ML092300090
| ML092300090 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 08/14/2009 |
| From: | Krich R Tennessee Valley Authority |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| TAC ME1343 | |
| Download: ML092300090 (11) | |
Text
Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402-2801 August 14, 2009 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001.
Sequoyah Nuclear Plant, Unit 2 Facility Operating License No. DPR-79 NRC Docket No. 50-328
Subject:
Response To Request For Additional Information Concerning -
Technical Specifications Change 09 W-STAR Alternate Repair Criteria For Steam Generator Tubes Cold Leg (TAC No. ME1343)
References:
Technical Specifications. (TS) Change 09 W* Alternate Repair Criteria (ARC) For Steam Generator (SG) Tubes Cold Leg," dated May 21, 2009
- 2. Letter from NRC to TVA, "Sequoyah Nuclear Plant, Unit 2 - Request for Additional Information Regarding The Proposal to Change the Scope of the Steam Generator Tube Inspections (TAC No. ME1343)," dated July 15, 2009 By letter dated July 15, 2009 (Ref. 1), Tennessee Valley Authority (TVA) submitted a license amendment application to NRC to revise the Sequoyah Nuclear Plant (SQN) Unit 2 Technical Specifications (TS) to allow the implementation of Steam Generator (SG) tubing alternate repair criteria for axial indications in the Westinghouse Electric Company explosive tube expansion (WEXTEX) region below the top of the tubesheet and specify the W-STAR distance for the SG cold legs. By letter dated July 15, 2009 (Ref. 2), the NRC requested additional information be submitted to support their review of the license amendment application. Enclosure 1 provides the TVA responses to the NRC requests for additional information provided in Reference 2.
TVA has determined that the additional information provided by this letter does not affect the no significant hazards considerations associated with the proposed TS changes. The proposed TS changes still qualify for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c)(9). contains the commitments reflected in the TVA responses to the NRC requests for additional information.
Printed on recycled paper
U.S. Nuclear Regulatory Commission Page 2 August 14, 2009 If you have any questions about this change, please contact Beth A. Wetzel at (423) 843-7170.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on the 14th day of August 2009.
Respectfully,
/74 R M Krich Vice President Nuclear Licensing
Enclosures:
Enclosure 1 - Response to NRC Request For Additional Information Concerning Technical Specifications Change 09 W-Star Alternate Repair Criteria For Steam Generator Tubes Cold Leg Enclosure 2 - TVA Commitments cc (Enclosures):
Regional Administrator - Region II NRC Senior Resident Inspector - Sequoyah Nuclear Plant Director, Division of Radiological Health - State of Tennessee
ENCLOSURE1 RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION CONCERNING TECHNICAL SPECIFICATIONS CHANGE 09 W-STAR ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBES COLD LEG NRC Question 1 Page E1-2 of the May 21, 2009, letter indicates that the inspection scope for refueling outage (RFO) 17 will be based on the results of the cold-leg sample inspection performed during RFO 16, and that if no degradationis reportedin RFO 16, no inspections will be performed during RFO 17. The Sequoyah 2 TSs are performance based specificationsthat require inspections to be performed with the objective of detecting flaws of any type that may be present and that may satisfy the applicable tube repaircriteria. Because a degradation assessment is requiredprior to each SG tube inspection and there could be additional operating experience that could influence the scope of inspections during RFO 17, please discuss your plans to base the scope of your RFO 17 inspection on the degradation assessment and your operationalassessment, which justifies the time interval between inspections.
TVA Response In accordance with TVA's Steam Generator Procedure, TVA will develop a degradation assessment that defines the eddy current inspection scope prior to RFO 17 based on the previous RFO 16 inspection results and any applicable industry operating experience.
Sequoyah Nuclear Plant (SQN) Unit 2 currently has the only operating original Model 51 Steam Generators (SGs) with Westinghouse Explosive Tube Expansion (WEXTEX); therefore, any additional industry operating experience influencing the conclusions of the degradation assessment with respect to eddy current inspection scope would not be expected.
NRC Question 2 Page A1-3 of the May 21, 2009, letterproposes a revision to TS 6.8.4.k.d.5 whereby 20 percent of the inservice tubes in the cold leg tubesheet region would be inspected. The current TSs are largely performance-basedand generally do not specify a sample size, except for alternate repaircriterionwhere the potential for cracking is known to exist and a 100 percent sample is specified. Please discuss your plans for removing the sampling strategy from your TSs since the sample size should be based on providing reasonableassurancethat tube integrity will be maintained.
TVA Response TVA has reviewed the Electric Power Research Institute (EPRI) SG degradation database and this review indicates that cracking at the cold leg top of tubesheet has not occurred in domestic Westinghouse Electric Company Model 51 SGs with WEXTEX expanded low temperature mill annealed tubing. Therefore, the potential for cold leg top of tube sheet cracking is not known to exist and a 20 percent sample instead of a 100 percent sample provides reasonable assurance that tube integrity will be maintained.
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LTR-SGMP-09-35-P (Reference 1) includes cold leg inspection history data for similar SGs. At Joseph M. Farley Nuclear Plant (Farley) on Unit 1 extensive cold leg top of tube sheet inspections on their original SGs was performed. At the last inspection before replacement of the SGs (16.38 effective full power years [EFPY]), over 1200 outside diameter stress corrosion cracking (ODSCC) indications and 241 primary water stress corrosion cracking (PWSCC) indications had been reported on the hot leg, with no stress corrosion cracking (SCC) reported on the cold leg. The time in the hot leg to 0.1 percent affected level (10 tubes total for all SGs) was 7.33 EFPY for both ODSCC and PWSCC. An empirical hot leg to cold leg improvement factor cannot be determined, but is no less than 16.38EFPY/7.33EFPY = 2.24. The initial reporting of ODSCC on the hot leg was 4.93 EFPY. Thus an improvement factor for the first initiation cannot be determined but is not less than 16.38EFPY/4.93EFPY = 3.32.
The first reliable ODSCC reporting for SQN Unit 2 is taken as 10.56 EFPY. Thus, applying the above data from Farley Unit 1 to SQN Unit 2, the first reporting of ODSCC on the cold leg would not be expected before 23.65 EFPY, using the most conservative empirical data.
As such, a 20 percent sample of the cold leg top of tubesheet region at End of Cycle (EOC) 16 (20 EFPY) is not expected to result in detection of ODSCC degradation. If no ODSCC indications are reported at EOC-16, none would then be expected at EOC-17 (approximately 21.4 EFPY).
For SQN Unit 2, the first hot leg PWSCC report was at 4.15 EFPY while the 0.1 percent affected level is 5.37 EFPY. The EOC-13q(.16.04 EFPY) cold leg sampling did not identify, indications. The only plant to have reported reliable cold leg PWSCC indications is at Farley; Unit 2 (original SGs). The Farley Unit 2 SGs used full depth roll expansion and include residual stress levels much higher than for WEXTEX expanded tubing used in the SQN Unit 2 SGs. For Farley Unit 2, an empirical hot leg to cold leg improvement factor of 3.5 is established for one SG; indications were never reported in the other two SGs. The Farley 2 data would then suggest that the 0.1 percent affected level for PWSCC would be expected at about 18.8 EFPY, assuming equal stress conditions. However, residual stress affects SCC initiation at the fourth power. For example, a difference of 5.0 ksi (5000 pounds per square inch) in residual stress would suggest an adjustment to the PWSCC initiation time of about 1.0/0.31, or about 3.16 times longer. If no cold leg PWSCC indications are observed at SQN Unit 2 EOC-16, then the relationship between stress level and initiation potential would be substantiated. As such, postulated cold leg PWSCC indications would not be expected at SQN Unit 2 EOC-1 7 (approximately 21.4 EFPY).
TVA acknowledges that W-STAR (W*) is an alternate repair criteria (ARC), but TVA application in the hot leg and the proposed application in the cold leg is to determine the length of expansion which must be examined to ensure tube integrity is maintained. Because cold leg top of tube sheet cracking has not been detected in domestic Westinghouse Model 51 SGs with WEXTEX expansions, the proposed 20 percent sample provides reasonable assurance that SG tube integrity will be maintained for SQN Unit 2 Cycle 16 and Cycle 17.
NRC Question 3 Page EI-2 of the May 21, 2009, letter indicates that a 20 percent sample of the cold-leg tubesheet region will be performed during the end-of-cycle (EOC) RFO 16 in the fall of 2009.
This is consistent with the proposed wording of TS 6.8.4.k.d.5. However, page EI-2 also indicates that if no flaws are found during the EOC RFO 16 inspection of the cold-leg tubesheet region, that no cold-leg inspections will be performed at EOC RFO 17 (spring 2011). These plans appearcontradictoryto the proposed wording in TS 6.8.4.k.d.5. Please clarify.
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TVA Response TVA will perform the 20 percent sample scope of inspection as defined in Technical Specification (TS) 6.8.4.k.d.5 each outage that the cold leg W* ARC is implemented.
NRC Question 4 Page EI-2 of the May 21, 2009, LAR indicates that if no primary waterstress corrosion cracking (PWSCC) indicationsare identified in the cold-leg top of tubesheet region (i.e., the upper 10.5 inches) that the leakage allowance for the operationalassessment will be considered to be zero gallons per minute. The technical basis for this assumption is not clear.
Operating experience at other plants indicates that cracking can occur near the tube end without observing cracking near the top of the tubesheet. In addition, it is known that cracking has the potentialto occur nearthe tube end at Sequoyah 2. Please discuss your plans for assessing leakage from the lower portion of the tubes within the tubesheet, regardless of the results of the inspection near the top of the tubesheet, which would be a methodology similarto what is applied to the hot-leg. In addition, given that a sampling strategy, ratherthan a 100 percent inspection, is performed in the inspected region of the tubesheet, the basis for not assuming any potential flaws in the uninspected tubes is not clear. Pleasediscuss your plans to account for the potential that there may be undetected flaws in the cold-leg in your assessment of leakage.
TVAResponse "
As discussed in LTR-SGMP 2 09-35-P (Reference 1), indications below the tubesheet neutral axis represent a negligible leakage potential because of the tightening of the tube-to-tubesheet joint as a result of tubesheet deflection (see LTR-SGMP-09-35-P Section 5.1 - 2nd paragraph, Section 5.2 - paragraphs: 1, 2, 3, and 9). The estimation of indication count in the 8 to 12 inch below top of tubesheet range for the hot leg is estimated from the indication counts above this region. Prior trending (Figure 5-2 of LTR-SGMP-09-35-P) shows that initiation potential is greatest for the first 1-inch distance below the top of tubesheet and rapidly decays with increasing distance below the top of tubesheet. If no indications are observed in the first 10.5-inch distance below the top of tubesheet for the cold leg, then it is a reasonable assumption that no degradation is present in the distance from 10.5 inches below the cold leg top of tubesheet and below. If a 20 percent sampling program is applied and no indications are detected, the discussion provided in the response to Question No. 2 will be confirmed that the 0.1 percent affected level would not be achieved before SG replacement; therefore, negligible leakage would be expected from the cold leg before the SGs are replaced in Cycle 18.
Additionally, if a flaw is detected in the cold leg sample, then 100 percent of that SG will be inspected, and if a flaw is identified in the expanded sample, 100 percent of the other SGs will be inspected.
With regard to the cracking potential below the top of tubesheet in SQN Unit 2, the EOC-1 5 indication was identified in a Row 1 tube at the cold leg tube end, which had been previously plugged using a roll plug, then deplugged using a relaxation process. Both the plug installation and plug removal operations introduce significant residual stresses to the SG tube. The only tubes in which tube plugs have been installed and removed are Row 1 tubes. Thus, the single EOC-1 5 identified condition does not have a technical basis to extend these results to the tubes outside of Row 1 because of the prior plugging and plug removal activities. In the event a postulated circumferentially separated tube occurred at a distance greater than 12 inches below the top of tube sheet on the cold leg, substantial contact pressure and crevice lengths would El -3
exist above this location, resulting in a negligible leakage condition (see LTR-SGMP-09-35-P Section 5.2 - paragraph 10).
Discussion of long-term sampling of the cold leg roll expanded region for another plant with Model 51 SGs and partial depth expansion is included in LTR-SGMP-09-35-P. This plant experience shows no expansion transition or tack roll region PWSCC degradation through 27.52 EFPY. The hot leg W* application assumes all tubes are flawed at greater than 12 inches below the top of tubesheet. The leakage allowance for this assumption is bounded by 0.3 gallon per minute (gpm). Figure 5-11 of LTR-SGMP-09-35-P presents an estimation of the number of tack roll indications that may be present in SQN Unit 2 at 20 EFPY of 0.1 percent, or about 14 indications. Thus, if all of these are assumed to contain a complete circumferential separation, the leakage allowance would be 0.3 gpm (0.1 percent/100 percent) or 0.0003 gpm, and can be neglected.
Additionally, circumferential PWSCC indications were reported at a plant with A600TT tubing on the cold leg side in 2007. These reported indications do not apply to Model 51 SGs WEXTEX expansions because a review of the specifics of these indications suggests that these reports may be false. First, the discussion of LTR-SGMP-09-35-P for the partial depth expanded tubes indicates that about 90 percent of the tack roll indications are axially oriented. For the A600TT plant, hot leg tack roll cracking is primarily axial degradation. Thus, the reporting of only circumferential PWSCC at the cold leg tack roll raises questions regarding the validity of these reports. Second, the reported cold leg flaw amplitudes are three times the hot leg flaw amplitudes, which are not supported by general corrosion theory. Two Westinghouse eddy.
current Level .111analysts reviewed these cold leg PWSCC reports from the A600TT plant.. Both concluded that the signals are most likely-.not attributed to SCC but to a geometry effect. Thus, it can be concluded that these cold leg PWSCC reports from the A600TT plant are most likely false reports.
Based on the above, TVA considers that cold leg leakage would be negligible. However, to conservatively account for the potential of undetected flaw leakage, the following will be performed. If cold leg indications are detected, then the hot leg leakage methodology as required by the Steam Generator Program will be applied to the cold leg (except 10 percent of the total cumulative quantity of indications in the cold leg region 0 to 10.5 inches below the top of tubesheet will be assumed in the cold leg region 10.5 to 12 inch below the top of tubesheet and multiplied by 0.0045 gpm). If cold leg indications are not detected (i.e., a 20 percent sample is performed), then in the faulted SG TVA will assume a total of four top of tubesheet indications exist in the nonexamined tubes, plus the inservice Row 1 tubes that have had plugs removed will be assumed to leak at 0.00009 gpm. TVA will revise the Steam Generator Program to require the assumed leakage.
NRC Question 5 For the cold-leg, please confirm thatyou will determine the number of indications between the W* distance (10.5 inches) and 12 inches below the top of the tubesheet, using the methodology discussed in Section 5.1.3 of Reference I based on the numberof indicationsfound (or postulated to be present if a sampling approachis used - refer to question 4), and that a minimum of 25 indications will be assumed, as discussed in section 5.1.4 of Reference 1.
TVA Response The 25 assumed indications mentioned in Section 5.1.4 of LTR-SGMP-09-35-P (Reference 1) are for the hot leg side, at the 8- to 12-inch elevation range. If a 20 percent sampling program is applied at EOC-16 to the cold leg and no indications are observed, then at the 95t percentile, E1-4
as many as 11 indications per SG could be present in the uninspected population in the cold leg top of tube sheet to 10.5 inches below top of tube sheet (TTS) range. However, if 11 indications per SG are assumed, then the probability of sampling one of these for all SGs is 99.99 percent, and the probability of expanding the inspection is high. Therefore, if no indications are observed, the number of postulated indications in the uninspected population can realistically be no more than 4 per SG (5 0th percentile estimate of indications in the uninspected population). LTR-SGMP-09-35-P includes discussion that another alternate repair criterion methodology has concluded that steam line break (SLB) condition leakage would not be more than twice the normal operating condition leakage for indications below the top of tubesheet. Therefore, if no leakage is detected during operation, then no leakage would be expected during a SLB. However, based on the other alternate repair criterion methodology, as much as twice the threshold of leakage detection, or about 2 gallons per day (gpd) (0.0014 gpm), could be assumed during a SLB.
If the inspection total sample is 20 percent (i.e., no expansion) and no indications are detected, TVA will assume 4 indications in the faulted SG cold leg 0- to 10.5-inch region plus all the inservice Row 1 tubes that have had plugs removed will be assumed to leak at 0.00009 gpm. If indications are detected then the quantity of indications and leakage will be determined similar to the hot leg method (except 10 percent of the total cumulative quantity of indications in the cold leg region 0 to 10.5 inches below the top of tubesheet will be assumed in the cold leg region 10.5 to 12 inch below the top of tubesheet).
NRC Question 6 In the May 21, 2009, letter it is stated that the proposal is conservative since it requires repairof any service induced degradationwithin the W* distance. The proposalmay be conservative; however, it is not clear that it is conservative for this reason alone. In the W* approach originally developed by the vendor, a flaw that was detected and not repairedwould generally require that additionaltubing be examined in order to ensure some minimum non-degraded length of tubing existed. As a result, please clarify the originalstatement.
TVA Response The conservative reference relates to the fact that TVA plugs on detection and the applied cold leg inspection distance is 10.5 inches below the top of tubesheet whereas the inspection distance established by WCAP-14797 (Reference 2) is less than 8 inches. In addition, indications that are identified within the 8 to 10.5 inch below top of tubesheet distance will be plugged, based on the TVA proposal. This ensures conservatism. Additionally, if a flaw is detected in the cold leg sample, then 100 percent of that SG will be inspected, and if a flaw is identified in the expanded sample, 100 percent of the other SGs will be inspected.
NRC Question 7 In Item 2 of the Significant Hazards Considerationon page El-10 of the May 21, 2009, letter,it is stated that, "...and allows axial cracks in the WEXTEX region to remain in service if prescribedcriteria are met. Removal of the existing PWSCC axial at dented tube support plate ARC [alternaterepaircriteria]incorporatesthe more conservative TS limit for SG tube plugging." This text does not appearto be applicable to this amendment. Please confirm that this text is not applicable to your request. If it is applicable,please clarify.
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TVA Response The text concerning PWSCC axial at dented tube support plate ARC is not applicable to this amendment and was erroneously included in the significant hazards evaluation provided in TS Change 09-02. The wording refers to language that was removed from the TS in a previous license amendment. As such, the existing significant hazards consideration evaluation bounds the changes requested in TS Change 09-02.
NRC Question 8 On page E1-3 of the May 21, 2009, letter, the proposed TS 6.8.4.k.c.2.c indicates that the W*
distance for the cold-leg tubesheet is 10.5 inches. Since the W* approachrelies on a minimum distance of non-degradedtubing below the bottom of the expansion transition,please either (a) confirm that the bottom of the cold-leg expansion transition for all tubes is below the TTS and that the bottom of the transitionis no more than 3 inches from the TTS, including uncertaintyin the measurement,or (b) discuss your plans to modify the definition of the W* distance for the cold-leg tubesheet region to ensure that 10.5 inches of non-degradedexpanded tubing exists below the TTS or the bottom of the expansion transition,whichever is lower.
TVA Response During future inspections, TVA will confirm that the bottom of the cold leg expansion transition for all tubes is below the top,of tube sheet and that the bottom of the transition is no more than 2.88 inches including uncertainty from the top of tubesheet. TVA performs a bobbin coil inspection of 100 percent of the tubing which identifies location accounting for any inspection uncertainties of any tube-to-tubesheet expansion feature including conditions such as over expansion above the top-of-tubesheet, bulges within the tubesheet, and unexpanded crevice depth below the top-of-tubesheet. In addition to the 20 percent planned cold leg W* scope, if bobbin coil defines other candidates with abnormal conditions then additional examinations will be added to the cold leg W* inspection scope.
TVA will revise the Steam Generator Program to confirm that the bottom of the cold leg expansion transition for all tubes is below the top of tubesheet and that the bottom of the transition is no more than 2.88 inches including uncertainty from the top of tubesheet.
NRC Question 9 There is extensive discussion regardingthe leak rate methodology. Please confirm that for the hot-leg tubesheet region you are not proposing any changes to the previously approved W*
leak rate methodology for determining the number of tubes with indications, as well as the leak rates assignedto those indications. Pleasealso confirm that you have been determining the number of potential indicationsin the region of the tube from 8 to 12 inches below the TTS on the hot-leg each outage, based on the inspection results.
TVA Response In accordance with TSs and W* program requirements, no changes have been made to the hot leg W* methodology for determining indication distribution or calculated leakage as a result of this cold leg W* proposal. The leak rate methodology discussion is unchanged for the hot leg W* application, and is only repeated to avoid having to refer to the previous 2004 license amendment request for the leakage bases. Additional discussion has been included that shows E1-6
the inherent conservatism of using a leakage methodology based solely on indication elevation and not a combination of elevation and contact pressure. Also, the number of potential indications in the region of the tube from 8 to 12 inches below the top of tubesheet on the hot leg has been increased based on inspection results.
NRC Question 10 Page 9 of Reference I refers to Np from equation (2) as "The normal force due to the resultant pressure in the tube." The term Np is then replacedby Fp in equation (3) and Pp in equation (4).
On page 10, however, Pp is referred to as the differentialpressure term (point4.) instead of the resultantpressure term (althoughit is obvious that the primary-to-secondarydifferential pressure does affect the resultantpressure). Additionally, point 4 on page 10 also indicates that the differential pressure term, Pp, used for the Sequoyah 2 analysisis less than the generic analysis and that this smaller differential pressure results in a specific Sequoyah 2 W* value that is less than the generic value. This statement is in contrast with informationpresented in Table 4-1 that shows Sequoyah 2 steam pressure, Ps, as smaller than the generic W* value, which results in a largerpressure tightening, Pp, term and therefore a smaller W* value. Please clarify.
TVA Response The statement in LTR-SGMP-09-35-P (Reference 1), page 10:
"4. The differentialpressure term, Pp,: is affected by changes in the primary or secondary pressure. The differentialpressure term used for the Sequoyah Unit 2 analysisis less than the generic analysis; therefore, the value of W* for use at Sequoyah Unit 2 should be less than the generic value."
Should be changed to:
- 4. The resultant pressure term, Pp, is affected by changes in the primary or secondary pressure. The secondary pressure used for the Sequoyah Unit 2 analysis is less than the generic analysis; therefore, the resultant pressure tightening is greater than the generic analysis and consequently the value of W* for use at Sequoyah Unit 2 should be less than the generic value.
This statement (item 4) as revised is consistent with the text in Section 4.2 of LTR-SGMP-09-35-P (Reference 1) repeated below:
"4.2 APPLICATION OF WCAP-14797-P, REV. 2, TO SEQUOYAH UNIT 2 The determinationof the non-degradedtube length considers the residualpreload capabilityof the tube expansion process, the thermal tightening effects because of thermal expansion coefficient differences between the tube and the tubesheet material,pressure tightening effects, and loss of preloaddue to tubesheet bow effects. The residualpreloadinherent in the expansion process is independent of differences between analysis and plant conditions. The generic analysis uses a cold leg temperature of 5250 F, whereas the currentSQN-2 cold leg operating temperature is approximately 544°F (Reference 4.1). Therefore, the generic analysis includes less thermal tightening contribution than the actual condition within the steam generators. The generic analysis uses a secondary side steam pressure of 900 psia for evaluation of pressure tightening effects whereas the current secondary side steam pressure is 834 psig (849 psia). This steam pressureresults in a smaller primary-to-secondarypressure E1-7
differential for the generic analysis condition compared to the SQN-2 condition. Therefore, the generic analysis considers about 5. 0 percent less pressure tightening contribution than the actual condition within the SQN-2 steam generators. The generic analyses uses a steam pressureof 760 psia (1490 psi differentialpressure across the tubesheet) for evaluation of end cap loading and tubesheet bow effects whereas the current SQN-2 differential pressure across the tubesheet is 1401 psi, thus the generic analysis is about 6.0 percent more conservative than the current SQN-2 conditions. Assumed normal operatingsteam pressure also influences the analysis with regard to defining the applied end cap load that acts to push the postulated separatedtube out of the tubesheet hole."
The statement (item 4 on page 10 of LTR-SGMP-09-35-P) as revised above is also consistent with Table 4-1, which lists the secondary side pressure for SQN Unit 2 as 849 pounds per square inch absolute and for the generic analyses as 900 pounds per square inch absolute.
References
- 1. LTR-SGMP-09-35 P-Attachment, "Application of W* Alternate Repair Criteria to Sequoyah Unit 2 Cold Leg Tubes (Proprietary)," Westinghouse Electric Company LLC, dated March 25, 2009.
- 2. WCAP-14797, Revision 2, "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," Westinghouse Electric Company, Madisons PA, Marchý.2003 (Proprietary).
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I I I ENCLOSURE 2 COMMITMENTS
- 1. TVA will revise the Steam Generator Program to confirm that the bottom of the cold leg expansion transition for all tubes is below the top of tubesheet and that the bottom of the transition is no more than 2.88 inches including uncertainty from the top of tubesheet.
- 2. TVA will revise the Steam Generator Program to require the assumed leakage as follows. If cold leg indications are not detected (i.e., a 20 percent sample is performed), then in the faulted SG TVA will assume a total of four top of tubesheet indications exist in the nonexamined tubes plus the inservice Row 1 tubes that have had plugs removed will be assumed to leak at 0.00009 gpm. Additionally, the total cumulative quantity of indications in the cold leg region 0 to 10.5 inches below the top of tubesheet will be assumed in the cold leg region 10.5 to 12 inch below the top of tubesheet and multiplied by 0.0045 gpm will be added.
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