ML070920008
| ML070920008 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 04/09/2007 |
| From: | Chandu Patel NRC/NRR/ADRO/DORL/LPLII-2 |
| To: | Walt T Carolina Power & Light Co |
| Patel C, NRR/DORL/LPL2-2, 415-3025 | |
| References | |
| TAC MD4046 | |
| Download: ML070920008 (16) | |
Text
April 9, 2007 Mr. Thomas D. Walt, Vice President Carolina Power & Light Company H. B. Robinson Steam Electric Plant Unit No. 2 3581 West Entrance Road Hartsville, South Carolina 29550
SUBJECT:
H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 - ISSUANCE OF AN AMENDMENT ON STEAM GENERATOR TUBE REPAIR IN THE TUBESHEET (TAC NO. MD4046)
Dear Mr. Walt:
The Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No. 214 to Renewed Facility Operating License No. DPR-23 for the H. B. Robinson Steam Electric Plant, Unit No. 2 (HBR). This amendment changes the HBR Technical Specifications in response to your application dated January 19, 2007, as supplemented by letters dated March 13 and 22, 2007.
The amendment revises the steam generator tube repair criteria for tubes within the region of the tubesheet for a single operating cycle and adds additional steam generator reporting requirements.
A copy of the related Safety Evaluation is enclosed. A Notice of Issuance will be included in the Commission's biweekly Federal Register notice.
Sincerely,
/RA/
Chandu P. Patel, Project Manager Plant Licensing Branch II-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-261
Enclosures:
- 1. Amendment No. 214 to DPR-23
- 2. Safety Evaluation cc w/encls: See next page
ML070920008 Package: ML071060259 TS: ML071060396 OFFICE LPL2-2/PM LPL2-2/LA CSGB/BC OGC LPL2-2/BC NAME CPatel RSola AHiser (by memo dated)
DRoth TBoyce DATE 04/03/07 04/06/07 03/30/07 04/09/07 04/09/07
CAROLINA POWER & LIGHT COMPANY DOCKET NO. 50-261 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 214 Renewed License No. DPR-23 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment by Carolina Power & Light Company (the licensee), dated January 19, 2007, as supplemented by letters dated March 13 and 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; 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 3.B. of Renewed Facility Operating License No. DPR-23 is hereby amended to read as follows:
B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 214, are hereby incorporated in the license. Carolina Power &
Light Company shall operate the facility in accordance with the Technical Specifications.
3.
This license amendment is effective as of the date of its issuance and shall be implemented within 60 days.
FOR THE NUCLEAR REGULATORY COMMISSION
/RA/
Thomas H. Boyce, Chief Plant Licensing Branch II-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to Operating License No. DPR-23 and the Technical Specifications Date of Issuance: April 9, 2007
ATTACHMENT TO LICENSE AMENDMENT NO. 214 RENEWED FACILITY OPERATING LICENSE NO. DPR-23 DOCKET NO. 50-261 Replace page 3 of Operating License No. DPR-23 with the attached page 3.
Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.
Remove Page Insert Pages 5.0-13 5.0-13 5.0-14 5.0-14 5.0-15 5.0-15 5.0-26 5.0-26 5.0-27 5.0-27 5.0-28 5.0-28
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 214 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-23 CAROLINA POWER & LIGHT COMPANY H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261
1.0 INTRODUCTION
By application dated January 19, 2007, as supplemented by letters dated March 13, 2007, and March 22, 2007, Carolina Power and Light Company (the licensee) submitted an application to change the H.B. Robinson Steam Electric Plant (HBR), Unit 2 technical specifications (TS) related to steam generator (SG) tube repair. The changes would revise the repair criteria for the portion of the tubes within the hot leg and cold leg regions of the tubesheet for a single operating cycle (Operating Cycle 25) following Refueling Outage (RFO) 24. The amendment would define a distance downward into the hot leg and cold leg tubesheet, below which flaws may remain in service regardless of size. As a result, tube inspection within the hot leg and cold leg region would be required only within 17 inches of the top of the tubesheet (TTS). The supplements to the January 19, 2007, application provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the Nuclear Regulatory Commission (NRC, Commission) staffs original proposed no significant hazards consideration determination as published in the Federal Register on January 30, 2007 (72 FR 4300).
The proposed changes would approve a 17-inch inspection zone at the top of the hot-leg and cold-leg tubesheet and associated tube repair criteria on a temporary basis for HBR, Unit 2.
This proposed change would only apply until the end of Operating Cycle 25. The proposed amendment also adds additional steam generator reporting requirements.
2.0 REGULATORY EVALUATION
The SGs are replacement Westinghouse Model 44F SGs with 3,214 Alloy 600 TT (thermally-treated) tubes per SG. The tubes have an outside diameter of 0.875 inches and an average wall thickness of 0.050 inches. The SGs have six stainless steel tube support plates with quatrefoil shaped holes. Based on recent operating experience at plants with Alloy 600 TT tubing, this tubing is potentially susceptible to stress corrosion cracking in the tubesheet region in the near term.
Steam generator 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, 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 Part 50.55a specifies that components which are part of the RCPB must meet the requirements for Class 1 components in Section III of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code). 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 and main steamline break (MSLB). These analyses consider the primary-to-secondary leakage through the tubing which may occur during these events and must show that the offsite radiological consequences do not exceed the applicable limits of the 10 CFR Part 50.67 or 10 CFR Part 100 guidelines for offsite doses, GDC-19 criteria for control room operator doses, or some fraction thereof as appropriate to the accident, or the NRC-approved licensing basis (e.g., a small fraction of these limits).
The proposed license amendment would limit the required inspections in the tubesheet region to the upper 17 inches of the 21.81-inch thick tubesheet during RFO 24 and the subsequent operating cycle (Operating Cycle 25). Similar amendments have been approved for Salem Unit 1, Byron Unit 2, and Braidwood Unit 2 with Westinghouse Model D5 and Model F SGs over the past 2 years.
3.0 TECHNICAL EVALUATION
3.1 Proposed TS Section 5.5.9.c, Provisions for SG tube repair criteria.
Proposed TS Section 5.5.9.c states (italics show changes):
Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding the following criteria shall be plugged: 47% [percent] of the nominal tube wall thickness if the next inspection interval of the tube is 12 months, and a 2% reduction in the repair criteria for each 12 month period until the next inspection of the tube.
The following alternate tube repair criteria shall be applied as an alternative to the preceding criteria, until the end of Operating cycle 25:
Flaws found in the portion of the tube below 17 inches from the top of the tubesheet do not require plugging. 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 upon detection.
The requirement in TS Section 5.5.9.c requiring that tubes be plugged on detection of flaws in the upper 17 inches of the tubesheet is more restrictive than the depth-based repair criteria limit which would otherwise apply. This is because the technical basis for the alternate repair criteria (ARC) and the associated 17-inch tubesheet inspection zone (evaluated in Section 3.2 of this safety evaluation) did not consider the presence of flaws in the 17-inch inspection zone. Thus, the staff finds this restriction to be acceptable.
3.1.1 Proposed TS Section 5.5.9.d, Provisions for SG tube inspections TS Section 5.5.9.d currently states in part, 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 licensee proposes to add the following parenthetical expression (in italics) to proposed TS Section 5.5.9.d:
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 (until the end of Operating Cycle 25 the required inspection length extends 17 inches below the TTS on the tube hot leg side to 17 inches below the TTS on the tube cold leg side) and that may satisfy the applicable tube repair criteria.
As evaluated in Section 3.2 of this safety evaluation, the staff finds the exclusion of the portion of tube below 17 inches from the TTS to be acceptable.
3.1.2 Proposed TS Section 5.6.8, Steam Generator Tube Inspection Report Proposed TS Section 5.6.8 adds two additional reporting requirements relating to the implementation of the proposed tubesheet ARC in TS Section 5.5.9.c and the proposed 17-inch tubesheet inspection zone in TS Section 5.5.9.d:
h.
The number of indications including location, size, and orientation, and whether the indications initiated in the primary or secondary side of the tube for each indication detected in the upper 17 inches of the tubesheet region of the tube.
i.
The operational cycle primary to secondary leakage rate observed in each SG during the cycle preceding the tube inspection that is the subject of this report and the corresponding calculated accident leakage from the lower 4.81 inches of the tube for the most-limiting accident in the most-limiting SG. If the calculated accident leakage rate for any SG is less than two times the total observed operational primary to secondary leakage rate, the report should describe how it was determined.
Proposed requirement h. will allow the staff to monitor the level of degradation activity in the tubesheet. Proposed requirement i will allow the staff to monitor potential accident leakage from the lowermost 4.81 inches of the tubesheet where the proposed ARC in TS 5.5.9.c applies and which is proposed to be excluded from the inspection requirements in TS 5.5.9.d. As discussed in Section 3.2 of this safety evaluation, the staff has concluded that accident leakage in the lowermost 4.81 inches of the tubesheet will not increase by more than a factor of two over the normal operating value in this region immediately prior to the accident. Proposed requirement i will also allow the staff to monitor how and on what basis the licensee is apportioning observed normal operating leakage between the lowermost 4.81 inches of the tubesheet and the rest of the SG for purposes of determining the potential accident leak rate contribution from the lowermost 4.81 inches of the tubesheet. The staff concludes reporting requirements h and i in proposed TS 5.6.8 are acceptable.
3.2 Proposed 17-Inch Tubesheet Inspection Zone and Associated Tube Repair Criteria 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 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 proposed TS amendment would exclude the lower 4.81 inches of the 21.81-inch deep tubesheet region from a tube inspection and, in addition, exclude tubes with flaw indications in the lower 4.81-inch zone from the need to plug. As discussed above, these exclusions would only apply until the end of Operating Cycle 25. These exclusions effectively redefine the pressure boundary at the tube-to-tubesheet joint as consisting of a friction or expansion joint with the tube assumed to be hydraulically expanded against tubesheet over the top 17 inches of the tubesheet region. Under this proposal, no credit is taken for the lower 4.81 inches of the tube or the tube-to-tubesheet weld in contributing to the structural or leakage integrity of the joint. The lower 4.81 inches of the tube, tubesheet, and weld are assumed not to exist.
The acceptance standard by which the staff has evaluated the subject license amendment is that the amended TSs should continue to ensure that tube integrity will be maintained. This includes maintaining structural safety margins consistent with the structural integrity performance criteria (which in turn are consistent with the plant design basis as embodied in the stress limit criteria of the ASME Code,Section III), as discussed in Section 3.2.1 below. In addition, this includes limiting the potential for accident-induced primary to secondary leakage to values not exceeding the accident leakage performance criteria (which are consistent with the licensing basis accident analyses), as discussed in Section 3.2.2 below. Maintaining tube integrity in this manner ensures that the amended TSs continue to be consistent 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 RFO 24 and the subsequent operating cycle (Operating Cycle 25). The staff finds this proposed requirement acceptable since it is more conservative than the current TS Section 5.5.9.c 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. In addition, it is consistent with the testing performed to support the 17-inch inspection zone since this testing was performed with non-degraded tubing.
3.2.1 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. 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 both normal operating and DBA conditions. The licensees contractor, Westinghouse, determined the required engagement distance on the basis of maintaining a factor of three against pullout under normal operating conditions and a factor of 1.4 against pullout under accident conditions.
Pullout was conservatively treated as tube slippage relative to the tubesheet of 0.25 inches.
The staff finds this to be acceptable since these safety factors are consistent with those in the structural integrity performance criteria and the design basis (i.e., the stress limit criteria in the ASME Code,Section III). The staff also finds the 0.25-inch slip criterion to be acceptable, since there is still pullout resistence beyond this amount of slip.
The resistance to pullout is the axial friction force developed between the expanded tube and the tubesheet over the engagement distance. The friction force is a function of the radial contact pressure between the expanded tube and the tubesheet. The radial contact pressure derives from several contributors including (1) the contact pressure associated directly with the hydraulic expansion process, (2) additional contact pressure due to differential radial thermal expansion between the tube and tubesheet under hot operating conditions, (3) additional contact pressure caused by the primary pressure inside the tube, (4) reduced contact pressure due to pressure inside the crevice between the tube and tubesheet, and (5) additional or reduced contact pressure associated with tubesheet bore dilation (distortion) caused by tubesheet bow (deflection) as a result of the primary to secondary pressure load acting on the tubesheet. Westinghouse employed a combination of pullout tests and analyses, including finite element analyses of the tubesheet, to evaluate these contributors. Based on these analyses and tests, Westinghouse initially concluded (licensees letter dated January 19, 2007, Attachment VI) that the required engagement distances to ensure the safety factor criteria against pullout vary from 4.78 to 8.34 inches depending on the radial location of the tube within the tube bundle, with the largest engagement distances needed toward the center of the bundle. Westinghouse refers to the required engagement distance as the H-star criterion.
In a letter dated March 13, 2007, the licensee provided revised analyses which, in part, address recent test results indicating that a fundamental assumption in the original analyses (i.e., the analyses provided with the January 19, 2007, letter) was not justified. Specifically, the original analysis assumed that for a throughwall flaw located 17 inches or more below the TTS, 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, throughwall 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 overly 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 the vertical deflection of the tubesheet. This case was analyzed in response to a staff request for additional information (NRC letter dated December 13, 2006, Agencywide Document Access and Management System accession number ML063400204) 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 ranges from 10.62 to 11.81 inches, compared to 4.78 to 8.34 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 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 13, 2007, the licensee reported that the net effect was to increase the required engagement distance at the limiting tube radial location from 11.81 inches to 13.6 inches, still well within the proposed 17-inch inspection zone.
The staff has not reviewed the Westinghouse analyses in detail and, thus, has not reached a conclusion with respect to whether 13.6 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 such as to ensure a minimum of 17 inches of effective engagement, well in excess of the 13.6 inches that the Westinghouse analyses indicate are needed. The staff 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 staff concludes that the applicability of the 17-inch inspection zone and associated repair criteria should only apply until the end of Operating Cycle 25. The technical bases (from a structural integrity standpoint) supporting the adequacy of the proposed 17-inch inspection zone and associated repair criteria for this limited time period are as follows:
Pullout tests of nine samples indicate that the radial contact pressure between the tube and tubesheet produced by the tube hydraulic expansion coupled with the contact pressure due to differential thermal expansion between the tube and tubesheet (due to a higher thermal expansion coefficient for the Alloy 600 TT tubing as compared to the A508 steel tubesheet) for joint temperatures ranging from room temperature to 600EF is such as to require an engagement distance of 1.1 to 4.8 inches to ensure the appropriate safety margins against pullout. This engagement range of 1.1 to 4.8 inches reflects very considerable scatter in the pullout data, but is well within the proposed 17-inch inspection zone.
The primary pressure inside the tube exceeds the average pressure outside the tube over the length of the tube-to-tubesheet crevice, thus acting to tighten the joint relative to unpressurized conditions under which the pullout tests were performed. (The pressure differential across the tube wall is reduced in the revised analyses (discussed above) relative to the original analysis, but remains positive when averaged over the 17-inch inspection zone.)
Tubesheet bore dilations caused by tubesheet bow under primary to secondary pressure differential can increase or decrease contact pressure depending on the tube location within the bundle and on location along the length of the tube in the tubesheet region. 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 TTS 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., 10.9 inches below the TTS), tubesheet bore dilation effects would be expected to further tighten the joint from 10.9 inches below the TTS to 17 inches below the TTS which would be the lower limit of the proposed tubesheet region inspection zone. Combined with the effects of the joint tightening associated with differential pressure across the tube wall, contact pressure over at least a 6.1-inch distance will be significantly higher than the contact pressure simulated in the above mentioned pull out tests. A similar logic applied to the periphery of the tubesheet leads the staff to conclude that at the top 10.9 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 staff concludes that the proposed 17-inch engagement distance (or inspection zone) is acceptable to ensure the structural integrity of the tubesheet joint.
3.2.2 Joint Leakage Integrity If no credit is to be taken for the presence of the tube-to-tubesheet weld, a potential leak path from the primary-to-secondary side is introduced between the hydraulically-expanded tubing and the tubesheet. In addition, not inspecting the tubing in the lower 4.81 inches of the tubesheet region may lead to an increased potential for 100 percent throughwall flaws in this zone and the potential for leakage of primary coolant through the crack and up between the hydraulically expanded tubes and tubesheet to the secondary system. Operational leakage integrity is assured by monitoring primary to secondary leakage relative to the applicable TS limiting condition for operation (LCO) limit. However, it must also be demonstrated that the proposed TS changes do not create the potential for leakage during DBAs which may exceed values assumed in the licensing basis accident analyses. The licensee states that this is ensured by limiting primary to secondary leakage to 0.3 gallons per minute (gpm) in the faulted SG during a MSLB.
To support its H-star 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 staff has not reviewed in detail or accepted this model. To support a temporary 17-inch inspection zone, Westinghouse cited a number of qualitative arguments supporting a conclusion that a minimum 17-inch engagement length ensures that leakage during MSLB will not exceed two times the observed leakage during normal operation.
Westinghouse refers to this as the bellwether approach. Thus, for a SG leaking at the TS LCO limit (i.e., 75 gallons per day (gpd)) under normal operating conditions, Westinghouse methodology would estimate that leakage would not be expected to exceed 0.1 gpm (150 gpd),
significantly less than the 0.3 gpm assumed in the licensing basis accident analyses for MSLB.
The factor of two upper bound is based on the Darcy equation for flow through a porous media where leakage rate would be proportional to differential pressure. Westinghouse considered normal operating pressure differentials between 1200 and 1400 psi and accident differential pressures on the order of 2560 to 2650 psi, essentially a factor of two difference. The factor of two 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 staff concurs that the factor of two upper bound is reasonable, given the stated premise. The staff notes that the assumed linear relationship between leak rate and differential pressure is conservative relative to alternative models such as the Bernoulli or orifice models which assume leak rate to be proportional to the square root of differential pressure.
The 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 staff in detail. Among the Westinghouse observations is that for all tubes, there is at least an 8-inch zone in the upper 17 inches of the tubesheet where there is an increase in joint contact pressure due to higher primary pressure inside the tube and changes in tubesheet bore dilation along the length of the tubes. The revised analyses described in the licensees letter dated March 13, 2007 (and discussed in Section 3.2.1 of this safety evaluation) do not affect this observation. In Section 3.2.1 above, the staff observed that there is at least a 6.1-inch zone where changes in tubesheet bore dilations 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 in the 6.1-inch zone under the increased pressure loading on the tubesheet during accident conditions.
Although joint contact pressures and leak flow resistance decrease over other portions of the tube length, Westinghouse expects a net increase in total leak flow resistance on the basis of its insights from leakage test data that leak flow resistance is more sensitive to changes in joint contact pressure as contact pressure increases due to the linear log normal nature of the relationship. The staffs depth of review did not permit it to credit this aspect of the Westinghouse assessment. However, the staff concludes from the above discussion that there should be no significant reduction in leakage flow resistance when going from normal operating to accident conditions.
Finally, the staff has considered that undetected cracks in the lower 4.81 inches are unlikely to produce leakage rates during normal operation that would approach the TS LCO operational leakage limits, thus providing additional confidence that such cracks will not result in leakage in excess of the values assumed in the accident analyses. Any axial cracks will be tightly clamped by the tubesheet, limiting the opening of the crack faces. In addition, little of the end cap pressure load should remain in the tube below 17 inches 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.
In summary the staff concludes that any primary to secondary leakage existing under normal full power operating conditions would not increase by more than a factor of two for DBAs such as a MSLB. Since operating leakage is limited by the LCO limit in TS Section 3.4.13 to 75 gpd, the maximum possible leakage from the lowermost 4.81 inches inside the tubesheet will not exceed 150 gpd during a MSLB.
It is the licensees responsibility to ensure the total accident-induced leakage for the entirety of the tubing (not just the 4.81-inch exclusion zone) is within the accident leakage performance criteria of TS Section 3.4.13. The proposed new reporting requirements in TS Section 5.6.8 will allow the staff to monitor potential accident leakage from the lowermost 4.81 inches of the tubesheet. As discussed above, the staff has concluded that accident leakage in the lowermost 4.81 inches of the tubesheet will not increase by more than a factor of two over the normal operating value in this region immediately prior to the accident. The proposed new reporting requirements will allow the staff to monitor how and on what basis the licensee is apportioning observed normal operating leakage between the lowermost 4.81 inches of the tubesheet and the rest of the SG for purposes of determining the potential accident leak rate contribution from the lowermost 4.81 inches of the tubesheet. The staff concludes the proposed new reporting requirements are acceptable.
3.3 Technical Evaluation Conclusion
The NRC staff concluded that the licensees proposed license amendment, which is applicable to RFO 24 and the subsequent operating cycle (Operating Cycle 25), is acceptable since the licensee will be able to maintain the structural and leakage integrity of the tube-to-tubesheet joint consistent with the design and licensing basis of the facility.
4.0 STATE CONSULTATION
In accordance with the Commission's regulations, the State of South Carolina 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 4300). 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: Leslie S. Miller Date: April 9, 2007
Mr. T. D. Walt H. B. Robinson Steam Electric Plant, Carolina Power & Light Company Unit No. 2 cc:
David T. Conley Associate General Counsel II - Legal Department Progress Energy Service Company, LLC Post Office Box 1551 Raleigh, North Carolina 27602-1551 Ms. Margaret A. Force Assistant Attorney General State of North Carolina Post Office Box 629 Raleigh, North Carolina 27602 U. S. Nuclear Regulatory Commission Resident Inspectors Office H. B. Robinson Steam Electric Plant 2112 Old Camden Road Hartsville, South Carolina 29550 Mr. Ernest J. Kapopoulos, Jr.
Plant General Manager H. B. Robinson Steam Electric Plant, Unit No. 2 Carolina Power & Light Company 3581 West Entrance Road Hartsville, South Carolina 29550 Mr. William G. Noll Director of Site Operations H. B. Robinson Steam Electric Plant, Unit No. 2 Carolina Power & Light Company 3581 West Entrance Road Hartsville, South Carolina 29550 Public Service Commission State of South Carolina Post Office Drawer 11649 Columbia, South Carolina 29211 J. F. Lucas Manager - Support Services - Nuclear H. B. Robinson Steam Electric Plant, Unit No. 2 Carolina Power & Light Company 3581 West Entrance Road Hartsville, South Carolina 29550 Mr. C. T. Baucom Supervisor, Licensing/Regulatory Programs H. B. Robinson Steam Electric Plant, Unit No. 2 Carolina Power & Light Company 3581 West Entrance Road Hartsville, South Carolina 29550 Ms. Beverly Hall, Section Chief N.C. Department of Environment and Natural Resources Division of Radiation Protection 3825 Barrett Dr.
Raleigh, North Carolina 27609-7721 Mr. Robert P. Gruber Executive Director Public Staff - NCUC 4326 Mail Service Center Raleigh, North Carolina 27699-4326 Mr. Henry H. Porter, Assistant Director South Carolina Department of Health Bureau of Land & Waste Management 2600 Bull Street Columbia, South Carolina 29201 Mr. J. Paul Fulford Manager, Performance Evaluation and Regulatory Affairs PEB 5 Carolina Power & Light Company Post Office Box 1551 Raleigh, North Carolina 27602-1551 Mr. John H. ONeill, Jr.
Shaw, Pittman, Potts, & Trowbridge 2300 N Street NW.
Washington, DC 20037-1128