3F0505-12, Revised Response to NRC Request for Additional Information Regarding Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13

Revised Response to NRC Request for Additional Information Regarding Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13

ML051520535
Person / Time
Site:	Crystal River
Issue date:	05/20/2005
From:	Annacone M Progress Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
3F0505-12
Download: ML051520535 (46)

Text

Progress Energy Crystal River Nuclear Plant Docket No. 50-302 Operating Ucense No. DPR-72 Ref: 10 CFR 50.36 May 20,2005 3F0505-12 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

Crystal River Unit 3 - Revised Response to NRC Request for Additional Information Regarding Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13

References:

1. NRC to PEF letter dated February 1, 2005, "Request for Additional Information Regarding Crystal River Unit 3 - Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13 (TAC NOS. MCI 176 and MC1853)"

2 PEF to NRC letter dated March 30, 2005, "Crystal River Unit 3 - Response to NRC Request for Additional Information Regarding Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13"

Dear Sir:

Florida Power Corporation, doing business as Progress Energy Florida, Inc. (PEF), is hereby providing a revised response to Reference 1, NRC Request for Additional Information (RAI).

The information provided herein, supersedes the March 30, 2005 submittal (Reference 2).

Crystal River Unit 3 (CR3) personnel discussed the need for a revised submittal with the NRC staff during a meeting held on April 26, 2005. Specifically, CR3 is deleting the information regarding a technique for predicting leakage attributed to Tube End Cracks during the next Refueling Outage (14R), which was previously contained in Question lb, Attachment A. CR3 also deleted the Background questions related to each of the February 1, 2005 RAI questions (Attachment A) and made minor editorial changes. Additions to the text of Attachment A are shown in Italics font. No changes were made to Attachment B.

Attachment C was changed to add a clarification. Additions to the text are shown in Italics font.

Attachment D has been added to provide the corrective actions established by CR3 to address exceeding the postulated Main Steam Line Break (MSLB) as-found primary to secondary leakage during Refueling Outage 13 (13R). The attachment also provides additional data informally requested by the NRC staff.

Progress Energy Florida, Inc.

Crystal River Nuclear Plant 15760 W. Powerline Street Crystal River, FL 34428

U. S. Nuclear Regulatory Commission Page 2 of 2 3F0505-12 This letter establishes no new regulatory commitments.

If you have any questions regarding this submittal, please contact Mr. Sid Powell, Supervisor, Licensing and Regulatory Programs at (352) 563-4883.

Sincerely, Micha J. Annacone Manager Engineering MJA/lvc Attachments:

A. Response to NRC Request for Additional Information Regarding Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13 B. Tubes with Tube End Cracks (TEC) Remaining In-Service (Without Repair)

C. Revision of Refueling Outage 12 (12R), MODE 4 Report, Table 3 -

D. CR3 Corrective Actions from 13R Discussed During the April 26, 2005 Meeting, and Supplemental Data Requested by the NRC staff xc: NRR Project Manager Regional Administrator, Region II Senior Resident Inspector

FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 ATTACHMENT A RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING ONCE-THROUGH STEAM GENERATOR TUBE INSERVICE INSPECTION CONDUCTED DURING REFUELING OUTAGE 13

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 1 of 19 FEBRUARY 1, 2005 - NRC RAI QUESTION 1 With respect to your accident induced leakage assessment, please provide the following a) a technical description of the methodology used to project the number and location (tubesheet radius) of tube-end-crack indications and the technical basis for this methodology (e.g., a benchmarking of this methodology based on previous inspection data). Include in this description, the actual values used.

b) the actual value of leakage from tube-end-crack indications based on the number of projected indications (from la above) and the existing NRC-approved leakage model.

c) a clarification of the number of tubes with tube-end-crack indications and the number of tube-end-crack indications. The staff notes that there appears to be a discrepancy in the reported number of tubes with tube-end-crack indications and the number of indications in both steam generators. For example, in steam generator A, 957 tubes were reported to have 1228 tube-end-crack indications in the October 31, 2003, letter; however, Appendix 5 to the January 27, 2004, letter indicates 1105 tubes in steam generator A contained tube end cracks. In addition, Table A-3 of the August 10, 2004, letter indicates 1119 tubes contained 1474 indications which does not appear (based on a cursory count) to match the number of tubes listed in Tables A-1 and A-2 (1099 tubes).

RESPONSE - la)

For the Refueling Outage 13 (13R) Operation Assessment Tube End Crack (TEC) leakage, Crystal River Unit 3 (CR3) used the methodology to project leakagefrom TEC as described in BAW-2346P, Alternate Repair Criteria for Tube End Cracking in the Tube-to-Tubesheet Roll Joint of Once-Through Steam Generators, Revision 0. The projected number of TEC for each radial zone was based on the number of as-found indications multiplied by the inverse of the probability of detection (POD) for Stress Corrosion Cracking (SCC) in the upper tube end. To account for cracks that were not detected during the inspection, which could potentially leak during accident conditions, during the next cycle of operation the frequency distribution of TEC is scaled upward by a factor of 1/POD (based on radius location found during the eddy-current inspections). The equation used is from section 10.0 of BAW-2346P:

NIradius = [(l/POD)(NAsFound)radius] - [(Nrepaired)radius(l)]

Where:

NMradius = estimated number of indications at given radius zone NAsFound)radius = number of indications actually detected at given radius zone Nrcpalrcd)radius = number of repaired indications at a given radius zone POD = probability of detection for TECs = 0.84 The actual values of 13R TEC indications are summarized in Tables 1 & 2 below:

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 2 of 19 TABLE 1- A-OTSG 13R TEC Indications Radial Zone Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Totals As-Found 450 423 273 173 58 97 1474 Indications As-Left 449 422 233 122 0 2 1228 Indications Repaired 1 1 40 51 58 95 246 Indications Projected Indications (POD 534.7 502.6 285.0 155.0 11.0 20.4 1509

& As-Left) I I I I I I TABLE 2 - B-OTSG 13R TEC Indications Radial Zone Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Totals As-Found 163 348 396 167 73 141 1288 Indications 1 As-Left 149 343 391 165 14 9 1071 Indications Repaired 14 5 5 2 59 132 217 Indications Projected Indications (POD 180.0 409.3 466.4 196.8 27.9 35.9 1316

& As-Left) I I I I To accountfor an increasein the TEC population, (more than those indications accountedfor in the POD), CR3 repairedadditionaltubes to reduce the as-left TEC calculatedleakage. Tie number of tubes repairedreduced the Refueling Outage 14 (14R) projected as-found TEC leakage value below the TEC leakage limit (0.856) by an amount approximately equivalent to the excess as-found 13R leakage value.

RESPONSE - lb)

The projected TEC leak rate from all zones for each OTSG is based oil the NRC approved plant specific TEC leak rate and corresponding radial zones for CR3 (See Table 3 below). These values are obtained from the most conservative leak rate table from Addendum A of BAW-2346P, Revision 0 (FPC to NRC letter, 3F0599-21, dated May 28, 1999).

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 3 of 19 TABLE 3 - CR3 TEC Leak Rate vs. Tubesheet Radius (faulted steam generator, plugged tube case)

CR-3 SLB Accident Condition Upper Tubesheet Lower Tubesheet Radial Zone Radius (inch) Leak Rate Radius (inch) Leak Rate (gpm) (gpm)

I > 3, < 39 7.1OE-5 > 3, < 42 7.1OE-5 2 > 39, <49 1.90E-4 > 42, < 49 1.90E-5 3 > 49, < 53 3.83E-4 > 49, < 53 3.83E-4 4 > 53, < 55 5.41E-4 > 53, < 55 5.41E-4 5 > 55, < 56 1.37E-3 > 55, < 56 1.37E-3 6 > 56 5.72E-3 > 56 5.72E-3 Radius - Location of tube center relative to the center of the tubesheet

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 4 of 19 The actual values used in the TEC leakage projections for the next cycle are based on the BAW-2346P method of using as-left leakage attributed to TEC and adding an additional amount for the POD. The leakage is calculated using the projected indications (as-left & POD) for the A and B-OTSGs from Tables 1 and 2 above.

The Topical Report BAW-2346P projected TEC leakage values for the current operating cycle are:

TABLE 4 - A-OTSG 13R TEC Projected Leakage Radial Zone Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Totals Projected Indications (POD 534.7 502.6 285.0 155.0 11.0 20.4 1509

& As-Left)

Leakage Value (gpm)per 7.10E-5 1.90E-4 3.83E-4 5.41E-4 1.37E-3 5.72E-3 N/A Indication from Table 3 As-Left Leakage 0.032 0.080 0.089 0.066 0.000 0.011 0.279 (gpm)

POD Leakage 0.006 0.015 0.020 0.018 0.015 0.106 0.180 (g p m )_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Projected Leakage 0.459 (POD & As- 0.038 0.095 0.109 0.084 0.015 0.117 Note 1 L eft)(gpm ) __ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _

• Note I - This is the Leakage value reported as the Projected Accident Leakage for TEC in the Mode 4 Report (CR3 to NRC letter, 3F1003-07, dated October 31, 2003).

TABLE 5 - B-OTSG 13R TEC Projected Leakage Radial Zone Zone I Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Totals Projected Indications (POD 180.0 409.3 466.4 196.8 27.9 35.9 1316

& As-Left)

Leakage Value (gpm)per 7.10E-5 1.90E-4 3.83E-4 5.41E-4 1.37E-3 5.72E-3 N/A Indication from Table 3 As-Left Leakage 0.011 0.065 0.150 0.089 0.019 0.051 0.385 (gpm)

POD Leakage 0.002 0.013 0.029 0.017 0.019 0.154 0.234 (g p m )__ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _

Projected Leakage 0.619 (POD & As- 0.013 0.078 0.179 0.106 0.038 0.205 Note 2 Left)(gpm ) .

. Note 2 - This is the Leakage value reported as the Projected Accident Leakage for TEC in the Mode 4 Report (CR3 to NRC letter, 3F1003-07, dated October 31, 2003).

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 5 of 19 Conclusion The projection of TECfor the next cycle was based on BAW-2346P. Additionally, CR3 repaired tubes with TEC to reduce the as-left leakage to accountfor a population increase in TEC. Tubes in the highest leakage value zone were repaired to minimize the recurrence of TEC in those zones. 77Te methodology to project tie number of indications was based on thie number of new TEC indications identified in 13R since ProgressEnergy personnelconsidered that there are too few datapoints to develop a meaningful historicaltrend. 7Te improvements in eddy currentdata analysis training in 13R gives confidence that CR3 identified TEC indicationsmore accuratelyin 13R than in past outages.

CR3 recognized that additional corrective actions had to be taken during the 13R outage as a result of finding the TEC postulated leakage higher than the allowable. Besides procedural and administrative changes to the OTSG inspection program, the physical changes to the plant include the re-rolling of additional tubes with TEC in both OTSGs to conservatively reduce the as-left leakage even further than the existing BAW-2346P criteria. Attachment D lists corrective actions establishedto prevent recurrence.

As part of the corrective actions, CR3 submitted License Amendment Request (LAR) #290, Revision 0, to the NRC on January 27, 2005. Approval has been requested prior to the next refueling outage for use in estimating leakage for the subsequent cycle. The LAR proposes to utilize a probabilistic methodology to determine the contribution to SLB leakage rates from TEC.

The proposed probabilistic method to estimate TEC leakage provides more accurate and realistic TEC leakage predictions while maintaining all other assumptions in BAW-2346P, Revision 0.

The methodology change for TEC leakage calculation proposed in LAR #290, Revision 0, utilizes the same probabilistic process approved by the NRC for use by plants implementing Generic Letter (GL) 95-05, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking." The predicted leakage from TEC indications found in 13R would not have exceeded predictions had the probabilistic method been employed.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 6 of 19 RESPONSE - 1c) Part 1 The CR3 October 31, 2003 letter to the NRC (3F1003-07) provided the number of axially orientated TEC indications left in-service after the 13R inspection outage in each steam generator. The reported population of tubes included tubes with TEC indications that were not removed from service by re-rolling or plugging. Those tubes left in service with TEC have a projected accident leakage value assigned to each indication. The number of as-left TEC tubes reported was:

OTSG TUBES INDICATIONS Location UTEILTE UTE/LTE A 953/4 1221/7 B 729/105 959/112 The tubes with TEC indications were also identified by upper tube end (UTE) or lower tube end (LTE) since this was the first occurrence of lower tube end cracking. For the A-OTSG, the total number of tubes with TEC indications per steam generator was the sum of the two (957) because there were no tubes with a TEC on both the upper and lower tube end of the same tube. For the B-OTSG, the total number of tubes with TEC indications per steam generator was not the sum of the two because there are some tubes with a TEC on both the upper and lower tube ends. The total of unique tubes for B-OTSG is 804 and tube ends is 834. In either case, when determining TEC leakage for each steam generator, a leakage value is assigned to each and every indication whether the TEC indications are on the upper or lower tube end.

Appendix 5 from the CR3 January 4, 2004 letter (3F0104-03) to the NRC provided tables of tubes in the A and B steam generators with TEC remaining in service after the 13R outage.

After a detailed comparison between the lists in the October 31, 2003 and January 4, 2004 letters, CR3 determined that the January 2004 list included some TEC tubes that are in-service, but had been re-rolled during the 13R outage. Therefore, while the list accurately represented in-service tubes with a TEC identified, the population of re-rolled tubes should not have been included in this list. Once a tube end is re-rolled, a TEC is no longer assigned a leakage value because the tube end is outside the new pressure boundary. The re-roll is assigned a different leakage value instead of the TEC leakage value. Pages 1 through 7 of Appendix 5 identify that 1105 tubes had TECs in the A-OTSG. When revised for repaired (re-rolled) tubes, the total agrees with the 957 (953+4) identified in the first table. Pages 8 through 13 of Appendix 5 identify that 972 tubes had TECs in the B-OTSG. When revised for repaired (re-rolled) tubes, the total also agrees with the 834 (729+105) total tube ends identified above. A revised Appendix 5, consistent with previous submittals, is included as Attachment B. This attachment provides an updated listing including a tube count column.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 7 of 19 RESPONSE - Ic) Part 2 Table A-3 from the August 10, 2004 letter (3F0804-04) to the NRC provided a summary of the A and B-OTSG as-found TEC indications. The totals from Table A-3 are summarized below:

OTSG A Tubes A Indications B Tubes B Indications Upper Tubesheet 1115 1467 908 1173 Lower Tubesheet 4 7 108 115 Totals 1119 1474 1016 1288 The above numbers of tubes and indications have been reviewed and determined to be accurate.

RAI question Ic questions whether the number of tubes listed in Tables A-I and A-2 agree with the totals above for A-OTSG. A review of the tube numbers from Table A-I (pages 2 thru 23 from the August 10, 2004 letter) identified a total of 1115 tubes with 1467 indications. A review of the tube numbers from Table A-2 (page 24) identified a total of 4 tubes with 7 indications.

The same review was performed for the tube numbers in the B-OTSG. A review of the tube numbers from Table B-1 (pages 25 thru 42) identified a total of 908 tubes with 1173 indications.

A review of the tube numbers from Table B-2 (pages 43 thru 45) identified a total of 108 tubes with 115 indications.

The CR3 review did not identify any discrepancies between the number of tubes/indications in the A-3 Summary Table and the corresponding detailed tables A-1, A-2, B-1, or B-2.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 8 of 19 FEBRUARY 1 2005 - NRC RAI QUESTION 2 In the November 24, 2004, response to RAI question 1.d, it was indicated that indications are classified as being attributed to wear based on bobbin coil data. These "wear indications" are then compared to previous inspection data to determine if there is a change in signal characteristics. Rotating probe examinations are then performed at these locations of "wear" if the indications are new, the bobbin signal characteristics have changed, or there is no previous rotating probe data. Given that crack indications have been found at locations also affected by wear, please provide the technical basis for this approach. This technical basis should include the following:

a) a description of the bobbin coil eddy current data parameters used to distinguish wear from other degradation mechanisms (including intergranular attack and cracking); In particular, discuss whether other degradation mechanisms (e.g., intergranular attack and cracking) may also pass the test for being called wear based on screening the bobbin data.

b) the data supporting these parameters for screening wear from other forms of degradation.

c) a description of the criteria used to determine if the bobbin signal characteristics have changed and the basis for this "change criteria." Please discuss whether operational data supports your screening criteria. For example, in the cases where cracking has been observed in wear scars, discuss whether the bobbin signals from these indications would have met your criteria for performing rotating probe examinations. If field wear scars with cracks would not have met your criteria for performing rotating probe examinations, discuss what corrective actions will be taken (including the basis for concluding that existing wear scars (with the potential for cracks being present) will have adequate integrity at the time of your next inspection).

RESPONSE - 2 Each tube in service is inspected with the bobbin coil from tube end-to-tube end. An indication, such as wear, intergranular attack (IGA), or stress corrosion cracking (SCC) is first identified as a non-quantifiable indication (NQI) with the bobbin coil and then re-evaluated with a rotating coil probe to characterize the indication. If the indication is characterized as wear from the rotating coil examination, it is sized with the qualified bobbin sizing technique and left in-service pending review for structural integrity. Historic wear indications previously evaluated with a rotating coil and characterized as wear (volumetric wall loss) with the bobbin signal characteristics having no notable change, have the percent through-wall dimension recorded using the bobbin data. Indications are compared to the earliest inspection data (typically data from three inspections) to determine if there is any change in signal characteristics. If an indication does not have previous bobbin data (new indication) or previous rotating coil data, the indications are marked for further evaluation (NQI) using a mid-frequency +Point probe and 0.115 RPC Coil. All indications identified as NQI are resolved prior to the close out of the inspection.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 9 of 19 The technical basis for not repeating the rotating coil exam on confirmed wear signals is based on observing no notable bobbin signal change and that the previous rotating coil examination did not identify a flaw, other than wear. Since there is no notable change in the bobbin signal, there is reasonable assurance that the tube condition has not changed and a rotating coil exam would repeat the finding from the previous confirmation examination.

At a minimum, a notable change is characterized as a change in the phase angle of -10% or a change in the signal voltage of -0.5V or 25% of the previously recorded voltage. However, an absolute criterion for signal change is not always applicable and therefore a smaller amount of change may prompt a rotating coil exam at the discretion of the Eddy Current Qualified Data Analyst (QDA). For example, if the analyst determines that the formation of the lissajous for a specific indication is different than that of the previous data, but the phase angle and voltage are the same as the previous data, the QDAs are expected to mark the indication for further evaluation (NQI) using a mid-frequency +Point probe and 0.115 RPC.

To date, there have been no indications of wear that have had other degradation [such as Outside Diameter Stress Corrosion Cracking (ODSCC)] associated with the wear scar. In general, other degradation such as ODSCC has not occurred at broached support wear scars anywhere within the OTSG fleet. At CR3, a sample of tubes with previous wear have been examined with rotating coil during the past two inspections, Refueling Outages 12 and 13 (12R) and (13R), to confirm no change in the bobbin coil wear signal characterization.

From discussions with steam generator program representatives from other utilities with non-OTSG design steam generators, there has been no other degradation such as ODSCC that has "grown out of" support wear scars. It should also be understood that the prevalent source of ODSCC in the free span of OTSGs is "groove IGA" which develops from scratches in the tubes from tube manufacturing. In other steam generator designs, such as the Combustion Engineering (CE) design utilizing "eggcrate" lattice structures, ODSCC develops from corrosion within the crevice created at the support structure.

IGA and SCC bobbin signals are included for the Site Specific Performance Demonstration (SSPD) test that each QDA (primary, secondary, resolution, independent, and utility QDAs) must successfully complete prior to analyzing data at CR3. During the site familiarization training, the QDAs are provided examples of graphics of bobbin signals for IGA and SSC and expectations for identifying indications for further review.

The technical basis for the bobbin technique used at CR3 is based on the Electric Power Research Institute (EPRI) qualified techniques for wear, impingement, IGA, and stress corrosion cracking detection (SCC). EPRI Specific Technique Sheet (ETSS) 96007.1 and 96008.1 for IGA and SCC respectively are the basis for the CR3 ETSS bobbin coil examination technique. The EPRI qualifications were evaluated for application to the OTSG tubes at CR3 and determined that the essential variables are equivalent and applicable to CR3, including the data sample set.

[Framatome Document 51-5005589-02]. Additionally, the qualification probability of detection for intergranular attack and stress corrosion cracking detection was determined using pulled tube data from OTSG tubes, including tubes from CR3 [B&WOG Documents 77-1258722-00, "Probability of Detection of Defects in Once-Through Steam Generators" and 77-5002925-05, "Probability of Detection of Defects in Once-Through Steam Generators" (2002 Project Supplement)].

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 10 of 19 Inspection Results Cracking in a wear scar has not been specifically observed at CR3 as an active degradation mechanism. During 12R (fall 2001), 109 wear indications in the A-OTSG and 503 indications in B-OTSG were inspected using the rotating coil and no flaws, other than wear, were identified.

During the bobbin examination, 222 indications were identified as NQI, using the screening criteria described above, in A-OTSG, of which 47 indications were near a tube support plate (TSP) or upper tube sheet secondary face (+/-1.0 inch from the TSP centerline) where a wear signal is expected to appear. Two of the 47 indications were evaluated as unacceptable, volumetric IGA or SCC indications, and were removed from service (one indication was evaluated as a single circumferential crack, not associated with a wear indication). In B-OTSG, 101 indications were near a TSP or upper tube sheet secondary face (+/-1.0 inch from the TSP centerline) where a wear signal is expected to appear. Two of the 101 indications were evaluated as volumetric indications (IGA) and were removed from service.

During 13R (fall 2003), 281 wear indications in the A-OTSG were inspected using the rotating coil. One indication in A-OTSG, tube 143-3, had a flaw other than wear and was removed from service. The indication was identified during the bobbin exam and indicated as a NQI and was further evaluated with RPC and confirmed to have a volumetric indication (IGA). In B-OTSG, 323 wear indications were inspected using the rotating coil. No flaws, other than wear, were identified. During the bobbin examination, 188 indications were identified as NQI using the screening criteria described above in A-OTSG, of which 21 indications were near a TSP or upper tubesheet secondary face (+/-1.0 inch from the TSP centerline). Three indications were evaluated as IGA and were removed from service. In B-OTSG, 9 indications were near a TSP or upper tube sheet secondary face (+/-1.0 inch from the TSP centerline) where a wear signal is expected to appear. No indications were identified or confirmed as a flaw. This specific data demonstrates that CR3 applies a conservative threshold for evaluating wear indications for further characterization based on the small percentage of wear NQIs that actually have additional degradation. No corrective actions are considered necessary since the operational data shows that unacceptable flaws near the TSP would be detected.

Conclusion Bobbin indications of wear in the 2003 inspection were evaluated and compared for change based on available historical data for that indication. If there was previous rotating coil data AND there was no significant change in the bobbin signal based on available historical data, the bobbin indication was assigned a through-wall dimension. Over the past several cycles there have been hundreds of bobbin NQI indications reported, and all NQI indications are characterized with a rotating coil. Within these examinations are many support structures, of which all that have been inspected show no evidence of other degradation associated with wear scars.

The standard industry practice is to use the bobbin coil to screen the OTSG tubes for indications potentially associated with SCC and perform a follow-up inspection with a rotating coil. The bobbin technique was able to detect IGA and SCC near the TSP as detailed above. Therefore, the qualification for detection of flaws and operational data provides reasonable assurance that unacceptable flaws near the TSP (wear) would be detected for further evaluation using the bobbin coil technique.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 11 of 19 CR3 reviewed NRC Information Notice (IN) 03-05, Failure to Detect Freespan Cracks in PWR Steam Generator Tubes. As identified in IN 03-05, the industry practice is to use the bobbin coil technique to screen for indications potentially associated with SCC and then further characterize the indication with rotating coil techniques. The proposed actions in the IN were to evaluate the reporting criteria for bobbin flaws to ensure that potential flaws are further evaluated with the appropriate technique. During the review of IN 03-05, the CR3 data analyst guidelines were reviewed to ensure they included the minimum expectation to report any change in the bobbin signal from all available previous data. The qualified data analysts at CR3 are required to pass the site-specific performance demonstration test, which includes bobbin indications where flaws were later confirmed, with a rotating coil. The analysis process at CR3 is an independent review of all of the data by primary analysts and secondary analysts. If an indication is called by one group and not the other, two resolution analysts (Level III QDAs) evaluate the indications to determine the appropriate action, keep the indication for further evaluation or determine the indication is non-relevant. The indications are then reviewed by an Independent QDA or Utility QDA for concurrence on the final disposition. This rigor in data analysis provides reasonable assurance that unacceptable flaws will be identified and appropriately dispositioned within the industry guidelines.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 12 of 19 FEBRUARY 1, 2005 - RAI QUESTION 3 In the November 24, 2004, response to RAI question 2b, it was indicated that the difference between certain inspection numbers was due to the sleeves installed in the steam generators.

In response to question lb, it was indicated that 163 sleeves were installed in each steam generator at the start of the 2003 outage. Clarify the difference between the inspection numbers for steam generator B which is 159 rather than 163 (as it is for steam generator A).

RESPONSE - 3 There were 163 Alloy 690 sleeves originally installed in 1994 in both A and B-OTSG. One sleeved tube was removed from service from B-OTSG during the 1997 inspection due to an outside diameter indication in the non-sleeved region of the tube. Three sleeved tubes were removed from service in B-OTSG during the 1999 inspection due to indications in the parent tube.

Therefore, at the beginning of the fall 2003 inspection, there were 163 sleeves in-service in A-OTSG and 159 sleeves in-service in B-OTSG.

In the 2003 outage, four sleeved tubes in A-OTSG were removed from service because the eddy current probes could not traverse the sleeve upper end. Also in the 2003 outage, three sleeved tubes in B-OTSG were removed from service preventatively to address tube end degradation and operating experience recommendations from the Three Mile Island tube sever issue. At the conclusion of the fall 2003 inspection, there were 159 sleeves in-service in A-OTSG and 156 sleeves in-service in B-OTSG.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 13 of 19 FEBRUARY 1, 2005 - NRC RAI QUESTION 4 In the November 24, 2004, response to RAI question 3, the size of indications with the largest voltages was provided. Given that the largest voltage indication may not always correspond to the most severe indication (in terms of structural and leakage integrity),

confirm that, in this case, the largest voltage indications were the most severe indications detected. In the future it would be beneficial to delineate the location of each imperfection based on whether the indications are in the original roll transition, the original roll expanded region (other than the transition and the tube end), the re-roll upper or lower roll transition, the re-roll expanded region, the unexpanded portion of tube in the tubesheet region (not between re-rolls), the free span portion of the tube (outside the tubesheet) etc.

In addition, it would be beneficial to specify the number of re-rolls (if any) were in the tube at the time of the inspection if the imperfections are in the tubesheet region.

RESPONSE - 4 The response to RAI question 3 from the November 24, 2004 letter provided a table of the eddy current indications that identified the largest signal voltage for a given type of Non-destructive Examination (NDE) indication. This table provided a list of many of the largest percent through-wall indications found during the inspection. The response also provided a separate list of indications in each OTSG excluding indications near the cladding, first span intergranular attack and wear. However, not all of the largest voltage indications are the most severe when compared to a condition monitoring assessment for structural and leakage evaluation. As requested, the most limiting indications based on the structural and leakage assessment are identified in the table and Figures 1 and 2 below. Where a given type of NDE indication is not represented in the table, it is because that type of indication was not considered the most limiting based on the structural and leakage assessment. To provide additional flaw information, the locations of the imperfections are identified by OTSG landmark.

The choice of the largest indications for the A-OTSG and B-OTSG is from the 13R Condition Monitoring (CM) assessment. For condition monitoring, degradation dimensions are inferred from NDE measurements. Therefore, the condition monitoring limit curves in Figures 1 & 2 include NDE sizing uncertainties as well as material property variation and burst pressure calculation uncertainties. NDE readings which plot under the Condition Monitoring Limit curve demonstrate at least a 0.95 probability at 50% confidence that the burst pressure meets or exceeds a value of 3 Delta P. Indications with NDE measured lengths and depths at or below the Condition Monitoring Limit curve meet the required deterministic structural performance criteria for minimum degraded tube burst pressure. Each of the indications was compared to the CM criteria which are established for CR3. The leakage assessment for these indications was also acceptable.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 14 of 19 13R Largest Indications For Structural and Leakage Integrity Type of Passed Condition OTSG & Tube Degradation & LDo in OTS -ELength Monitoring for Number Indication (inches) & Depth Structural &

Code - Leakage Integrity?

Multiple Axial A2-26 Crack 15S - 7.30 inch 3.8 YES Indications (Freespan) 25% TW (MAI)

Single Axial 15S - 5.73 inch 4.0 A2-26 CrackYE Indication (SAT) (Freespan) 34% TW YES Single Axial 15S - 3.28 inch 0.31 A2-26 Crack resa)3%TYE Indication (SAT) (repa)3%T Single A13-67 Volumetric 15S + 0.03 inch 0.62 x 0.22 YES Indication (Within 15'h TSP) 16% TW (SVI)

Single Volumetric UTS -0.21 inch 0.21 x 0.14 A7750 Indication (Secondary face of 27% TW YES (SVI) Upper Tubesheet)

Single A103Volumetric 15S - 0.22 inch 0.18 x 0.17YE A103Indication (W~ithin 1511h TSP) 23% TWYE

__ _ _ _ __ _ _ _ _ _(S V I)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

A143-3 Volumetric 15S + 0.73 inch 0.44 x 0.22 YES Indication (SVI) (Top of 15h TSP) 48% TW Single Axial 15S -5.09 inch 0.39 B6-6 Indication (SAI) (Freespan) 43% TW YES Volumnetric LTS + 0.00 inch 0.38 x 0.23 B46-2 Indication (SVI) (Top of Lower 57% Te B114-1 Axial Crack 15S - 1.62 inch 0.53 YES Indication (SAI) (Freespan) 42% TW I TSP Tube Support Plate TW Through-Wall

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 15 of 19 Condition Monitoring Plot Axial ODSCCIIGA at 3 Delta P, S/G's A and B 100 90 80 70 60 I-0 50 "C

w 40 a

z 30 20 10 0

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 NDE Length of Degradation, inches lFigure 1

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 16 of 19 Condition Monitoring Plot Volumetric Degradation at 3 Delta P, SIG's A and B inn I I 90 -

- CM Line 80 -

• S/G A o S/G B I I.

70 -

60 - II 3 B46-2 I j

------__,--v t C.) 50 -

0.6 To ' A143-3 l ~ ~ ~ -__

I----------

CL 40 -

z 30 - I-- - ----- I a A77-50 & I.I AI 10-3 20 - r--I-------- I 0: A13-67 l t ---------- _ I 10- ... , . - .1 l I 0 -

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 NDE Length of Degradation, inches lFigure2l

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 17 of 19 February 1. 2005 - NRC RAI Ouestion 5 In the November 24, 2004, response to RAI question 5, you indicated that the obstructed sleeves were attributed to tube/sleeve end damage from previous loose parts and no indications were identified in the portion of the sleeve and tube examined. Please discuss the following with respect to this finding:

a) State whether the loose part was identified and removed from the steam generator (presumably from the primary side of the steam generator). Discuss the source of the part. If a part was not identified, discuss the basis for concluding the damage was from a loose part.

b) Discuss the location of the obstruction (i.e., the portion of tube/sleeve extending above the upper tubesheet). If the obstruction was located in the portion of tube/sleeve within the tubesheet (including the clad), discuss how the part caused the obstruction.

c) Given that the upper sleeve joint is a mechanical joint, discuss how you confirmed that the obstruction did not result in a weakening of the joint (i.e., pulling of the sleeve away from the parent tube) such that the sleeve could not meet its original design criteria.

Provide the extent of the obstruction and the technical basis for your conclusion.

d) Although no rejectable flaw-like signals were identified during the inspection of the portion of the sleeve that could be inspected, discuss whether an obstruction in another sleeved tube could have weakened the joint such that the sleeve could no longer meet its original design criteria.

RESPONSE - 5a)

Loose parts on the primary side of the OTSG are typically identified visually before the eddy current inspection begins and then using the eddy current tool camera. There was not a specific loose part removed from the upper tubesheet area of the A-OTSG in the 2003 inspection.

However, the A-OTSG tubes have had significant tube end (upper 0.125 inch) damage from loose parts in previous cycles. The source of loose parts was foreign material (section of Unistrut and related fasteners) in the Reactor Coolant System after Refueling Outage 8. During 13R, the decision was made to plug the sleeved tubes even though no defects were identified, instead of delaying the outage by several shifts waiting for the tube-end repair tool to arrive on site.

RESPONSE - 5b)

The damage was at the tube end and the bobbin coil probe could not completely traverse the sleeved tube end that extends above the tubesheet. The roll joints in the tube were inspected from the cold leg (lower tube end) and did not reveal any flaws in the sleeve or parent tube.

RESPONSE - Sc)

Visual inspection of the sleeve ends showed that the ends were not pulled away from the parent tube and the sleeve opening was essentially round indicating only minor impacts from above.

The sleeve end was only slightly deformed to the point where the eddy current probe could not

U. S. Nuclear Regulatory Commission Attachment A 3FO505-12 Page 18 of 19 enter and traverse the sleeve. For example, there were several other sleeves that originally could not pass a probe (NDE Code OBS) which later had the sleeve ends opened using a tube end repair tool. Once the tube ends were opened, every sleeve was inspected and no defects were identified in any sleeve or rolled joint. These four sleeves/tubes were only plugged because the original tube-end repair tool had to be replaced and a new tool was not available in a timely manner. In addition, the original sleeve qualification testing (BAW-2120P, Steam Generator Tube Sleeving) included axial load cycling in excess of the possible impact loading from loose parts. The qualification testing results, along with the minimal damage to the sleeve end, was the technical basis for determining the sleeve and rolled joints were still acceptable.

RESPONSE - 5d)

As explained in response 5a), the obstruction was tube end damage and not foreign material.

The tubes and upper sleeve ends extend above the tubesheet approximately 0.187 inch. The upper sleeve rolled joint is centered approximately 1.375 inch below the tube end. Therefore, sleeve end damage is not expected to weaken the joint such that the sleeve could no longer meet its original design criteria. A drawing of a typical sleeve is attached.

U. S. Nuclear Regulatory Commission Attachment A 3F0505-12 Page 19 of 19 Cross Sectional View of an OTSG Tubing Sleeve at Crvstal River Unit 3 Area where sleeve end damage occurred @ upper 0.125 inch l

S"l

FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 ATTACHMENT B TUBES WITH TUBE END CRACKS (TEC) REMAINING IN-SERVICE (Without Repair)

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 1 of 13 A-OTSG TUE ROW, TUBE TUBE TUBE LROW TUBE-, COUNT ROW TUBE

'COUNT COUNT 1 5 21 52 16 46 105 21 76 2 5 23 53 16 48 106 21 77 3 5 24 54 16 58 107 21 81 4 5 32 55 16 70 108 21 83 5 5 33 56 16 73 109 21 85 6 6 25 57 17 38 110 22 8 7 6 27 58 17 41 III 22 33 8 6 30 59 17 57 112 22 52 9 6 34 60 17 70 113 22 63 10 6 36 61 17 71 114 22 65 11 7 30 62 17 72 115 22 66 12 8 26 63 17 73 116 22 72 13 8 30 64 17 74 117 22 74 1 5 21 65 17 75 118 22 76 2 5 23 66 17 78 119 22 78 14 9 54 67 18 16 120 22 82 15 10 30 68 18 50 121 22 85 16 10 49 69 18 59 122 22 86 17 10 56 70 18 60 123 22 89 18 11 39 71 18 70 124 23 50 19 11 57 72 18 72 125 23 65 20 11 59 73 18 74 126 23 69 21 12 45 74 18 75 127 23 76 22 12 .53 75 18 76 128 23 77 23 12 65 76 18 78 129 23 78 24 13 35 77 19 59 130 23 79 25 13 37 78 19 62 131 23 80 26 13 39 79 19 69 132 23 81 27 13 42 80 19 72 133 23 85 28 13 47 81 19 73 134 23 86 29 13 48 82 19 74 135 23 89 30 13 53 83 19 75 136 24 24 31 13 54 84 19 76 137 24 53 32 13 55 85 19 77 138 24 55 33 13 56 86 20 39 139 24 66 34 13 68 87 20 40 140 24 68 35 14 45 88 20 41 141 24 69 36 14 46 89 20 42 142 24 77 37 14 47 90 20 59 143 24 79 38 14 54 91 20 66 144 24 80 39 14 55 92 20 68 145 24 83 40 14 66 93 20 75 146 24 84 41 14 67 94 20 76 147 24 86 42 14 69 95 20 77 148 24 90 43 14 70 96 20 79 149 25 13 44 15 39 97 20 85 150 25 55 45 15 40 98 21 38 151 25 59 46 15 44 99 21 61 152 25 66 47 15 46 100 21 62 153 25 67 48 15 67 101 21 64 154 25 78 49 15 68 102 21 73 155 25 79 50 16 40 103 21 74 156 25 80 51 16 42 104 21 75 157 25 81

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 2 of 13 A-OTSG TUBE C~UUbr. RO ROW IIJBE -TUBE .

TUBE TUBE COUNT ROW-. TUBE COUNT. TB COUNT ROW 158 25 85 211 30 33 264 35 60 159 25 88 212 30 49 265 35 61 160 25 89 213 30 51 266 35 73 161 25 90 214 30 55 267 35 74 162 26 43 215 30 57 268 35 82 163 26 46 216 30 59 269 35 90 164 26 50 217 30 70 270 35 95 165 26 55 218 30 71 271 35 96 166 26 68 219 30 72 272 35 99 167 26 79 220 30 82 273 36 76 168 26 81 221 30 84 274 36 78 169 26 82 222 30 89 275 36 86 170 26 85 223 30 90 276 36 91 171 26 86 224 30 95 277 36 95 172 26 87 225 30 96 278 36 97 173 26 88 226 31 9 279 36 98 174 26 90 227 31 40 280 36 99 175 26 93 228 31 43 281 36 100 176 27 56 229 31 69 282 36 103 177 27 57 230 31 71 283 36 104 178 27 60 231 31 86 284 36 105 179 27 66 232 31 95 285 36 106 180 27 78 233 31 96 286 36 107 181 27 79 234 32 16 287 36 109 182 27 82 235 32 37 288 37 61 183 27 83 236 32 48 289 37 76 184 27 84 237 32 56 290 37 83 185 27 86 238 32 58 291 37 88 186 27 87 239 32 59 292 37 89 187 27 88 240 32 63 293 37 94 188 27 90 241 32 72 294 37 97 189 27 93 242 32 83 295 37 98 190 28 47 243 32 86 296 37 99 191 28 59 244 32 90 297 37 100 192 28 61 245 32 91 298 37 103 193 28 67 246 32 94 299 37 106 194 28 70 247 32 96 300 37 109 195 28 75 248 32 97 301 37 110 196 28 79 249 32 101 302 38 63 197 28 80 250 33 15 303 38 77 198 28 83 251 33 51 304 38 84 199 28 88 252 33 65 305 38 87 200 28 89 253 33 93 306 38 95 201 28 91 254 33 97 307 38 96 202 29 50 255 33 100 308 38 98 203 29 54 256 34 59 309 38 99 204 29 58 257 34 83 310 38 100 205 29 83 258 34 90 311 38 101 206 29 93 259 34 93 312 38 104 207 29 94 260 34 95 313 38 105 208 29 95 261 34 96 314 38 109 209 29 97 262 34 98 315 38 111 210 30 13 263 34 99 316 38 115

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 3 of 13 A-OTSG TUBE' ROW TUBE ROW TUBE TUBE lw TB CO~nr .ROW COUNT :TlTJBE TB COUNT___ COUNT ROW TUBE 317 39 36 370 42 114 423 45 108 318 39 64 371 43 56 424 45 109 319 39 71 372 43 61 425 45 112 320 39 76 373 43 62 426 45 114 321 39 78 374 43 80 427 45 117 322 39 89 375 43 83 428 46 60 323 39 90 376 43 88 429 46 66 324 39 91 377 43 90 430 46 69 325 39 99 378 43 91 431 46 76 326 39 100 379 43 92 432 46 77 327 39 101 380 43 93 433 46 86 328 39 103 381 43 96 434 46 87 329 39 104 382 43 98 435 46 88 330 39 111 383 43 99 436 46 96 331 40 15 384 43 100 437 46 103 332 40 16 385 43 101 438 46 109 333 40 58 386 43 107 439 46 113 334 40 77 387 43 109 440 47 12 335 40 88 388 43 112 441 47 62 336 40 94 389 43 114 442 47 78 337 40 99 390 43 115 443 47 88 338 40 100 391 44 60 444 47 92 339 40 101 392 44 62 445 47 93 340 40 111 393 44 65 446 47 94 341 40 112 394 44 89 447 47 98 342 40 113 395 44 91 448 47 101 343 41 53 396 44 93 449 47 104 344 41 60 397 44 94 450 47 105 345 41 73 398 44 97 451 47 107 346 41 77 399 44 100 452 47 117 347 41 89 400 44 101 453 47 119 348 41 90 401 44 102 454 48 61 349 41 91 402 44 103 455 48 63 350 41 95 403 44 105 456 48 69 351 41 96 404 44 106 457 48 74 352 41 98 405 44 107 458 48 90 353 41 99 406 44 109 459 48 91 354 41 101 407 44 110 460 48 99 355 41 103 408 44 114 461 48 110 356 41 104 409 45 66 462 48 112 357 41 108 410 45 88 463 48 118 358 41 111 411 45 90 464 49 51 359 41 112 412 45 91 465 49 63 360 42 15 413 45 92 466 49 82 361 42 69 414 45 93 467 49 88 362 42 90 415 45 97 468 49 95 363 42 97 416 45 98 469 49 99 364 42 101 417 45 99 470 49 100 365 42 102 418 45 102 471 49 104 366 42 103 419 45 103 472 49 106 367 42 104 420 45 104 473 49 110 368 42 105 421 45 106 474 49 111 369 42 107 422 45 107 475 50 58

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 4 of 13 A-OTSG TUBE TUBE ROW TUBE TUE lROW -TUBE COUNTE ROW: TUBE COUNT*

iCOUNT ___

476 50 88 529 56 57 582 65 49 477 50 99 530 56 80 583 65 56 478 50 110 531 56 108 584 65 59 479 50 111 532 56 118 585 65 101 480 50 112 533 57 5 586 66 60 481 50 115 534 57 7 587 66 62 482 50 116 535 57 85 588 66 63 483 50 119 536 57 87 589 66 79 484 51 24 537 57 96 590 66 95 485 51 57 538 57 97 591 66 97 486 51 59 539 57 112 592 66 98 487 51 76 540 57 113 593 66 102 488 51 93 541 57 124 594 66 103 489 51 94 542 58 7 595 66 109 490 51 95 543 58 28 596 67 20 491 51 97 544 58 62 597 67 50 492 51 103 545 58 74 598 67 54 493 51 107 546 58 85 599 67 78 494 51 108 547 58 110 600 67 92 495 51 110 548 58 111 601 67 97 496 51 111 549 58 122 602 67 101 497 51 115 550 58 123 603 67 102 498 51 116 551 59 19 604 67 103 499 51 118 552 59 48 605 68 51 500 51 120 553 59 87 606 68 97 501 51 121 554 59 94 607 69 55 502 52 59 555 59 97 608 69 58 503 52 62 556 59 100 609 69 60 504 52 64 557 59 105 610 69 62 505 52 91 558 59 109 611 69 66 506 52 101 559 59 120 612 69 70 507 52 107 560 59 121 613 69 71 508 52 115 561 60 65 614 69 74 509 52 117 562 60 91 615 69 93 510 52 120 563 60 96 616 69 103 511 53 108 564 60 97 617 70 50 512 53 115 565 60 110 618 70 51 513 53 116 566 60 115 619 70 55 514 53 117 567 60 118 620 70 57 515 53 120 568 61 16 621 70 113 516 53 121 569 61 54 622 71 51 517 53 122 570 61 62 623 71 60 518 53 123 571 61 64 624 71 64 519 54 49 572 61 81 625 71 91 520 54 92 573 61 89 626 72 18 521 54 101 574 62 69 627 72 49 522 54 109 575 62 94 628 72 50 523 54 113 576 62 109 629 .72 51 524 55 10 577 63 62 630 72 52 525 55 77 578 63 100 631 72 57 526 55 83 579 64 94 632 72 62 527 55 96 580 64 103 633 72 94 528 55 110 581 65 24 634 73 24

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 5 of 13 A-OTSG TUBE. O Tt ' TUBE,,

OUNTU ROW TUBE COUNT -ROW TBE COUNT ROW TUBE 635 73 26 688 82 60 741 94 123 636 73 47 689 82 63 742 94 125 637 73 53 690 83 10 743 95 66 638 73 54 691 83 49 744 95 69 639 73 55 692 83 50 745 95 74 640 73 60 693 84 52 746 95 82 641 73 64 694 84 73 747 95 110 642 74 46 695 85 4 748 95 112 643 74 49 696 85 6 749 95 117 644 74 57 697 85 8 750 95 119 645 74 62 698 85 45 751 96 56 646 74 64 699 85 47 752 96 64 647 74 74 700 85 48 753 96 109 648 75 61 701 85 86 754 96 115 649 75 63 702 86 9 755 96 116 650 75 84 703 86 71 756 97 62 651 75 89 704 86 72 757 97 66 652 78 30 705 86 73 758 97 72 653 78 36 706 86 75 759 97 99 654 78 57 707 87 62 760 97 109 655 78 67 708 87 70 761 97 113 656 79 18 709 88 66 762 97 114 657 79 29 710 89 79 763 97 116 658 79 56 711 90 46 764 97 117 659 79 63 712 90 59 765 97 122 660 79 64 713 91 65 766 98 60 661 79 66 714 91 70 767 98 64 662 79 70 715 91 72 768 98 66 663 79 71 716 91 82 769 98 85 664 79 79 717 91 83 770 98 94 665 79 85 718 91 84 771 98 114 666 79 92 719 91 85 772 98 115 667 80 8 720 91 87 773 98 118 668 80 9 721 91 109 774 98 120 669 80 13 722 92 61 775 98 122 670 80 58 723 92 67 776 98 123 671 80 62 724 92 80 777 99 72 672 80 64 725 92 114 778 99 78 673 80 65 726 92 122 779 99 81 674 80 66 727 92 123 780 99 97 675 80 67 728 93 92 781 99 110 676 81 8 729 93 107 782 99 115 677 81 20 730 93 108 783 99 116 678 81 38 731 93 111 784 99 122 679 81 48 732 93 116 785 99 123 680 81 64 733 93 117 786 100 9 681 81 67 734 93 121 787 100 64 682 81 70 735 94 73 788 100 65 683 81 73 736 94 97 789 100 74 684 81 102 737 94 98 790 100 77 685 82 8 738 94 113 791 100 78 686 82 10 739 94 118 792 100 80 687 82 59 740 94 122 793 100 96

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 6 of 13 A-OTSG TUBE CTOUET ROW' TUBE TUBE ROW TUBE TouBE ROW TUBE -COUNT~

794 100 108 847 110 102 900 126 28 795 100 109 848 111 97 901 126 72 796 100 110 849 111 99 902 126 74 797 100 114 850 111 101 903 126 80 798 100 117 851 112 6 904 126 87 799 100 121 852 112 42 905 126 94 800 101 96 853 112 90 906 127 14 801 101 101 854 112 95 907 127 81 802 101 109 855 112 99 908 127 92 803 101 112 856 112 104 909 128 80 804 101 114 857 112 112 910 128 89 805 101 115 858 113 107 911 128 90 806 101 120 859 113 111 912 129 34 807 101 121 860 114 85 913 129 69 808 102 70 861 114 90 914 129 80 809 102 82 862 114 99 915 129 90 810 102 114 863 114 104 916 130 88 811 102 115 864 114 105 917 131 19 812 102 120 865 114 106 918 132 17 813 103 102 866 114 108 919 132 73 814 103 107 867 114 109 920 133 5 815 103 112 868 114 110 921 133 42 816 103 113 869 114 111 922 133 51 817 104 82 870 115 76 923 133 59 818 104 101 871 115 102 924 133 61 819 104 105 872 115 109 925 134 11 820 105 64 873 116 88 926 134 14 821 105 114 874 116 92 927 134 59 822 105 115 875 116 99 928 134 60 823 106 53 876 116 101 929 134 71 824 106 91 877 116 105 930 134 80 825 106 98 878 116 106 931 135 56 826 106 101 879 116 108 932 137 7 827 106 108 880 116 109 933 137 11 828 107 93 881 117 96 934 137 49 829 107 103 882 118 96 935 137 55 830 107 104 883 120 72 936 137 73 831 107 107 884 120 73 937 139 38 832 107 108 885 120 79 938 139 45 833 107 109 886 121 69 939 139 56 834 107 112 887 121 71 940 139 57 835 107 115 888 121 73 941 139 58 836 107 116 889' 121 83 942 139 66 837 108 48 890 121 96 943 140 9 838 108 93 891 121 98 944 140 58 839 108 111 892 122 71 945 140 60 840 108 112 893 122 79 946 140 65 841 108 113 894 122 80 947 141 53 842 109 6 895 122 99 948 141 54 843 109 25 896 123 80 949 141 55 844 109 68 897 124 78 950 141 56 845 109 102 898 124 96 951 141 58 846 110 98 899 125 95 952 142 30

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 7 of 13 A-OTSG l

l TUBE ROW TUBEU ROW . TUUB T ROW TUBE 953 142 50 955 144 25 957 145 43 954 143 53 956 144 46 I

U. S. Nuclear Regulatory Commission Attachment B 3F0305-03 Page 8 of 13 B-OTSG TUBE- ROW TUBE TUBE ROW 'TUBE CoUrB ROW TUiBE COUNT___

1 4 25 53 17 15 105 29 7 2 6 12 54 17 22 106 29 7 3 6 34 55 17 25 107 29 94 4 7 20 56 17 26 108 29 96 5 7 34 57 17 43 109 29 97 6 7 44 58 17 76 110 30 8 7 7 47 59 18 12 III 30 8 8 8 11 60 18 14 112 30 9 9 8 12 61 18 16 113 30 12 10 8 23 62 19 6 114 30 12 11 9 12 63 19 12 115 30 97 12 9 15 64 19 18 116 31 8 13 9 18 65 19 47 117 31 9 14 9 48 66 19 60 118 31 9 15 10 15 67 20 31 119 31 18 16 10 19 68 20 55 120 31 88 17 10 34 69 21 20 121 31 97 18 10 49 70 21 27 122 31 99 19 10 52 71 21 50 123 32 9 20 11 9 72 22 12 124 32 12 21 11 11 73 22 16 125 32 13 22 11 12 74 22 28 126 32 14 23 11 20 75 22 64 127 32 38 24 11 21 76 22 79 128 32 53 25 11 23 77 23 16 129 32 102 26 11 51 78 23 21 130 33 5 27 12 16 79 23 23 131 33 9 28 12 29 80 24 19 132 33 13 29 12 36 81 24 33 133 33 15 30 12 55 82 24 84 134 33 23 31 13 19 83 25 5 135 33 26 32 13 20 84 25 5 136 34 23 33 13 56 85 25 11 137 34 27 34 14 19 86 25 24 138 34 28 35 14 20 87 25 28 139 34 39 36 14 30 88 25 29 140 34 56 37 14 66 89 25 58 141 35 6 38 15 8 90 26 93 142 35 11 39 15 13 91 26 94 143 35 61 40 15 16 92 27 6 144 35 104 41 15 19 93 27 10 145 35 106 42 15 21 94 27 19 146 36 102 43 15 35 95 27 85 147 36 104 44 15 45 96 27 95 148 36 105 45 15 49 97 28 4 149 36 107 46 15 58 98 28 6 150 37 7 47 16 11 99 28 7 151 37 12 48 16 20 100 28 30 152 37 103 49 16 24 101 28 66 153 38 13 50 16 25 102 28 83 154 38 104 51 17 10 103 28 95 155 38 111 52 17 13 104 28 97 156 39 11

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 9 of 13 B-OTSG TUBE TUBE TUBE TROW TUBE COuNT ROW TUBE COUNT' ROW TUBE COUNT.___

157 39 27 210 49 62 263 58 17 158 39 31 211 50 6 264 58 114 159 39 70 212 50 113 265 58 117 160 39 86 213 50 115 266 58 119 161 39 108 214 50 115 267 58 120 162 40 15 215 50 120 268 59 38 163 41 38 216 50 122 269 59 113 164 41 46 217 51 112 270 59 117 165 41 102 218 51 116 271 59 121 166 41 111 219 51 117 272 59 122 167 41 113 220 51 117 273 60 26 168 42 13 221 51 119 274 60 116 169 42 31 222 51 120 275 60 122 170 42 54 223 51 122 276 60 126 171 42 63 224 52 7 277 60 127 172 42 106 225 52 13 278 61 121 173 42 111 226 52 30 279 61 123 174 43 14 227 52 53 280 62 34 175 43 28 228 52 110 281 62 123 176 43 47 229 52 111 282 63 26 177 43 107 230 52 114 283 63 37 178 43 108 231 52 116 284 63 121 179 43 110 232 52 120 285 64 27 180 43 111 233 53 5 286 65 69 181 44 7 234 53 119 287 65 121 182 44 12 235 53 120 288 66 4 183 44 14 236 54 6 289 66 9 184 44 29 237 54 16 290 66 10 185 44 32 238 54 108 291 66 16 186 44 109 239 54 114 292 66 50 187 45 8 240 54 115 293 66 111 188 45 15 241 55 4 294 66 120 189 45 29 242 55 25 295 67 52 190 45 32 243 55 47 296 68 26 191 45 85 244 55 115 297 69 10 192 46 6 245 55 121 298 69 22 193 46 14 246 55 122 299 69 54 194 46 15 247 55 123 300 69 107 195 46 16 248 55 123 301 70 50 196 47 14 249 56 5 302 71 4 197 47 25 250 56 5 303 71 42 198 47 33 251 56 17 304 71 43 199 48 14 252 56 26 305 71 51 200 48 31 253 56 53 306 71 67 201 48 34 254 56 55 307 72 39 202 48 50 255 56 118 308 72 105 203 48 62 256 56 121 309 72 122 204 49 9 257 57 5 310 73 77 205 49 16 258 57 13 311 73 104 206 49 17 259 57 16 312 74 40 207 49 23 260 57 71 313 74 108 208 49 58 261 57 122 314 75 53 209 49 59 262 57 125 315 75 57

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 10 of 13 B-OTSG TUBE ROW -TUBE C TUB lROW TUBE . 7UBE TUBE COUNT - CONT -ROW COUNT___

316 75 61 369 98 7 422 115 40 317 78 34 370 98 48 423 115 43 318 78 50 371 98 123 424 116 9 319 78 57 372 98 124 425 116 27 320 79 67 373 99 2 426 116 92 321 80 111 374 99 5 427 117 18 322 81 85 375 99 5 428 117 25 323 82 8 376 99 6 429 117 26 324 82 50 377 99 6 430 117 73 325 83 126 378 99 20 431 117 77 326 84 9 379 99 124 432 117 87 327 84 54 380 100 5 433 117 88 328 84 59 381 100 12 434 117 89 329 85 9 382 100 31 435 117 102 330 85 41 383 101 4 436 117 103 331 85 53 384 101 9 437 118 17 332 85 58 385 102 5 438 119 26 333 85 86 386 102 106 439 119 32 334 86 8 387 103 4 440 119 33 335 86 13 388 103 5 441 119 40 336 86 55 389 103 31 442 119 87 337 86 60 390 104 5 443 119 88 338 87 7 391 104 18 444 120 8 339 87 107 392 105 3 445 120 13 340 88 9 393 105 4 446 120 26 341 88 49 394 105 4 447 120 30 342 89 7 395 106 9 448 120 36 343 89 7 396 106 10 449 120 65 344 89 8 397 107 2 450 120 100 345 89 9 398 107 3 451 121 18 346 89 21 399 107 10 452 121 23 347 89 41 400 107 104 453 121 25 348 90 7 401 108 10 454 121 26 349 90 8 402 109 1 455 121 28 350 90 11 403 109 13 456 121 31 351 90 13 404 110 2 457 121 38 352 90 20 405 110 30 458 121 87 353 92 7 406 110 34 459 121 89 354 92 8 407 111 12 460 122 5 355 92 21 408 111 18 461 122 12 356 92 24 409 III 64 462 122 17 357 92 126 410 112 1 463 122 26 358 93 6 411 112 2 464 122 29 359 93 7 412 112 13 465 122 32 360 93 7 413 113 31 466 122 36 361 93 20 414 114 12 467 122 38 362 93 30 415 114 17 468 122 57 363 94 21 416 114 101 469 122 61 364 94 29 417 115 7 470 122 76 365 97 7 418 115 8 471 122 87 366 97 8 419 115 12 472 122 88 367 97 122 420 115 27 473 122 89 368 98 6 421 115 32 474 123 6

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 11 of 13 B-OTSG TUBE TUBE TUBE CUT ROW TUBE - com- ROW' TUBE' COUNT ROW: TUBE 475 123 6 528 128 9 581 131 63 476 123 10 529 128 10 582 131 68 477 123 11 530 128 12 583 131 74 478 123 17 531 128 17 584 131 77 479 123 18 532 128 18 585 131 78 480 123 22 533 128 19 586 131 84 481 123 28 534 128 23 587 132 9 482 123 30 535 128 24 588 132 13 483 123 37 536 128 37 589 132 14 484 123 74 537 128 69 590 132 23 485 124 16 538 128 78 591 132 26 486 124 26 539 128 81 592 132 28 487 124 29 540 128 84 593 132 29 488 124 98 541 129 6 594 132 30 489 125 4 542 129 10 595 132 33 490 125 6 543 129 12 596 132 46 491 125 11 544 129 20 597 132 55 492 125 19 545 129 23 598 132 61 493 125 23 546 129 27 599 132 71 494 125 29 547 129 29 600 132 73 495 125 39 548 129 68 601 133 8 496 125 69 549 129 70 602 133 9 497 125 73 550 129 76 603 133 12 498 125 82 551 129 77 604 133 13 499 125 83 552 129 79 605 133 14 500 125 95 553 129 80 606 133 15 -N 501 126 10 554 130 5 607 133 16 502 126 25 555 130 9 608 133 16 503 126 26 556 130 10 609 133 20 504 126 30 557 130 22 610 133 29 505 126 31 558 130 23 611 133 44 506 126 62 559 130 27 612 133 47 507 126 63 560 130 28 613 133 66 508 126 70 561 130 31 614 133 72 509 126 71 562 130 36 615 133 74 510 126 72 563 130 40 616 133 75 511 126 79 564 130 74 617 133 75 512 126 83 565 130 78 618 133 76 513 127 10 566 130 79 619 134 7 514 127 15 567 131 7 620 134 15 515 127 19 568 131 11 621 134 16 516 127 24 569 131 14 622 134 16 517 127 34 570 131 16 623 134 18 518 127 37 571 131 18 624 134 20 519 127 62 572 131 20 625 134 22 520 127 63 573 131 21 626 134 22 521 127 75 574 131 22 627 134 25 522 127 80 575 131 23 628 134 28 523 127 83 576 131 25 629 134 32 524 127 85 577 131 30 630 134 40 525 127 89 578 131 35 631 134 53 526 128 6 579 131 45 632 134 65 527 128 8 580 131 58 633 134 72

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 12 of 13 B-OTSG TUBE CUBE -ROW TUBE COUNT ROW -TUBE, TUBE COUNT.___ ROW TUBE COUNT 634 134 73 687 138 9 740 140 47 635 134 74 688 138 10 741 140 48 636 135 12 689 138 11 742 140 56 637 135 13 690 138 13 743 140 60 638 135 14 691 138 14 744 140 63 639 135 15 692 138 14 745 141 7 640 135 16 693 138 16 746 141 7 641 135 23 694 138 17 747 141 9 642 135 26 695 138 21 748 141 9 643 135 27 696 138 23 749 141 10 644 135 33 697 138 25 750 141 14 645 135 53 698 138 30 751 141 17 646 135 59 699 138 31 752 141 18 647 135 69 700 138 37 753 141 18 648 135 70 701 138 38 754 141 19 649 135 72 702 138 63 755 141 19 650 136 4 703 138 69 756 141 27 651 136 8 704 138 70 757 141 33 652 136 14 705 139 7 758 141 34 653 136 19 706 139 10 759 141 35 654 136 21 707 139 12 760 141 36 655 136 27 708 139 12 761 141 40 656 136 27 709 139 13 762 141 49 657 136 40 710 139 14 763 142 12 658 136 46 711 139 16 764 142 16 659 136 56 712 139 17 765 142 17 660 136 61 713 139 18 766 142 17 661 136 65 714 139 22 767 142 18 662 136 70 715 139 26 768 142 21 663 136 71 716 139 27 769 142 26 664 136 72 717 139 30 770 142 27 665 136 74 718 139 37 771 142 32 666 136 75 719 139 41 772 142 33 667 137 8 720 139 43 773 142 34 668 137 9 721 139 48 774 142 45 669 137 10 722 139 50 775 142 47 670 137 11 723 139 64 776 142 49 671 137 14 724 140 7 777 143 7 672 137 17 725 140 9 778 143 11 673 137 17 726 140 10 779 143 12 674 137 18 727 140 11 780 143 13 675 137 24 728 140 12 781 143 14 676 137 25 729 140 15 782 143 15 677 137 28 730 140 16 783 143 16 678 137 29 731 140 18 784 143 18 679 137 39 732 140 19 785 143 20 680 137 40 733 140 20 786 143 21 681 137 66 734 140 20 787 143 24 682 137 67 735 140 22 788 143 25 683 137 68 736 140 23 789 143 30 684 137 69 737 140 24 790 143 32 685 138 6 738 140 33 791 143 41 686 138 9 739 140 36 792 143 42

U. S. Nuclear Regulatory Commission Attachment B 3F0505-12 Page 13 of 13 B-OTSG TUBE -ROW TUBE

-COUNT___

793 143 44 794 143 46 795 143 47 796 144 11 797 144 12 798 144 13 799 144 14 800 144 15 801 144 18 802 144 22 803 144 23 804 144 26 805 144 27 806 144 42 807 144 43 808 145 8 809 145 10 810 145 12 811 145 17 812 145 19 813 145 21 814 145 25 815 145 26 816 145 28 817 145 38 818 145 43 819 146 12 820 146 14 821 146 18 822 146 23 823 146 26 824 146 29 825 146 30 826 147 10 827 147 13 828 147 16 829 147 21 830 147 23 831 147 33 832 148 15 833 148 17 834 148 25

FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 ATTACHMENT C REVISION OF REFUELING OUTAGE 12 (12R),

MODE 4 REPORT, TABLE 3

U. S. Nuclear Regulatory Commission Attachment C 3F0505-12 Page 1 of 1 Table 3 numbers below are from the Refueling Outage 12 (12R) MODE 4 Report (Table 3 of letter 3F1001-03, dated October 19, 2001). It was not known at the time, but the numbers in that document were based on a non-conservative TEC leak rate table used for determining total leakage. It was not until after the 13R inspection and the preparation of the revised TEC calculation that this discrepancy was identified. Using the corrected leak rates in the revised 12R TEC calculation allows for a better comparison with Refueling Outage 13 (13R) as-found leakage. Below, CR3 is providing Table 3 with the previous non-conservative information and the revised Table 3. The information in the revised Table 3 supersedes the Table 3 provided in the 12R MODE 4 Report.

Any under-prediction calculated using the 13R accident leakage tables (letter 3F1003-07, dated October 31, 2003) should use the upper tubesheet leakage rate from 13R because the lower tube end leakage could not have been predicted.

Table 3 provided in the MODE 4 Report of 12R:

Table 3 Cycle 13 Projected Accident Leakage (MSLB) for TECs Projected Accident Leakage Leakage Leakage Contribution at Contribution at Total Leakage at OTSG Room Temperature Room Temperature Room Temperature From In-Service from Undetected for Accident TEC Assuming 100% TW Conditions 100% TW Indications Based on 100%

TWPOD of 0.84 A 0.564 gpm 0.109 0.673 gpm B 0.556 gpm 0.154 0.710 gpm Revised Table 3 of 12R MODE 4 Report:

Revised Table 3: Cycle 13 Projected Accident Leakage (MSLB) for TECs Projected Accident Leaka e Leakage Leakage Contribution at Roomtemperonatur Total Leakage at OTSG Room Temperature Room Temperature Room Temperature From In-Service from Undetected for Accident TEC Assuming 100% TW Conditions 100% TW Indications Based on 100%

TWPOD of 0.84 A 0.626 gpm 0.120 0.746 gpm B 0.625 gpm 0.169 0.794 gpm

FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 ATTACHMENT D CR3 CORRECTIVE ACTIONS FROM 13R DISCUSSED DURING THE APRIL 26, 2005 MEETING, AND SUPPLEMENTAL DATA REQUESTED BY THE NRC STAFF

U. S. Nuclear Regulatory Commission Attachment D 3F0505-12 Page 1 of 7 Corrective Actions

1. Revised the Once-Through Steam Generator (OTSG) Program Manual. The changes included:

a. Added information related to use of the appropriate Tube End Crack (TEC) leak rate table.

b. Added guidance to ensure accounting of new TEC beyond Probability of Detection (POD).

c. Added a requirement for vendor notification for use of correct leak rate table prior to the outage.

2. Revised the OTSG Inspection Procedure. The changes included:

a. Added signature confirmation that the correct leak rate table was utilized.

b. Ensured Refueling Outage 13 (13R) leakage assessment used the correct leak rate table.

Added requirement to evaluate the need for repairs made to account for rate of new TEC found in the current outage.

c. Repaired TEC in 13R to gain margin for Refueling Outage 14 (14R).

d. Revised Refueling Outage 12 (12R) TEC calculation to correct errors.

3. Will re-evaluate the method to account for rate of new TEC for Refueling 15 (15R) projection. The projection will be based upon:

a. Refueling Outage 14R as-found data as compared to previous outage trends. A more precise prediction can be made with multiple data points.

b. Lessons learned from NRC Requests for Additional Information (RAls).

c. The status of License Amendment Request #290, Revision 0, "Probabilistic Methodology to Determine the Contribution to Main Steam Line Break Leakage Rates for the Once-Through Steam Generator from the Tube End Crack Alternate Repair Criteria."

4. CR3 will establish a requirement for the Plant Nuclear Safety Committee approval of the methodology utilized for projecting the next operating cycles Main Steam Line Break (MSLB) leakage value and the basis for projecting TEC values beyond the Probability of Detection (POD) amount, and the as-left results for the upcoming operating cycle.

5. CR3 will perform a review of RAIs from recent submittals to identify process improvements. CR3 recognizes that more early face-to-face communications will be required when addressing complex issues.

U. S. Nuclear Regulatory Commission Attachment D 3F0505-12 Page 2 of 7 APRIL 8,2005, NRC RAT OUESTION - a) a) A justification for reducing the expected number of indications in the lower tubesheet by a factor of 15. Since a similar reduction factor could have been applied following the initial detection of indications in the upper tubesheet, discuss whether such a reduction was actually observed in the upper tubesheet.

RESPONSE - a)

This question addresses information provided in the response to Question lb), Attachment A, Reference 1, that has been deleted from the response provided in this letter. The deleted information addressed a technique for predicting leakage attributed to Tube End Cracks for the next Refueling Outage (14R). The deleted information was not used during the 13R OTSG inspection and will not be used during the 14R inspection. Thus, Question a) above is no longer applicable.

APRIL 8,2005, NRC RAI QUESTION - b) b) A justification for reducing the number of indications expected to find in zone 6 given that some of the zone 6 tubes were plugged or repaired. This justification should include the following: i) the number of non-repaired or non-plugged tubes in each zone since IOR (i.e.,

the number of tubes in which tube end cracks (TECs) could initiate and contribute to leakage), ii) the number of actual TEC indications (tubes) detected in each zone since 1 IR, iii) the number of projected TEC indication in each zone since 1IR, iv) the number of as-left TEC indications (tubes) since IIR, v) the number of new TEC indications (tubes) found in each zone since 1 IR, vi) the average number of TEC indications per tube per zone since IIR, vii) the percentage of tubes that developed new TECs since 1 IR.

RESPONSE - b First Part)

This question addresses information from the response to Question lb), Attachment A, Reference 1, that has been deleted from the response. The deleted information addressed a technique for predicting leakage attributed to Tube End Cracks for the next Refueling Outage (14R). The deleted information was not used during the 13R OTSG inspection and will not be used during the 14R inspection. Thus, the first part of Question b) is no longer applicable.

U. S. Nuclear Regulatory Commission Attachment D 3F0505-12 Page 3 of 7 RESPONSE - b.i)

Prior to 2003, the lower tube ends were not inspected for TEC and no indications were identified.

Therefore, the data for 1997, 1999, and 2001 only have TEC information for the upper tube end.

All data prior to 13R (2003) is from the Upper Tube End.

CR3 Non-Repaired (Plugged or Re-rolled) Tubes at the End of an Outage OTSG/Zone Mid-Cycle (1997) 11R (1999) 12R (2001) 13R(2003) 13R (2003).

Upper Tube End Upper Tube Upper Tube Upper Tube End Lower Tube End End End -

A-Zone 1 7071 6790 6768 6747 7017 A-Zone 2 4065 3960 3950 3944 - 4058 A-Zone 3 1905 1860 1856 1836 1902 A-Zone 4 1021 1007 1001 969 977 A-Zone 5 505 500 499 421 . 414 A-Zone 6 813 580 559 470 . 737 B-Zone 1 6600 6081 5965 5918 6522 B-Zone 2 4078 3880 3834 3797 . 4066 B-Zone 3 1894 1851 1832 1822 1884 B-Zone 4 1015 1001 988 984 1011 B-Zone 5 503 499 490 430 . 495 B-Zone 6 807 620 581 453 -757.-.

RESPONSE - h.ii)

CR3 TEC Indications & Tubes Detected (As-Found) in Each Zone OTSG/Zone 11R (1999) 12R (2001) 13R (2003) Upper Tube .13R (2003) Lower Tube Indications/Tubes Indications/Tubes End  : End' Upper Tube End Upper Tube End Indications/Tubes Indications/Tubes A-Zone 1 191/117 318/233 450/353 0/0 7 A-Zone 2 188/140 341/251 419/317 4/1 A-Zone 3 136/93 225/159 273/192 0/0 A-Zone 4 79/55 137/102 172/129 1/1 A-Zone 5 26/21 42/37 58/49 0/0 A-Zone 6 343/184 57/50 95n5 2/2 B-Zone 1 165/102 152/122 163/120 -CO .

B-Zone 2 198/160 262/213 334/267 14/14 B-Zone 3 179/134 280/204 351/255 45/43.

B-Zone 4 66/54 123/91 137/110 30/28 B-Zone 5 22/19 56/45 59/52 14/13 B-Zone 6 274/151 101/82 129/104 12/10 RESPONSE - b.iii)

The number of projected TEC indications has not been provided. Corrective Action 3 in this attachment will use data from Refueling Outage 14, and previous outages, to re-evaluate the method to account for new TEC and to adjust projections for 15R.

U. S. Nuclear Regulatory Commission Attachment D 3F0505-12 Page 4 of 7 RESPONSE - b.iv)

CR3 Number of As-Left TEC Indications (Tubes) Since 11R (1999)

OTSG/Zone 11R (1999) 12R (2001) 13R (2003) 13R (2003)

Indications/Tubes Indications/Tubes Upper Tube End Lovwer Tube End Upper Tube End Upper Tube End Indications/Tubes Indications/Tubes -

A-Zone 1 180/110 318/233 449/352 0/0 A-Zone 2 187/139 340/250 418/316 -4/1 A-Zone 3 131/91 225/159 233/179 - 0/-

A-Zone 4 79/55 137/102 121/106 .1/1 A-Zone 5 25/20 42/37 0/0 0/0 A-Zone 6 21/21 56/49 0/0 2/2 B-Zone 1 68/49 120/91 149/107 0/0 B-Zone 2 177/142 247/204 329/262 14/14 B-Zone 3 173/128 277/201 346/251 45/43 B-Zone 4 61/51 96/79 135/109 30/28 B-Zone 5 21/18 37/37 0/0 14/13 B-Zone 6 49/49 63/63 0/0 9n7

U. S. Nuclear Regulatory Commission Attachment D 3F0505-12 Page 5 of 7 RESPONSE - b.v)

CR3 Number of New TEC Indications (Tubes) Since 11R (1999)

Number in 12R (2001 As- Number in 13R (2003 As- Number in 13R (2003 As-OTSG/Zone Found) that were not in Found) that were not in Found) Inspections that 1IR (1999 As-Left) 12R (2001 As-Left) were not performed in Indications/Tubes Upper Tube Ends - 12R (2001)

Upper Tube End Indications/Tubes Lower Tube Ends Indications/Tubes A-Zone 1 138/123 132/120 0/0 A-Zone 2 154/112 79/67 4/1 A-Zone 3 94/68 48/33 0/0 A-Zone 4 58/47 35/27 1/1 A-Zone5 17/17 16/12 0/0 A-Zone 6 36/29 39/26 2/2 B-Zone 1 84/73 43/29 0/0 B-Zone 2 85/71 87/63 14/14 B-Zone 3 107/76 74/54 45/43 B-Zone 4 62/40 41/31 30/28 B-Zone 5 35/27 22/15 14/13 B-Zone 6 52/33 66/41 12/10 RESPONSE - b.vi)

CR3 Average Number of As-found TEC Indications per Tubes Since IlR OTSG/Zone 1IR (1999) 12R (2001) 13R (2003) Upper 13R (2003)

Indications per Indications per Tube End Lower Tube Tube Tube Indications per End Upper Tube End Upper Tube End Tube Indications per

_ __ _ _ __ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _T ub e A-Zone 1 1.63 1.36 1.27 N/A A-Zone 2 1.34 1.36 1.32 4.00 A-Zone 3 1.46 1.42 1.42 N/A A-Zone 4 1.44 1.34 1.33 1.00 A-Zone 5 1.24 1.14 1.18 N/A A-Zone 6 1.86 1.14 1.27 1.00 B-Zone 1 1.62 1.25 1.36 N/A B-Zone 2 1.24 1.23 1.25 1.00 B-Zone 3 1.34 1.37 1.38 - 1.05 B-Zone 4 1.22 1.35 1.25  : 1.07 B-Zone 5 1.16 1.24 1.13 1.08 B-Zone 6 1.81 1.23 1.24 1.2

U. S. Nuclear Regulatory Commission Attachment D 3F0505-12 Page 6 of 7 RESPONSE - b.vii)

This table only presents new TEC for the upper tube end since there were no lower TEC identified prior to 2003.

CR3 Percent of tubes with New TECs Since 11R (1999)

OTSG/Zone New TEC tubes (12R - 11R) New TEC tubes (13R - 12R) divided by potential 11R divided by potential 12R non-repaired tubes) non-repaired tubes)

-Percent (%)- . -Percent (%)-

Upper Tube End Upper Tube End A-Zone 1 1.8% 1.8%

A-Zone 2 2.8% 1.7%

A-Zone 3 3.7% 1.8%

A-Zone 4 4.7% 2.7%

A-Zone 5 3.4% 2.4%

A-Zone 6 5.0% 4.7%

B-Zone 1 1.2% 0.5%

B-Zone 2 1.8% 1.6%

B-Zone 3 4.1% 2.9%

B-Zone 4 4.0% 3.1%

B-Zone 5 5.4% 3.1%

B-Zone 6 5.3% 7.1%

APRIL 8,2005. NRC RAI OUESTION - c) c) An assessment of the potential that the number of TEC indications is increasing at an increasing rate such that projections based on historical experience need to be adjusted.

RESPONSE - c)

An assessment of the potential that the number of TEC indications is increasing at an increasing rate has not been performed. Corrective Action 3 in this attachment will use data from Refueling Outage 14 and previous outages to re-evaluate the method to account for new TEC and to adjust projections for 15R.

APRIL 8, 2005. NRC RAI QUESTION - d) d) The basis for the new TEC leakage values of 0.274 gpm and 0.535 gpm in steam generators A and B, respectively in light of the information discussed above.

U. S. Nuclear Regulatory Commission Attachment D 3F050-12 Page 7 of 7 RESPONSE - d)

This question addresses information from the response to Question 1.b), Attachment A, Reference 1, that has been deleted from the response. The deleted information addressed a technique for predicting leakage attributed to Tube End Cracks for the next Refueling Outage (14R). The deleted information was not used during the 13R OTSG inspection and will not be used during the 14R inspection. Thus, Question d) is no longer applicable.

APRIL 11, 2005. NRC RAT QUESTION Upon further review of the March 30, 2005, there appear to be other inconsistencies in reported values. For example, the "new" leakage for the upper tubesheet reported in the March 30, 2005, letter does not appear to be based on values provided in previous reports. "New leakage" is defined as the difference between the "as found" leakage during one outage (13R in this case) and the "as-left" leakage in the prior outage (12R in this case). On pages 6 and 8 of 30 of Attachment A to the March 30, 2005 letter, the "new leakage" is reported as 0.261 gpm for steam generator A and 0.411 gpm for steam generator B. However, the "as-found" leakage for 13R is reported in the licensee's letter dated October 31, 2003 (ML033090110) as 1.102 gpm and 0.932 gpm for steam generators A and B, respectively. The "as-left" leakage for 12R was reported in the March 30, 2005 letter as 0.626 gpm and 0.625 gpm for steam generators A and B, respectively. The difference between these as-found and as-left leakage values (0.306 gpm and 0.477 gpm in steam generators A and B, respectively) do not match those reported in the March 30, 2005, letter. In addition, the number of indications in zone 6 reported in the body of the text of the March 30, 2005 letter (pages 7 and 9 of Attachment A) do not appear to match those reported in Tables 1 and 2.

RESPONSE

This question addresses information from the response to Question 1.b), Attachment A, Reference 1, that has been deleted from the response. The deleted information addressed a technique for predicting leakage attributed to Tube End Cracks for the next Refueling Outage (14R). The deleted information was not used during the 13R OTSG inspection and will not be used during the 14R inspection. Thus, this question is no longer applicable.

REFERENCE

1. PEF to NRC letter dated March 30, 2005, "Crystal River Unit 3 - Response to NRC Request for Additional Information Regarding Once-Through Steam Generator Tube Inservice Inspection Conducted During Refueling Outage 13"