exempt tubes from plugging) is needed as a practical matter since although rotating coil probe inspections will not be performed in this region, the bobbin probe will necessarily be recording any signals produced in this zone. This proposal, in effect, redefines the pressure boundary at the tube-to-tubesheet joint as consisting of a friction (or expansion) joint with the tube hydraulically expanded against the tubesheet over the top 17 inches of the tubesheet region. Under this proposal, no credit is taken for the lower 4 inches of the tube or the tube-to-tubesheet weld in contributing to the structural or leakage integrity of the joint. The lower 4 inches of the tube and weld are assumed not to exist.
The standard by which the NRC staff has evaluated the proposed amendment is that the amended TSs should continue to ensure that tube integrity will be maintained. This includes maintaining structural safety margins consistent with the structural integrity performance criteria in TS 6.8.4.i.b.1 (which in turn is consistent with the plant design basis as embodied in the stress limit criteria of the ASME Code,Section III) as discussed in SE Section 3.3 below. In addition, this includes limiting the potential for accident-induced primary-to-secondary leakage to values not exceeding the accident leakage performance criteria in TS 6.8.4.i.b.2 (which are consistent with the licensing basis accident analyses) as discussed in SE Section 3.4 below.
Maintaining tube integrity in this manner ensures that the amended TSs are in compliance with all applicable regulations.
The licensee is also proposing to plug all tubes found with flaws in the upper 17-inch region of the tubesheet during Refueling Outage 18 and the subsequent operating cycle (see proposed revision to TS 6.8.4.i.c). The NRC staff finds this proposed requirement acceptable since it is more conservative than the current TS 40% repair criteria and will provide added assurance that the length of tubing along the entire proposed 17-inch inspection zone will be effective in resisting tube pull out under tube end cap pressure loads and in resisting primary-to-secondary leakage between the tube and tubesheet.
3.3 Joint Structural Integrity Westinghouse has conducted analysis and testing to establish the engagement (embedment) length of hydraulically-expanded tubing inside the tubesheet that is necessary to resist pullout under normal operating and DBA conditions (designated by Westinghouse as the H* (H star) criterion). Pullout is the structural failure mode of interest since the tubes are radially constrained against axial fishmouth rupture by the presence of the tubesheet. The axial force which could produce pullout derives from the pressure end cap loads due to the primary-to-secondary pressure differentials associated with normal operating and DBA conditions. The licensees contractor, Westinghouse, determined the required engagement distance on the basis of maintaining a factor of three against pullout under normal operating conditions and a factor of 1.4 against pullout under accident conditions. This is acceptable to the NRC staff since it is consistent with the structural performance criteria burst margin requirements in TS 6.8.4.i.b.1.
The resistance to pullout is the axial friction force developed between the expanded tube and the tubesheet over the engagement distance. The friction force is a function of the radial contact pressure between the expanded tube and the tubesheet. The radial contact pressure derives from several contributors including (1) the contact pressure associated directly with the hydraulic expansion process, (2) additional contact pressure due to differential radial thermal expansion between the tube and tubesheet under hot operating conditions, (3) additional contact pressure caused by the primary pressure inside the tube, (4) reduced contact pressure due to pressure inside the crevice between the tube and tubesheet, and (5) additional or reduced contact pressure associated with tubesheet bore dilation (distortion) caused by tubesheet bow (deflection) as a result of the primary-to-secondary pressure load acting on the tubesheet. Westinghouse employed a combination of pullout tests and analyses, including finite element analyses, to evaluate these contributors. Based on these analyses and tests, Westinghouse initially concluded in WCAP-16640 that the required engagement distances, to ensure the safety factor criteria against pullout are achieved, vary from 2.25 to 7.05 inches depending on the radial location of the tube within the tube bundle, with the largest engagement distances needed toward the center of the bundle.
In its letter dated February 23, 2007, the licensee provided revised analyses which, in part, addressed recent test results indicating that a fundamental assumption in the original analyses (i.e., the analyses provided with the October 2, 2006, letter which enclosed WCAP-16640) was not justified. Specifically, the original analysis assumes that for a through-wall flaw located 17 inches or more below the top of the tubesheet, primary water inside the tube flashes to steam at secondary side pressure when it leaks through the flaw into the tube-to-tubesheet crevice. The recent tests were performed with several small, through-wall round holes representing the flaw under hot conditions. These tests indicated that the leakage through the holes remains in liquid state. Pressure inside the crevice ranges from primary pressure at the hole location to saturation pressure (based on primary water temperature) near the top of the crevice. The net effect relative to the original analyses is to reduce the pressure drop across the tube wall and, thus, to reduce the contact pressure between the tube and tubesheet.
The revised analyses included a revised finite element model of the tubesheet. The revised model is described by Westinghouse as a more detailed finite element model than that used in the original analyses. Westinghouse states that the original model was over conservative because it did not account for features in the lower SG region that act to increase the resistance of the tubesheet to vertical deflections. For example, the finite element model did not include the tube lane and the channel head to divider plate weld.
The revised analyses also considered a case where the divider plate is assumed to provide no restraint to vertical deflection of the tubesheet. This case was analyzed in response to an NRC staff question concerning the implications of cracks being found by inspection in the welds connecting the tubesheet to divider plate at certain foreign reactors.
The revised analyses, including the assumption of no divider plate restraint against tubesheet deflection, shows that the tube-to-tubesheet engagement distance that is needed to provide the required margins against pullout is 4.82 to 11.51 inches, compared to 2.25 to 7.05 inches indicated by the original analysis. The revised engagement distances are well within the proposed 17-inch inspection zone.
The technical basis for the proposed 17-inch tubesheet inspection zone and associated tube repair criteria is based in part on pullout tests conducted on nine tube-to-tubesheet joint specimens. These specimens utilized cylindrical collars to simulate the actual tubesheet.
These test collars were fabricated from 1018 steel rather than A508 steel from which the tubesheet is actually fabricated. When analyzing the results of the pullout tests, Westinghouse assumed that the thermal expansion coefficient (TEC) for 1018 steel was identical to that for A508 steel, consistent with the applicable nominal thermal expansion coefficients in Section II, Part D of the ASME Code. However, at the NRC staffs request, the licensee also analyzed the pullout test results using lower values of TEC published in the literature. This change affects the apportionment of the measured pullout loads to that provided by the tube hydraulic expansion process versus that provided by differential thermal expansion between the tube and tubesheet. Based on the reapportioned pullout test data, the licensee reanalyzed the required tubesheet engagement distance using the revised model described above and taking no credit for the divider plate restraint on the tubesheet. By letter dated March 9, 2007, the licensee reported that the net effect was to increase the required engagement distance at the limiting tube radial location from 11.51 inches to 13.0 inches, still well within the proposed 17-inch inspection zone.
The NRC staff has not reviewed the Westinghouse analyses in detail and, thus, has not reached a conclusion with respect to whether 13 inches of engagement is adequate to ensure that the necessary safety margins against pullout are maintained. The licensee, therefore, is proposing to inspect the tubes in the tubesheet region to ensure a minimum of 17 inches of effective engagement, well in excess of the 13 inches that the Westinghouse analyses indicate are needed. Pending a more detailed review of the licensees analyses, the NRC staff concludes that it cannot approve the licensees proposal on a permanent basis at this time.
However, the NRC staff also concludes there is an adequate technical basis (discussed below) to approve the proposed 17-inch inspection zone and accompanying repair criteria for a limited time period. Specifically, the NRC staff concludes that the applicability of the 17-inch inspection zone and associated repair criteria should apply only to Refueling Outage 18 and the subsequent operating cycle at Salem Unit 1, pending a more detailed review of the revised analyses submitted recently by the licensee. The technical basis (from a structural integrity standpoint) supporting the adequacy of the proposed 17-inch inspection zone and associated repair criteria for this limited time period is as follows:
1)
The NRC staff estimates, based on the Westinghouse pullout tests, that the radial contact pressure produced by the hydraulic expansion and differential radial thermal expansion requires an engagement distance of 9.0 inches to ensure the appropriate safety margins against pullout based on a no-slip criterion. This estimate is a mean minus one standard deviation estimate based on six pull tests. This estimate ignores the effect on needed engagement distance from internal primary pressure in the tube and tubesheet bore dilations associated with tubesheet bow. The NRC staff notes that from a tube pullout standpoint, the use of a no slip criterion is conservative. Allowing slippage of about 0.2 to 0.3 inches decreases the necessary engagement distance to 5.3 inches, again ignoring the effect on needed engagement distance from internal primary pressure in the tube and tubesheet bore dilations associated with tubesheet bow.
2)
The internal primary pressure inside the tube under normal operating and accident conditions also acts to tighten the joint relative to non-pressurized conditions, thus reducing the necessary engagement distance.
3)
Tubesheet bore dilations caused by tubesheet bow under primary-to-secondary pressure can increase or decrease contact pressure depending on the tube location within the bundle and on the location along the length of the tube in the tubesheet region. Basically, the tubesheet acts as a flat, circular plate under an upward acting net pressure load. The tubesheet is supported axially around its periphery with a partial restraint against tubesheet rotation provided by the SG shell and channel head. The SG divider plate provides a spring support against upward displacement along a diametral mid-line. Over most of the tubesheet away from the periphery, the bending moment resulting from the applied primary-to-secondary pressure load can be expected to put the tubesheet into tension at the top and compression at the bottom. Thus, the resulting distortion of the tubesheet bore (tubesheet bore dilation) tends to be such as to loosen the tube-to-tubesheet joint at the top of the tubesheet and to tighten the joint at the bottom of the tubesheet. The amount of dilation and resulting change in joint contact pressure would be expected to vary in a linear fashion from top to bottom of the tubesheet. Given the neutral axis to be at approximately the axial mid-point of the tubesheet thickness (i.e., 10.5 inches below the top of the tubesheet), tubesheet bore dilation effects would be expected to further tighten the joint from 10 inches below the top of the tubesheet to 17 inches below the top of the tubesheet which would be the lower limit of the proposed tubesheet region inspection zone. Combined with the effects of the joint tightening associated with the primary pressure inside the tube, contact pressure over at least a 6.5-inch distance should be considerably higher than the contact pressure simulated in the above mentioned pull out tests. A similar logic applied to the periphery of the tubesheet leads the NRC staff to conclude that at the top 10.5 inches of the tubesheet region, contact pressure should be considerably higher than the contact pressure simulated in the above mentioned pull out tests. Thus, the NRC staff concludes that the proposed 17-inch engagement distance (or inspection zone) is acceptable to ensure the structural integrity of the tubesheet joint.
3.4 Joint Leakage Integrity If no credit is taken for the presence of the tube-to-tubesheet weld, a potential leak path between the primary-to-secondary is introduced between the hydraulically-expanded tubing and the tubesheet. In addition, not inspecting the tubing in the lower 4 inches of the tubesheet region may lead to an increased potential for 100% through-wall flaws in this zone and the potential for leakage of primary coolant through the crack and up between the hydraulically expanded tubes and tubesheet to the secondary system. Operational leakage integrity is assured by monitoring primary-to-secondary leakage relative to the applicable TS limiting condition for operation (LCO) limit. However, it must also be demonstrated that the proposed TS changes do not create the potential for leakage during DBAs to exceed the values assumed in the plant licensing basis accident analyses. As shown in Table 15.4-7 of the Salem Updated Final Safety Analysis Report, primary-to-secondary leakage from a faulted SG during an MSLB is assumed to be 0.35 gpm.
To support its H* criterion (discussed above), Westinghouse has developed a detailed leakage prediction model which considers the resistance to leakage from cracks located within the thickness of the tubesheet. The NRC staff has neither reviewed nor accepted this model. For the proposed 17-inch inspection zone, Westinghouse cited a number of qualitative arguments supporting a conclusion that a minimum 17-inch engagement length ensures that leakage during MSLB, in the lower 4 inches of the tubesheet, will not exceed two times the observed leakage during normal operation. Westinghouse refers to this as the bellwether approach.
The TS LCO limit for operational primary-to-secondary leakage is 150 gallons per day (gpd) (or 0.104 gpm) per SG. Thus, for an SG leaking at the TS limit of 150 gpd under normal operating conditions, Westinghouse estimates that leakage would not be expected to exceed 0.208 gpm, which is less than the 0.35 gpm assumed in the licensing DBA analyses for an MSLB.
The factor of 2 upper bound is based on the Darcy equation for flow through a porous media where leakage rate would be proportional to differential pressure. Westinghouse considered normal operating pressure differentials between 1200 and 1400 psi and accident differential pressures on the order of 2560 to 2650 psi, essentially a factor of 2 difference. The factor of 2 as an upper bound is based on a premise that the flow resistance between the tube and tubesheet remains unchanged. Westinghouse states that the flow resistance varies as a log normal linear function of joint contact pressure. The NRC staff concurs that the factor of 2 upper bound is reasonable, given the stated premise. The NRC staff notes that the assumed linear relationship between leak rate and differential pressure is conservative relative to alternative models such as the Bernoilli or orifice models, which assume leak rate to be proportional to the square root of differential pressure.
The NRC staff reviewed the qualitative arguments developed by Westinghouse regarding the conservatism of the aforementioned premise; namely the conservatism of assuming that flow resistance between the expanded tubing and the tubesheet does not decrease under the most limiting accident relative to normal operating conditions. Most of the Westinghouse observations are based on insights derived from the finite element analyses performed to assess joint contact pressures and from test data relating leak flow resistance to joint contact pressure, neither of which has been reviewed by the NRC staff in detail. Among the Westinghouse observations is that for all tubes, there is at least an 11-inch zone in the upper 17 inches of the tubesheet where there is an increase in joint contact pressure, and, thus, leak flow resistance, due to higher primary pressure inside the tube and changes in tubesheet bore dilation along the length of the tubes. The NRC staff review of the revised analyses described in the licensees letter dated February 23, 2007 (and discussed in Section 3.3 of this SE) indicated that this observation is changed only slightly, from 11 to 10 inches. In SE Section 3.3 above, the NRC staff observed that there is at least a 6.5-inch zone over which changes in tubesheet bore dilations when going from unpressurized to pressurized conditions should result in an increase in joint contact pressure. The contact pressure due to changes in tubesheet bore dilation should increase further over this 6.5-inch zone under the increased pressure loading on the tubesheet during accident conditions. Considering the higher pressure loading in the tube when going from normal operating to accident conditions, the NRC staff finds that the Westinghouse estimates are reasonable.
Although joint contact pressures and leak flow resistance decrease over other portions of the tube length, Westinghouse expects a net increase in total leak flow resistance on the basis of its insights from leakage test data. This data shows that leak flow resistance is more sensitive to changes in joint contact pressure as contact pressure increases due to the linear log normal nature of the relationship. The NRC staffs depth of review did not permit it to credit this aspect of the Westinghouse assessment. However, it is clear from the discussion in the previous paragraph that there should be no significant reduction in leakage flow resistance when going from normal operating to accident conditions.
Finally, the NRC staff finds that undetected cracks in the lower 4 inches are unlikely to produce leakage rates during normal operation that would approach the operational leakage limit (150 gpd), thus providing additional confidence that such cracks will not result in leakage in excess of the values assumed in the accident analyses. Any axial cracks will be tightly clamped by the tubesheet, limiting the opening of the crack faces. In addition, little of the end cap pressure load should remain in the tube below 17 inches and, thus, any circumferential cracks would be expected to remain tight. Thus, irrespective of the flow resistance in the upper 17 inches of the tubesheet between the tube and tubesheet, the tightness of the cracks themselves should limit leakage to very small values.
Based on the above, the NRC staff concludes that there is reasonable assurance that the proposed exclusion of the lower 4 inches of the tubes in the tubesheet region from the tube inspection and repair criteria requirements will not impair the leakage integrity of the tube-to-tubesheet joint for Refueling Outage 18 and the subsequent operating cycle.
It is the licensees responsibility to ensure that total accident-induced leakage for the entirety of the tubing (not just the 4-inch exclusion zone) is within the accident leakage performance criteria of TS 6.8.4.1.b.2. The proposed new reporting requirements in TS 6.9.1.10 will allow the NRC staff to monitor potential accident leakage from the lowermost 4 inches of the tubesheet. As discussed above, the NRC staff has concluded that accident leakage in the lowermost 4 inches of the tubesheet will not increase by more than a factor of two over normal operating value in this region immediately prior to the accident. The proposed new reporting requirements will allow the NRC staff to monitor how and on what basis the licensee is apportioning observed normal operating leakage between the lowermost 4 inches of the tubesheet and the rest of the SG for purposes of determining the potential accident leak rate contribution from the lowermost 4 inches of the tubesheet. The NRC staff concludes the proposed new reporting requirements are acceptable.
3.5 Technical Evaluation Conclusion
The NRC staff finds that the proposed amended TSs will ensure that the structural and leakage integrity of the tube-to-tubesheet joint will be maintained during Refueling Outage 18 and the subsequent operating cycle, with structural safety margins consistent with the design basis, with leakage integrity within assumptions employed in the licensing basis accident analyses, and, thus, in accordance with the applicable regulations without undue risk to public health and safety. Therefore, the NRC concludes that the proposed amendment is acceptable.
4.0 STATE CONSULTATION
In accordance with the Commission's regulations, the New Jersey State official was notified of the proposed issuance of the amendment. The State official had no comments.
5.0 ENVIRONMENTAL CONSIDERATION
The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (72 FR 3427). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.
6.0 CONCLUSION
The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
Principal Contributor: E. Murphy Date: March 27, 2007