ML051020360

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

ML051020360
Person / Time
Site:	Crystal River
Issue date:	03/30/2005
From:	Annacone M Progress Energy Florida
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
3f0305-03, TAC MC1176, TAC MC1853
Download: ML051020360 (48)

Text

, Progress Energy Crystal River Nuclear Plant Docket No. 50-302 Operating Ucense No. DPR-72 Ref: 10 CFR 50.36 March 30,2005 3F0305-03 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

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

Reference:

NRC 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)"

Dear Sir:

Florida Power Corporation, doing business as Progress Energy Florida, Inc. (PEF), is hereby providing the Crystal River Unit 3 (CR3) response to the referenced Request for Additional Information (RAI). The RAI was discussed with the NRC staff during telecons on January 25, March 2 and March 23, 2005. Based on the March 23 discussions, the response due date was extended to March 30, 2005.

This letter establishes no new regulatory commitments.

Attachment C provides a revision to Table 3 from the Refueling Outage 12 (12R) MODE 4 Report (CR-3 letter 3F1001-03, dated October 19, 2001). The revised Table 3 supersedes the previously provided table.

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

Sincpely, Mic 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 xc:

NRR Project Manager Regional Administrator, Region II Senior Resident Inspector Progress Energy Florida, Inc.

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

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 3F0305-03 Page 1 of 30 This Attachment provides a Background for each question contained in the February 1, 2005 Request for Additional Information (RAI). Following the Background, each question from the February 1, 2005 RAI is provided with the corresponding Crystal River Unit 3 (CR3) response.

The Background consists of previously asked NRC questions and CR3 responses which are associated with the February 1, 2005 NRC questions.

BACKGROUND October 6.2004 - NRC RAI Question 1 The calculated amount of leakage during postulated accident limits exceeded expectations and the leakage limit. A root cause analysis determined the cause for exceeding the as-found leakage limit was that the use of the probability of detection for tube end cracking does not provide sufficient margin to account for the increase in the'number of tube end cracks in future outages.

Given the root cause, please discuss how this affects your current projections for accident-induced leakage during the current operating cycle (as discussed in the original request for additional information). That is, address whether adequate leakage integrity will be maintained once the initiation of new indications are included in the existing leakage model. If adequate leakage integrity will not be maintained, discuss your proposed corrective action.

November 24,2004 - CR3 Response to Ouestion 1 When the postulated Steam Line Break (SLB) as-found primary-to-secondary leakage was detennined to be greater than the leakage limit, it was recognized that the probability of detection (POD) was adequate to account for a small number of previously undetected Tube End Cracks (TEC), but was not sufficient to compensate for the larger number of tubes with new TEC indications. This information was not recognized during the previous Refueling Outage (12R).

However, since this was recognized during Refueling Outage 13 (13R), CR3 was able to perform an expanded re-roll repair effort which reduced the effective number of tubes with TEC, and associated leakage, for those remaining in service. The as-left number of tubes with TEC was reduced to a low level where the resulting as-left leakage, combined with the projected new TEC leakage, and an additional POD margin will be less than the CR3 leakage limit. Projections for the next Refueling Outage (14R) show that both Once-Through Steam Generators (OTSGs) will meet the leakage integrity criteria even with additional new TEC indications.

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

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 2 of 30 reported number of tubes with tutbe-end-crack indications and tile 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 S 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-i and A-2 (1099 tubes).

RESPONSE - la)

Projections of TEC indications are based on the methodology of 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 is 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:

NMradius = [(l/POD)(NAsFound)radius] -

[UNrepaired)radius(l)]

Where:

NIradiuS = estimated number of indications at given radius zone NAsFound)radius = number of indications actually detected at given radius zone Nrepaired)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:

TABLE 1 - A-OTSG 13R TEC Indications Radial Zone Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Totals As-Founds 450 423 273 173 58 97 1474 As-Left 449 422 233 122 0

2 1228 Indications 4

Repaired I

1 40 51 58 95 246 Indications 1

Projected Indications (POD 534.7 502.6 285.0 155.0 11.0 20.4 1509

& As-Left)

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment A Page 3 of 30 TABLE 2 - B-OTSG 13R TEC Indications Radial Zone Zone I Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Totals As-Found At-ons 163 348 396 167 73 141 1288 Indications Indications 149 343 391 165 14 9

1071 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)

RESPONSE - lb)

As mentioned above, projection of TEC leakage is based on the methodology of BAW-2346P, Revision 0. However, after determining that the TEC leakage had been under-predicted in the 12R Operational Assessment (OA) based on the as-found leakage attributed to TEC in the 13R outage, CR3 recognized that the previous practice of using only the TEC POD amount for a leakage projection was inadequate. To ensure that TEC leakage in the current cycle has not been under-predicted, a technique was developed to better project new TEC indications based on historical data. This technique is described below, immediately after the data corresponding to the projections required by Topical Report BAW-2346P (Tables 3, 4 & 5).

The total TEC leak rate from all zones for each OTSG is compared to plant specific allowable leak rates. The NRC approved plant specific TEC leak rate and corresponding radial zones for CR3 are identified in 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).

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) 1

> 3, < 39 7.1OE-5

> 3, <42 7.10E-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 3F0305-03 Attachment A Page 4 of 30 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 Projected Leakage 0.459 (POD & As-0.038 0.095 0.109 0.084 0.015 0.117 Note 1 Left)(gpm)

I Note 1 - This is the Leakage value reported as the Projected Accident Leakage for TEC in the Mode 4 Report (CR3 to NRC letter, 3F1 003-07, dated October 31, 2003).

TABLE 5-B-OTSG 13R TEC Projected Leakage Radial Zone Zone 1 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) l 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)

I XT-.A

^

T V-

• t.

A A_. A_

TA y

j NOte ills iS uie Leakage value reponed as me rrojected Accident.

Mode 4 Report (CR3 to NRC letter, 3F1003-07, dated October 31, 2003).

LeaCage iur 1U C in the

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 4

Page 5 of 30 The projected TEC leakage for the current operating cycle was calculated using the leakage model from BAW-2346P, Revision 0 and Addendum A. However, corrective actions taken in accordance with the CR3 Corrective Action Program required additional tubes with TEC indications to be re-rolled during the 13R refueling outage to reduce the as-left TEC indications/leakage and to provide additional margin for the current cycle. Thus, in order to provide for additional margin for the current cycle, CR3 preventatively plugged tubes and re-rolled additional tubes ends identified with TEC indications.

There were 246 and 217 indications in the A and B-OTSGs, respectively, repaired to bring the as-left and projected TEC leakage (Tables 4 and 5) to an acceptable margin for the current operating cycle.

TEC Prediction Process The process described below identifies a technique used to obtain a better prediction of the leakage attributed to TEC for 14R. The basis for this technique is engineering judgment and the recognition that the existing BAW-2346P method did not provide a process to estimate growth of new TEC indications.

This technique does not supersede the NRC approved BAW-2346P method, but it does provide an additional prediction tool for CR3 to use in determining the extent of tubes to be repaired (plugged or re-rolled).

TEC indications can be removed from the leakage total by having the tubes plugged or re-rolled.

Given the desire to keep tubes in service, the re-roll method is usually preferred. In 13R the as-found postulated leakage was calculated and the amount had to be reduced to at least below the 0.856 gpm leak limit plus a factor for the BAW-2346P POD calculation.

As shown in Table 3 above, Zone 6 has the highest leak rate per indication of all tubesheet locations. Tubes in Zone 6 (periphery) have the largest impact on the calculated leakage since for any indication the assigned leakage is higher than any other radial zone. It is for this reason that if additional tube re-rolling is required to reduce as-left (OA) leakage attributed to TEC, any TEC indication in Zone 6 is repaired first to achieve the most benefit.

As a corrective action in 13R, the leakage was reduced to less than the limit by re-rolling tubes with the highest assigned leakage. At the time, it was recognized that only re-rolling tubes to achieve the BAW-2346P POD amount would not result in the as-left leakage attributed to TEC being low enough to accommodate the expected number of "new" (undetected TEC due to inspection technique capabilities or due to the potential initiation of TEC) TEC based on previous cycle experience. New TEC leakage can also be considered to be a historically based prediction of the previously undetected TEC indications that are expected to be discovered in the next inspection. Therefore, as part of the corrective actions in 13R, additional TEC tubes were re-rolled to further reduce the as-left TEC indications/leakage to the levels documented here.

The process of performing additional re-rolls beyond the BAW-2346P minimum provides margin to allow for "new" TEC without exceeding any postulated leak limits.

The process to determine the TEC projected leakage for 14R is as follows:

1. Take the as-left (returned to service) TEC leakage from 13R

2. Use the "new" TEC leakage that was found in 13R and assume that same amount is again detected in 14R. New leakage is defined as the difference between the as-found TEC leakage in 13R versus the as-left leakage in 12R.

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 6 of 30

3. Adjust the expected "new" TEC leakage amount by the reduction in population of the available tubes in Zone 6. The actual number of potential TEC tubes in Zone 6 during the latest operating cycle will be determined from the Framatome Data Management System (FDMS) database.

The projected TEC leakage total for 14R is the total of the as-left in 13R and the adjusted "new" TEC based on previous cycle operation.

A-OTSG Calculations Step #1 The as-left return to service TEC leakage from 13R is 0.279 gpm [Reference 2].

Step #2 Given: The "new" TEC leakage for the upper tubesheet was 0.261 gpm [Reference 2].

Given: The "new" TEC leakage for the lower tubesheet was 0.013 gpm [Reference 2].

However, the lower tubesheet TECs are not expected to occur at the same rate in the future because this was the first inspection of the lower tube ends since the OTSGs have been in service and the TECs identified took longer than one cycle to develop. One assumption is that the lower TECs will occur at a ratio of 1/15 of the as-found rate from 13R. This is based on the fact that these indications took over 25 years to be discovered and will not reoccur at the same rate in only 2 years. The 1/15 rate is also discussed in the Framatome Condition Report [Reference 3] on lower tube end cracking. Therefore, the "new" TEC leakage for the lower tubesheet for 14R is 0.0 13 gpm x 1/15 = 0.0009 gpm.

Step #3 To be conservative, only the tubes in Zone 6 will be adjusted for the decreasing population.

Therefore, the tubes with TECs in Zones 1 through 5 will be assumed to occur at the same rate as found in 13R.

Because the number of tubes in Zone 6 is small compared to the entire OTSG and because tubes that are plugged or re-rolled no longer are part of the potential population of tubes that can contribute to future TEC leakage, the reduced population of tubes in that zone can be used to recalculate the projected new TEC for 14R. The same percentage of new tubes found with TEC in 13R will be used. The reduced number of Zone 6 tubes available for TEC due to re-rolling and plugging will be used to calculate the reduction in expected Zone 6 TEC leakage for 14R.

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 7 of 30 A-OTSG - Upper Tube End Zone 6 Calculations After 12R, there were 559 tubes out of 827 in Zone 6 of the "A" OTSG that were left in service and not previously re-rolled. During 13R, the as-found (new) number of TEC tubes was 26.

Therefore, the percentage of Zone 6 tubes that developed new TECs was:

(26 / 559)

• 100 = 4.7%

The tubes in Zone 6 that could potentially develop new TECs have now been reduced by an additional 99 (75 re-rolled and 24 plugged) after 13R since they were all either re-rolled or plugged. The number of potential TEC tubes remaining in Zone 6 is now 559 - 99 = 460 tubes.

Applying the same percentage from 12R to 13R to the tubes remaining from 13R yields:

X / 460 = 4.7%

X = 22 projected new TEC tubes Therefore, the reduction in the number of new TEC tubes is 26 - 22 = 4 tubes. These 4 tubes can be adjusted for the number of indications as follows:

Because many TEC tubes have more than one TEC indication, there needs to be an adjustment between tubes and indications in order to properly calculate the impacted TEC leakage. In 13R, there were 75 TEC tubes with 95 indications. The ratio of indications-to-tubes is:

(95 / 75) = 1.27 average TEC indications per tube 4 TEC tubes

• 1.27 = 5.1 indications Using the TEC leakage values from Table 1 Zone 6, the reduction in leakage from these indications is:

5.1 indications

• 5.72E-3 gpm/ indication = 0.0292 gpm Summarv of A-OTSG Prolected New TEC Leakage for 14R

+0.2740 gpm, New TEC Leakage in 13R (0.261 upper & 0.0 13 lower)

- 0.0130 gpm, Lower TECs (Not Expected to Reoccur at Same Rate)

+0.0009 gpm, Lower TECs (@ 1/15 of LTE Leakage)

- 0.0292 gpm, Zone 6 Population Reduction

= 0.233 gpm

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 8 of 30 B-OTSG Calculations Step #1 The as-left return to service TEC leakage from 13R is 0.385 gpm [Reference 2].

Step #2 Given: The "new" TEC leakage for the upper tubesheet was 0.411 gpm [Reference 2].

Given: The "new" TEC leakage for the lower tubesheet was 0.124 gpm [Reference 2].

However, the lower tubesheet TECs are not expected to occur at the same rate in 'the future because this was the first inspection of the lower tube ends since the OTSGs have been in service and the TECs identified took longer than one cycle to develop. One assumption is that the lower TECs will occur at a ratio of 1/15 of the as-found rate from 13R. This is based on the fact that these indications took over 25 years to be discovered and will not reoccur at the same rate in only 2 years. The 1/15 rate is also discussed in the Framatome Condition Report [Reference 3] on lower tube end cracking. Therefore, the "new" TEC leakage for the lower tubesheet for 14R is 0.124 gpm x 1/15 = 0.0083 gpm.

Step #3 To be conservative, only the tubes in Zone 6 will be reviewed; the tubes with TECs in Zones I through 5 will be assumed to occur at the same rate as found in 13R.

Because the number of tubes in Zone 6 is small compared to the entire OTSG and because tubes that are plugged or re-rolled no longer are part of the potential population of tubes that can contribute to future TEC leakage, the reduced population of tubes in that zone can be used to recalculate the projected new TEC's for 14R. The same percentage of new tubes found with TECs in 13R will be used. The reduced number of Zone 6 tubes available for TEC due to re-rolling and plugging will be used to calculate the reduction in expected Zone 6 TEC leakage for 14R.

B-OTSG - Upper Tube End Zone 6 Calculations After 12R, there were 581 tubes out of 827 in Zone 6 of the "B" OTSG that were in service and not previously re-rolled.

During 13R, the as-found (new) number of TEC tubes was 41.

Therefore, the percentage of Zone 6 tubes that developed new TECs was:

(41 /581)

• 100 =7.1%

The tubes in Zone 6 that could potentially develop new TECs have now been reduced by an additional 138 (104 re-rolled & 34 plugged) after 13R since they were all either re-rolled or plugged. The number of potential TEC tubes remaining in Zone 5 is now 581 - 138 = 443 tubes.

Applying the same percentage from 12R to 13R to the tubes remaining from 13R yields:

X /443 = 7.1%

X = 31 projected new TEC tubes

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment A Page 9 of 30 Therefore, the reduction in the number of new TEC tubes is 41 - 31 = 10 tubes. These 10 tubes can be adjusted for the number of indications as follows:

Because many TEC tubes have more than one TEC indication, there needs to be an adjustment between tubes and indications in order to properly calculate the impacted TEC leakage. In 13R, there were 104 TEC tubes with 129 indications. The ratio of indications-to-tubes is:

(129 / 104) = 1.24 average TEC indications per tube 10 TEC tubes

• 1.24 = 12.4 indications Using the TEC leakage values from Table 1 Zone 6, the reduction in leakage from these indications is:

12.4 indications

• 5.72E-3 gpm / indication = 0.071 gpm Summary of B-OTSG Proiected New TEC Leakage for 14R

+0.5350 gpm, New TEC Leakage in 13R (0.411 upper & 0.124 lower)

- 0.1240 gpm, Lower TECs (Not Expected to Recur at Same Rate)

+0.0083 gpm, Lower TECs (@ 1/15 of LTE Leakage)

- 0.0710 gpm, Zone 6 Population Reduction

= 0.348 gpm Prediction of 14R TEC Leakage Using Additional Prediction Tool 14R TEC Leakage for Cycle 14 Component "A" OTSG

"'S" OTSG 13R As-Left Leakage 0.279 gpm 0.385 gpm Projected New TEC 0.233 gpm 0.348 gpm Leakage Total TEC Leakage 0.512 gpm 0.733 gpm

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 10 of 30 Benchmarking Of This Technique for Cycle 12 The 12R predicted TEC leakage could not be determined using the same process because the required TEC as-found and as-left information was not available for the time frame prior to Refueling Outage 11 (I1IR).

The prediction of 12R TEC leakage data requires that, as a minimum, the as-left leakage from Refueling Outage 10 (IOR) and the as-found leakage from I R be known in order to obtain the historical increase (1 IR as-found minus 1OR as-left) of new TEC indications for the next cycle projections. License Amendment #188 for TEC ARC was issued in October 1999 and first used in November 1999. Therefore, because the existing TEC ARC was not implemented until 11 R (1999), there is not comparable data prior to the 1 R as-found information and the same prediction method is not possible.

Benchmarking Of This Technique for Cycle 13 Benchmarking this technique for Cycle 13, compared to actual as-found and as-left leakage shows the acceptability of this additional technique to conservatively predict future TEC leakage rates. For example, if this technique had been used during the 12R inspection, the projected leakage, as shown in the Table below, would have been higher than allowed and corrective actions (perform re-rolls) would have taken place to reduce the as-left TEC leakage. For the (12R to 13R) TEC leakage projections, the new TEC leakage was not adjusted for Zone 6 population reductions because no repair rolls were performed in the A-OTSG and only a small number in the B-OTSG.

Step #1 The A-OTSG as-left return to service TEC leakage from 12R is 0.626 gpm [Reference 9].

The B-OTSG as-left return to service TEC leakage from 12R is 0.625 gpm [Reference 9].

Step #2 Given: The A-OTSG 12R as-found TEC leakage was 0.631 gpm.

Given: The A-OTSG 1 IR as-left TEC leakage was 0.296 gpm.

Therefore, the projected new TEC leakage = (0.631 - 0.296) = 0.335 gpm.

Given: The B-OTSG 12R as-found TEC leakage was 0.889 gpm.

Given: The B-OTSG 1 IR as-left TEC leakage was 0.447 gpm.

Therefore, the projected new TEC leakage = (0.889 - 0.447) = 0.442 gpm.

Sten #3 Not applicable for this prediction due to little to no preventative re-rolling performed during 12R.

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment A Page 11 of 30 Prediction of 13R TEC Leakage Using Additional Prediction Tool Previous Cvcle 13R TEC Leakage for Cycle 13.

Leakage Component A-OTSG B-OTSG 12R As-Left Leakage 0.626 gpm 0.625 gpm Projected New TEC 0.335 gpm 0.442 gpm Leakage Total TEC Leakage 0.961 gpm

1.067 gpm A-OTSG TEC Leakage Benchmarking Summary The actual as-found TEC leakage in 13R was 0.945 gpm. A small part of that total was from the first time discovery of lower tube ends TECs which are not expected to reoccur at the same rate in the future. Therefore, the expected leakage should be reduced by 0.013 gpm. Therefore, the true leakage was only 0.932 gpm. The predicted leakage was 0.961 gpm or 103% of the as-found leakage and shows a good correlation.

B-OTSG TEC Leakage Benchmarking Summarv The actual as-found TEC leakage in 13R was 1.226 gpm. A small part of that total was from the first time discovery of lower tube ends TECs which are not expected to reoccur at the same rate in the future. Therefore, the expected leakage should be reduced by 0.124 gpm. Therefore, the true leakage was only 1.102 gpm. The predicted leakage was 1.067 gpm or 97% of the as-found leakage and shows a good correlation.

Therefore, this additional technique is in good agreement with the as-found conditions and can be used to predict future TEC leakage rates.

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 12 of 30

References:

1. A CMOA Evaluation of Steam Generator Tubing, 13RFO At CR3, Framatome Report 51-5035818-02

2. CR3 RFO-13 TEC Leakage Calculation, Framatome Report 32-5035732-00

3. Framatome Condition Report # 6029428, Rev 1, Cold Leg Tube End Cracking

4. BAW-2346P, Rev 0, Tube End Crack Alternate Repair Criteria

5. NCR 111677, OTSG Projected MSLB Leakage Exceeds OTSG Maintenance Rule Performance Criteria

6. NCR 109383, OTSG Condition Monitoring MSLB Leakage Results

7. Improved Technical Specifications 5.6.2.10.2.f

8. Letter to NRC, 3F0305-03, Response to NRC Request for Additional Information

9. Framatome Report, 32-5014980-01, CR-3 Tube End Cracking ARC Leakage Calculation -

12RFO Conclusion 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. Site specific projections of new TEC were used to determine the number of additional tubes to re-roll. This technique was also benchmarked to the previous cycle actual data (not including first time lower tube ends) and it was concluded that, if this technique had been applied during the 12R outage and additional re-rolls performed, the as found leakages would have satisfied the overall leakage criteria.

Therefore, this data shows a good agreement with this technique, in conjunction with BAW-2346P, to predict future TEC leakage rates.

Other Actions Taken License Amendment Request (LAR) #290, Revision 0, was submitted 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 NRC has previously evaluated this method for CR3 in the Safety Evaluation Report for License Amendment #188 (NRC letter dated October 1, 1999, TAC No. MA5395). 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 3F0305-03 Page 13 of 30 RESPONSE - 1c) Part 1 The CR3 October 31, 2003 letter to the NRC (3F1003-07) pirvided 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 TUBEES INDICATIONS Location UTE/LTE 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 3F0305-03 Attachment A Page 14 of 30 RESPONSE - 1c) 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-1 and A-2 agree with the totals above for A-OTSG. A review of the tube numbers from Table A-1 (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 3F0305-03 Page 15 of 30 BACKGROUND October 6,2004 - NRC RAI Ouestion 2.d Please clarify what bobbin indications were further characterized with a rotating probe. For example, were all suspect wear locations inspected with a rotating probe to confirm the absence of cracking? If not, please address the technical basis for the criteria used to disposition potential wear locations.

November 24, 2004 - CR3 Response to Ouestion 2.d Bobbin indications that are detennined to be other than wear are evaluated using a rotating coil.

Upon detection of a wear signal indication, a morphology determination is made with a bobbin probe. Wear indications are compared to the previous inspection data to determine if there is a change in signal characteristics.

Any new wear indication, change in bobbin signal characteristics, or indications with no previous Motorized Rotating Pancake Coil (RPC) data are characterized using a mid-frequency +Point probe and 0.115 Pancake rotating coil. Therefore, all suspect wear locations are inspected with a rotating probe to refute or confirm the presence of cracking. This evaluation is done in accordance with the CR3 Eddy Current Data Analysis Guidelines.

FEBRUARY 1, 2005 - NRC RAI QUESTION 2 In the November 24, 2004, response to RAI question L.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 detennine if there is a change in signal characteristics. Rotating probe examinations are then perfonmed 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 thefollowing:

a) a description of the bobbin coil eddy current data parameters used to distinguish wear from other degradation mechanisms (including intergranilar 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 parametersfor screening wearfrom otherforms 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. Iffield wear scars with cracks would not have met your criteria for perfonming 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).

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 16 of 30 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.

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 (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)

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 17 of 30 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 3F0305-03 Page 18 of 30 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 (ISP) 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 3F0305-03 Page 19 of 30 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 3F0305-03 Page 20 of 30 BACKGROUND October 6,2004 - NRC RAI Question 2.e Please clarify why the number of tubes examined with the bobbin coil does not equal the number of tube ends examined with a rotating probe. For example, Table 1 indicates that 15,151 upper tube ends were examined with a rotating probe in steam generator A, but 15,314 tubes were examined with a bobbin coil.

Were the upper tube ends for approximately 150 tubes not examined? If not, why not?

November 24, 2004 - CR3 Response to Question 2.e The difference between the numbers of tube ends examined with the bobbin coil versus the number examined with a rotating probe is due to the fact that there are sleeves installed in some of the upper tube ends of the steam generators. A rotating coil probe was used on all upper tube ends without a sleeve installed. For example, prior to 13R, there were 163 in-service sleeves in the A-OTSG. These tube ends were not included as part of the same inspection. Tubes with sleeves had their own inspections that included the parent tube material, the sleeve and rolled regions. The difference between the two numbers, 163 in A-OTSG and 159 in B-OTSG, is because the sleeves are considered as part of another inspection sample.

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 3F0305-03 Page 21 of 30 BACKGROUND October 6,2004 - NRC RAI Ouestion 3 It was indicated that the primary-to-secondary leakage prior to plant shutdown was less than 5 gallons per day (gpd), and the leakage after 13R is less than 2 gpd. Presumably the reduction in leakage could be a result of the repair of through-wall flaws; however, no in-situ testing was performed.

Please, clarify the types of degradation detected during the outage (including orientation and location), the number of indications for each type of degradation, and discuss the sizes of the larger indications of each of these types of indications. Tube end cracks (i.e., those near the cladding) and first span intergranular attack indications need not be included in this information; however, indications associated with the roll transition or roll expanded area should be provided.

November 24, 2004 - CR3 Response to Ouestion 3 The primary-to-secondary side leakage values of less than 5 gpd and then 2 gpd is not intended to imply that the leakage before the 13R outage was higher than after the outage. The 5 gpd limit was mentioned to identify that the leakage at CR3 was less than the lowest threshold limit from the EPRI Primary-To-Secondary Leak Guidelines. The actual leakage prior to the 13R outage was approximately 2.7 gpd.

The leakage after the 13R outage is approximately 2.4 gpd.

The difference between the two leakage rates is within the accuracy of the measurement.

The Tables provided in the next two pages have the information requested regarding orientation, location and size (voltage) for OTSG tube degradation (primarily Primary Water Stress Corrosion Cracking and Intergranular Attack). Indications near the cladding and first span intergranular attack are not included. Wear indications are provided in Special Report 04-01, Appendix 1.

The largest voltage indications from each of the different indication codes are identified below for each steam generator.

13R Largest Size (Voltage) Indications from Tables A-OTSG and B-OTSG OTSG/Tube Indication Code Location Length (Inches)

Depth (% TW)

A40-117 MAI UTE - 0.63" 0.20 93 A70-66 SCI UTE-1.13" 0.38 77 A143-3 SVI 15S + 0.73" 0.44 x 0.29 48 A144-28 SAI UTE-1.19" 0.21 53 B80-109 SAI UTE - 0.88" 0.19 57 B85-62 SVI LTE + 1.1 1" 0.29 xO.38 69 B109-2 MAI UTE - 4.14" 0.13 64 B 134-66 MVI UTE - 4.25" 0.27 x 0.44 40 MAI Multiple Axial Indication MVI Multiple Volumetric Indication SAI Single Axial Indication SCI Single Circumferential Indication SVI Single Volumetric Indication 15S 15t Tube Support Plate UTE Upper Tube End LTE Lower Tube end LTS Lower Tubesheet Secondary Interface

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment A Page 22 of 30

_ A-OTSG Row Tube Volts Degree Indication Landmark Location 2

26 0.26 83 SAI 15S

-5.73 0.31 86 MAI 15S

-7.3 0.19 85 SAI 15S

-3.28 2

27 0.18 100 SAI 15S

-7.77 0.21 101 SAI 15S

-6.63 13 67 0.21 105 SVI 15S 0.03 18 79 0.17

.111 SVI UTE

-4.07 25 3

0.34 24 SAI UTE

-1.29 25 12 0.73 14 SAI UTE

-1.42 27 51 0.56 23 SAI UTE

-1.21 27 68 0.55 13 SAI UTE

-1.41 28 100 0.55 17 SAI UTE

-0.94 30 104 0.71 20 SAI UTE

-0.99 40 85 0.71 21 SAI UTE

-1.54 40 117 1.24 28 MAI UTE

-0.63 44 17 0.5 16 SAI UTE

-1.25 52 112 0.58 20 SAI UTE

-1.18 52 118 0.81 22 SAI UTE

-0.97 54 40 0.71 22 SAI UTE

-1.16 55 100 0.61 26 SAI UTE

-1.08 57 80 0.39 23 SAI UTE

-1.47 58 115 0.58 32 MAI UTE

-3.89 62 7

0.66 14 SAI UTE

-1.32 65 73 1

24 SAI UTE

-0.52 69 56 0.8 14 SAI UTE

-0.57 69 127 0.64 20 SAI UTE

-1.1.

70 66 0.69 19 SCo UTE

-1.13 75 95 0.6 22 MAI UTE

-4.36 75 96 1.05 26 MAI UTE

-4.22 77 50 0.2 83 SVI UTS 0.21 80 102 0.72 13 SAI UTE

-1.1 80 124 0.3 16 SAI UTE

-1.02 81 9

0.91.

20 SAI UTE

-1.5 87 6

1.15 21 SAI UTE

-0.6 87 56 0.82 28 SAI UTE

-0.61 92 121 0.95 28 SAI UTE

-0.95 96 111 1.22 24 SAI UTE

-1.07 110 3

0.17 91 SVI 15S

-0.22 120 94 0.56 27 SAI UTE

-1.06 143 3

1.21 76 SVI 15S 0.73 144 28 1.38 20 SAI UTE

-1.19

U. S. Nuclear Regulatory Commission f

3F0305-03 Attachment A Page 23 of 30

_B-OTSG Row Tube Volts Degree Indication Landmark Location 6

6 0.27 74 SAI 15S

-5.09 8

5 0.2 122 SVI UTE

-4.51 14 27 0.36 20 SAI UTE

-1.19 38 47 0.53 9

MAI UTE

-1.17 44 3

1.02 16 SAI UTE

-1.99 44 28 0.3 11 SAI UTE

-1.19 46 2

0.47 59 SVI LTS 0

50 82 0.16 90 SVI UTE

-4.27 55 93 0.17 96 SVI UTE

-3.15 55 122 0.34 19 SAI UTE

-1.25 58 84 0.16 92 SVI UTE

-4.19 72 31 1.05 17 SAI UTE

-4.16 72 34 0.87 27 SAI UTE

-3.65 73 15 1.11 33 SAI UTE

-0.79 73 61 1.12 23 SAI UTE

-0.72 80 6

0.6 16 SAI UTE

-0.64 80 109 1.26 20 SAI UTE

-0.88 81 10 0.82 23 SAI UTE

-0.86 83 64 0.82 27 SAI UTE

-0.71 85 62 0.98 22 SVI LTE 1.11 89 94 0.13 122 SVI UTE

-2.87 97 125 0.33 17 SVI UTE

-1.12 98 97 0.84 18 SAI UTE

-1.47 99 107 0.29 43 SAI UTE

-0.84 100 33 0.52 25 SAI UTE

-0.9 101 94 0.17 90 SVI UTE

-3.36 109 2

0.7 24 MAI UTE

-4.14 112 90 0.94 16 SAI UTE

-1.43 114 1

0.35 80 SAI 15S

-1.62 121 83 0.69 17 SAI UTE

-1.34 125 81 0.84 19 SAI UTE

-4.24 127 79 0.76 15 SAI UTE

-1.27 134 66 1.14 40 MVI UTE

-4.25 137 4

0.82 26 SAI UTE

-0.62 143 31 0.34 16 MAI UTE

-1.14 149 33 0.41 138 SVI UTE

-3.44 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 tenms of structural and leakage integrity), confinn 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

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 24 of 30 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.

I-U. S. Nuclear Regulatory Commission 3F0305-03 Attachment A Page 25 of 30 13R Largest Indications For Structural and Leakage Integrity Type of Passed Condition OTSG & Tube Degradation &

NDE Length Monitoring for Number Indication a

.on i

(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 Crack (Freespan) 34% TW YES Single Axial 15S - 3.28 inch 0.31 A2-26 Crack (repn 1T E

Indication (SAI)

Single A13-67 Volumetric 15S + 0.03 inch 0.62 x 0.22 Indication (Within 15'" TSP) 16% TW (SVI)

Single Volumetric UTS + 0.21 inch 0.21 x 0.14 Indication (Secondary face of 27% TW YE (SVI)

Upper Tubesheet)

Single Volumetric 15S - 0.22 inch 0.18 x 0.17 YES A10-3 Indication (Within 15*' TSP) 23% TW A133Volumnetric 15S + 0.73 inch 0.44 x 0.22YS A133 Indication (SVI)

(Top of 15~' TSP) 48% TWYE 16-6 Single Axial

.15S - 5.09 inch 0.39 YES Indication (SAI)

(Freespan) 43% TW Volumetric LTS + 0.00 inch 0.38 x 0.23 B46-2 Indication (SVI)

(Top of Lower 57% TW YES T ubesheet Bi 14-1 Axial Crack 15S-1.62 inch 0.53 YES Indication (SAI)

(Freespan) 42% TW TSP TW Tube Support Plate Through-Wall

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment A Page 26 of 30 Condition Monitoring Plot Axial ODSCC/IGA at 3 Delta P, S/G's A and B 100 -

90 -

80 -

70 -

i ii 0

C.a-0waz 60 -

50 -

'40 -

(

B6-6 &

B114-1 A

---

l-7

-S/G A I

30 -

20 -

10 -

n Ir---------

A2-26 I

o S/G B 95-50 CM Lirit I

A2-26

' A2-26

'__ A2__! :*

-- -2 i

I v

0 0.5 1

1.5 2

2.5 3

3.5 4

4.5 NDE Length of Degradation, inches IFigure1

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 27 of 30 Condition Monitoring Plot Volumetric Degradation at 3 Delta P, S'G's A and B 100 -

90.

-lCM Line 80 -

l _-_

o S/G A oS/G B 70-

oB46.2 01-t o 30 -_klA75 O.A143-3 U~o40-z 30 -r I---

~,A77-50o&

8

A110-3 20 20

--- r----------.

c1A13-67 1 0 -

0.

0 0.2 0.4 0.6 0.8 1

1.2 1.4 1.6 NDE Length of Degradation, inches Figure 2

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 28 of 30 BACKGROUND October 6.2004 - NRC RAT Ouestion 5 Several tubes with sleeves were plugged for obstructions. Clarify the extent of the obstruction, the location of the obstruction, whether the tube/sleeve had adequate integrity (e.g., would the joints still have met all design criteria), identify when the sleeves were installed, the potential for the associated degradation mechanism to affect other sleeved tubes, and the technical basis for your conclusions. Also address your basis for not expanding the scope of the sleeve inspections based on these results.

November 24. 2004 - CR3 Response to Ouestion 5 The tubes plugged for obstruction were plugged because the probe could not traverse the upper tube end of the sleeves due to tube/sleeve end damage from previous loose parts. According to the Eddy-Current Analysis Guidelines, if a tube can not pass a probe through the entire length, the tube must be removed from service. There was no active degradation mechanism (rejectable indication) in the portions of the sleeve and tube examined. All rolled sleeve joints continued to meet their design criteria as determined by the Condition Monitoring (CM) evaluation. The Alloy 690 sleeves were installed in 1994. There is no basis for sample expansion since no rejectable flaws were identified.

Februarv 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 identfied 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 uipper 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 obstnrction and the technical basis foryour 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.

U. S. Nuclear Regulatory Commission Attachment A 3F0305-03 Page 29 of 30 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 - Sb)

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 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 3F0305-03 Attachment A Page 30 of 30 Cross Sectional View of an OTSG Tubing Sleeve at Crystal River Unit 3

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 3F0305-03 Attachment B Page 1 of 13 A-OTSG TUBE c u C-ROW

-TUBE 1

5 21 2

5 23 3

5 24 4

5 32 5

5 33 6

6 25 7

6 27 8

6 30 9

6 34 10 6

36 11 7

30 12 8

26 13 8

30 1

5 21 2

5 23 14 9

54 15 10 30 16 10 49 17 10 56 18 11 39 19 11 57 20 11 59 21 12 45 22 12 53 23 12 65 24 13 35 25 13 37 26 13 39 27 13 42 28 13 47 29 13 48 30 13 53 31 13 54 32 13 55 33 13 56 34 13 68 35 14 45 36 14 46 37 14 47 38 14 54 39 14 55 40 14 66 41 14 67 42 14 69 43 14 70 44 15 39 45 15 40 46 15 44 47 15 46 48 15 67 49 15 68 50 16 40 51 16 42 T.

- lROW TUBE

.COUNT. __

52 16 46 53 16 48 54 16 58 55 16 70 56 16 73 57 17 38 58 17 41 59 17 57 60 17 70 61 17 71 62 17 72 63 17 73 64 17 74 65 17 75 66 17 78 67 18 16 68 18 50 69 18 59 70 18 60 71 18 70 72 18 72 73 18 74 74 18 75 75 18 76 76 18 78 77 19 59 78 19 62 79 19 69 80 19 72 81 19 73 82 19 74 83 19 75 84 19 76 85 19 77 86 20 39 87 20 40 88 20 41 89 20 42 90 20 59 91 20 66 92 20 68 93 20 75 94 20 76 95 20 77 96 20 79 97 20 85 98 21 38 99 21 61 100 21 62 101 21 64 102 21 73 103 21 74 104 21 75

.TUBE.

ROW:

TUBE 105 21 76 106 21 77 107 21 81 108 21 83 109 21 85 110 22 8

111 22 33 112 22 52 113 22 63 114

• 22 65 115 22 66 116 22 72 117 22 74 118 22 76 119 22 78 120 22 82 121 22 85 122 22 86 123 22 89 124 23 50 125 23

.65 126 23 69 127 23 76 128 23 77 129 23 78 130 23 79 131 23 80 132 23 81 133 23 85 134 23 86 135 23 89 136 24 24 137 24 53 138 24 55 139 24 66 140 24

.68 141 24 69 142 24 77 143 24 79 144.

24 80 145 24 83 146 24 84 147 24 86 148 24 90 149 25 13 150 25 55 151 25 59 152 25

.66 153 25 67 154 25 78 155 25 79 156 25 80 157 25 81

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 2 of 13 A-OTSG

,TUBE COUN ROW TUBE 158 25 85 159 25 88 160 25 89 161 25 90 162 26 43 163 26 46 164 26 50 165 26 55 166 26 68 167 26 79 168 26 81 169 26 82 170 26 85 171 26 86 172 26 87 173 26 88 174 26 90 175 26 93 176 27 56 177 27 57 178 27 60 179 27 66 180 27 78 181 27 79 182 27 82 183 27 83 184 27 84 185 27 86 186 27 87 187 27 88 188 27 90 189 27 93 190 28 47 191 28 59 192 28 61 193 28 67 194 28 70 195 28 75 196 28 79 197 28 80 198 28 83 199 28 88 200 28 89 201 28 91 202 29 50 203 29 54 204 29 58 205 29 83 206 29 93 207 29 94 208 29 95 209 29 97 210 30 13 T-WBE R

TUBE-

,COUNT,___

211 30 33 212 30 49 213 30 51 214 30 55 215 30 57 216 30 59 217 30 70 218 30 71 219

.30 72 220 30 82 221 30 84 222 30 89 223 30 90 224 30 95 225 30 96 226 31 9

227 31 40 228 31 43 229 31 69 230 31 71 231 31 86 232 31 95 233 31 96 234 32 16 235 32 37 236 32 48 237 32 56 238 32 58 239 32 59 240 32 63 241 32 72 242 32 83 243 32 86 244 32 90 245 32 91 246

.32 94 247 32 96 248 32 97 249 32 101 250 33 15 251 33 51 252 33 65 253 33 93 254 33 97 255 33 100 256 34 59 257 34 83 258 34 90 259 34 93 260 34 95 261 34 96 262 34 98 263 34 99 TUBE COn lROW

'TUBE 264 35 60 265 35 61 266 35 73 267 35 74 268 35 82 269 35 90 270 35 95 271 35 96 272 35 99 273 36 76 274 36 78 275 36 86 276 36 91 277 36 95 278 36 97 279 36 98 280 36 99 281 36 100 282 36 103 283 36 104 284 36 105 285 36 106 286 36 107 287 36 109 288 37 61 289 37 76 290 37 83 291 37 88 292 37

.89 293 37 94 294 37 97 295 37 98 296 37

.99 297 37 100 298 37 103 299 37 106 300 37 109 301 37 110 302 38 63 303 38 77 304 38 84 305 38 87 306 38 95 307 38 96 308 38 98 309 38 99 310 38 100 311 38 101 312 38 104 313 38 105 314 38 109 315 38 111 316 38 115

I-U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 3 of 13 A-OTSG COUNt ROW TUBE 317 39 36 318 39 64 319 39 71 320 39 76 321 39 78 322 39 89 323 39 90 324 39 91 325 39 99 326 39 100 327 39 101 328 39 103 329 39 104 330 39 111 331 40 15 332 40 16 333 40 58 334 40 77 335 40 88 336 40 94 337 40 99 338 40 100 339 40 101 340 40 111 341 40 112 342 40 113 343 41 53 344 41 60 345 41 73 346 41 77 347 41 89 348 41 90 349 41 91 350 41 95 351 41 96 352 41 98 353 41 99 354 41 101 355 41 103 356 41 104 357 41 108 358 41 111 359 41 112 360 42 15 361 42 69 362 42 90 363 42 97 364 42 101 365 42 102 366 42 103 367 42 104 368 42 105 369 42 107 TUlir 1BE

• TBE ROW TUBE 370 42 114 371 43 56 372 43 61 373 43 62 374 43 80 375 43 83 376 43 88 377 43 90 378 43 91 379 43 92 380 43 93 381 43 96 382 43 98 383 43 99 384 43 100 385 43 101 386 43 107 387 43 109 388 43 112 389 43 114 390 43 115 391 44 60 392 44 62 393 44 65 394 44 89 395 44 91 396 44 93 397 44 94 398 44 97 399 44 100 400 44 101 401 44 102 402 44 103 403 44 105 404 44 106 405 44 107 406 44 109 407 44 110 408 44 114 409 45 66 410 45 88 411 45 90 412 45 91 413 45 92 414 45 93 415.

45 97 416 45 98 417 45 99 418 45 102 419 45 103 420 45 104 421 45 106 422 45 107 CTUE

ROW, TUBE CIOUNT

423 45 108 424 45 109 425 45

.112 426 45 114 427 45 117 428 46 60 429 46 66 430 46 69 431 46 76 432 46 77 433 46 86 434 46 87 435 46 88 436 46 96 437 46 103 438 46 109 439 46 113 440 47 12 441 47 62 442 47 78 443 47 88 444 47 92 445 47 93 446 47 94 447 47 98 448 47 101 449.

47 104 450 47 105 451 47 107 452 47.

117 453 47 119 454 48 61 455 48 63 456 48 69 457 48 74 458 48 90 459 48 91 460 48 99 461 48 110 462 48 112 463 48 118 464 49 51 465 49 63 466 49 82 467 49 88 468 49 95 469 49 99 470 49 100 471 49 104 472 49 106 473 49 110 474 49 111 475 50 58

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 4 of 13 A-OTSG TUBE OUNT ROW TUBE 476 50 88 477 50 99 478 50 110 479 50 111 480 50 112 481 50 115 482 50 116 483 50 119 484 51 24 485 51 57 486 51 59 487 51

• 76 488 51 93 489 51 94 490 51 95 491 51 97 492 51 103 493 51 107 494 51 108 495 51 110 496 51 111 497 51 115 498 51 116 499 51 118 500 51 120 501 51 121 502 52 59 503 52 62 504 52 64 505 52 91 506 52 101 507 52 107 508 52 115 509 52 117 510 52 120 511 53 108 512 53 115 513 53 116 514 53 117 515 53 120 516 53 121 517 53 122 518 53 123 519 54 49 520 54 92 521 54 101 522 54 109 523 54 113 524 55 10 525 55 77 526 55 83 527 55 96 528 55 110 COUNE ROW TUBE 529 56 57 530 56 80 531 56 108 532 56 118 533 57 5

534 57 7

535 57 85 536 57 87 537 57 96 538 57 97 539 57 112 540 57 113 541 57 124 542 58 7

543.

58 28 544 58 62 545 58 74 546 58 85 547 58 110 548 58 111 549 58 122 550 58 123 551 59 19 552 59 48 553 59 87 554 59 94 555 59 97 556 59 100 557 59 105 558 59 109 559 59 120 560 59 121 561 60 65 562 60 91 563 60 96 564 60 97 565 60 110 566 60 115 567 60 118 568 61 16 569 61 54 570 61 62 571 61 64 572 61 81 573 61 89 574 62 69 575 62 94 576 62 109 577 63 62 578 63 100 579 64 94 580 64

.103 581 65 24 TUBE couwrROW TUBE 582 65 49 583 65 56 584 65 59 585 65 101 586 66 60 587 66 62 588 66 63 589 66 79 590 66 95 591 66 97 592 66 98 593 66 102 594 66 103 595 66 109 596 67 20 597 67 50

.598 67

.54 599

67.

78 600 67 92 601 67 97 602 67 101 603 67 102 604 67 103 605 68 51 606 68 97 607 69 55 608 69 58 609 69 60 610 69 62 611 69 66 612 69 70 613 69 71 614 69 74 615 69 93.

616 69 103 617 70 50 618 70 51 619 70 55 620 70 57 621 70 113 622 71 51 623.

71 60 624 71 64 625 71 91 626 72 18 627 72 49 628 72 50 629 72 51 630 72 52 631 72 57 632 72 62 633 72 94 634 73 24

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 5 of 13 A-OTSG COTUB ROW..

TUBE 635 73 26 636 73 47 637 73 53 638 73 54 639 73 55 640 73 60 641 73 64 642 74 46 643 74 49 644 74 57 645 74 62 646 74 64 647 74 74 648 75 61 649 75 63 650 75 84 651 75 89 652 78 30 653 78 36 654 78 57 655 78 67 656 79 18 657 79 29 658 79 56 659 79 63 660 79 64 661 79 66 662 79 70 663 79 71 664 79 79 665 79 85 666 79 92 667 80 8

668 80 9

669 80 13 670 80 58 671 80 62 672 80 64 673 80 65 674 80 66 675 80 67 676 81 8

677 81 20 678 81 38 679 81 48 680 81 64 681 81 67 682 81 70 683 81 73 684 81 102 685 82 8

686 82 10 687 82 59 eOlrU ROW

-TUBE 688 82 60 689 82 63 690 83 10 691 83 49 692 83 50 693 84 52 694 84 73 695 85 4

696 85 6

697 85 8

698 85 45 699 85 47 700 85 48 701 85 86 702 86 9

703 86 71 704 86 72 705 86 73 706 86 75 707 87 62 708 87 70 709 88 66 710 89 79 711 90 46 712 90 59 713 91 65 714 91 70 715 91 72 716 91 82 717 91 83 718 91 84 719 91 85 720 91 87 721 91 109 722 92 61 723 92 67 724 92 80 725 92 114 726 92 122 727 92 123 728 93 92 729 93 107 730 93 108 731 93 111 732 93 116 733 93 117 734 93 121 735 94 73 736 94 97 737 94 98 738 94 113 739.

94 118 740 94 122

.TUBE COUN.ROW TUBE 741 94 123 742 94 125 743 95 66 744 95 69 745 95 74 746 95 82 747 95 110 748 95 112 749 95 117 750 95 119 751 96 56 752 96 64 753 96 109 754 96 115 755 96 116 756 97 62 757 97 66 758 97 72 759 97 99 760 97 109 761 97 113 762 97 114 763 97 116 764 97 117 765 97 122 766 98 60 767 98 64 768 98 66 769 98 85 770 98 94 771 98 114 772 98

-115 773 98 118 774 98 120 775 98 122 776 98

.123 777 99 72 778 99 78 779 99 81 780 99 97 781 99 110 782 99 115 783 99 116 784 99 122 785 99 123 786 100 9

787 100 64 788 100 65 789 100 74 790 100 77 791 100 78 792 100 80 793 100 96

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 6 of 13 A-OTSG TUBE COuNT l ROW T:UBE

.794 100 108 795 100 109 796 100 110 797 100 114 798 100 117 799 100 121 800 101 96 801 101 101 802 101 109 803 101 112 804 101 114 805 101 115 806 101 120 807 101 121 808 102 70 809 102 82 810 102 114 811 102 115 812 102 120 813 103 102 814 103 107 815 103 112 816 103 113 817 104 82 818 104 101 819 104 105 820 105 64 821 105 114 822 105 115 823 106 53 824 106 91 825 106 98 826 106 101 827 106 108 828 107 93 829 107 103 830 107 104 831 107 107 832 107 108 833 107 109 834 107 112 835 107 115 836 107 116 837 108 48 838 108 93 839 108 III 840 108 112 841 108 113 842 109 6

843 109 25 844 109 68 845 109 102 846 110 98

• TUBE COUNT1 ROW "TUBE 847 110 102 848 111 97 849 111 99 850 111 101 851 112 6

852 112 42 853 112 90 854 112 95 855 112 99 856 112 104 857 112 112 858 113 107 859 113 111 860 114 85 861 114 90 862 114 99 863.

114 104 864 114 105 865 114 106 866 114 108 867 114 109 868 114 110 869 114 111 870 115.

76 871 115 102 872

.115 109 873 116 88 874 116 92 875 116 99 876 116 101 877 116 105 878 116 106 879 116 108 880 116 109 881 117 96 882 118 96 883 120 72 884 120 73 885 120 79 886 121 69 887 121 71 888 121 73 889 121 83 890 121 96 891 121 98 892 122 71 893 122 79 894 122 80 895 122 99 896 123 80 897 124 78 898 124 96 899 125 95

-TUBE COUNT

'ROW,'

TUBE, 900 126 28 901 126 72 902 126 74 903 126 80 904 126 87 905 126 94 906 127 14 907 127 81 908 127 92 909 128 80 910 128 89 911 128 90 912 129 34 913 129 69 914 129 80 915 129 90 916 130 88 917 131 19 918 132 17 919 132 73 920 133 5

921 133 42 922 133 51 923 133 59 924 133 61 925 134 11 926 134 14 927 134 59 928 134 60 929 134 71 930 134 80 931 135 56 932 137 7

933 137 11 934 137 49 935 137 55 936 137 73 937 139 38 938 139 45 939 139 56.

940 139 57 941 139 58 942 139 66 943 140 9

944 140 58 945 140 60

.946 140 65 947 141 53 948 141 54 949 141 55 950 141 56 951 141 58 952 142 30

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 7 of 13 A-OTSG COUNT' ROW l TUBE TUNE ROW TUBE.

ROW l ETUBE 953 142 50 955 144 25 957 145 43 954 143 53 956 144 46

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 8 of 13 B-OTSG TUBE CROW ;TUBE 1

4 25 2

6 12 3

6 34 4

7 20 5

7 34

.6 7

44 7

7 47 8

8 11 9

8 12 10 8

23 11 9

12 12 9

15 13 9

18 14 9

48 15 10 15 16 10 19 17 10 34 18 10 49 19 10 52 20 11 9

21 11 11 22 11 12 23 11 20 24 11 21 25 11 23 26 11 51 27 12 16 28 12 29 29 12 36 30 12 55 31 13 19 32 13 20 33 13 56 34 14 19 35 14 20 36 14 30 37 14 66 38 15 8

39 15 13 40 15 16 41 15 19 42 15 21 43 15 35 44 15 45 45 15 49 46 15 58 47 16 11 48 16 20 49 16 24 50 16 25 51 17 10 52 17 13 TUBE ROW TUBE

-COUNT 53 17 15 54 17 22 55 17 25 56

17.

26 57 17 43 58 17 76 59 18 12 60 18 14 61

-18 16 62 19 6

63 19 12 64 19 18 65 19 47 66 19 60 67 20 31 68 20 55 69 21 20 70 21 27 71 21 50 72 22 12 73

.22 16 74 22 28 75 22 64 76 22 79 77 23 16 78 23 21 79 23 23 80 24 19 81 24 33 82

.24 84 83 25 5

84 25 5

85 25 11 86 25 24 87 25 28 88 25 29 89 25 58 90 26 93 91 26 94 92 27 6

93 27 10 94 27 19 95 27 85 96 27 95 97 28 4

98 28 6

99 28 7

100 28 30 101X 28 66 102 28 83 103 28 95 104 28 97

.TUBE

• COUTr ROW TUBE 105 29 7

106 29 7

107 29 94 108 29 96 109 29 97 110 30 8

i11 30 8

112 30 9

113 30 12 114 30 12 115 30 97 116 31 8

117 31 9

118 31 9

119 31 18 120 31 88 121 31 97 122 31 99 123 32 9

124 32 12 125 32 13 126 32 14 127 32 38 128 32 53 129 32 102 130 33 5

131 33 9

132 33 13 133 33 15 134 33 23 135 33 26 136 34 23 137 34 27 138 34 28 139 34 39 140 34 56 141 35 6

142 35 11 143 35 61 144 35 104 145 35 106

.146 36 102 147 36 104 148 36 105 149 36 107 150 37-7 151 37 12 152

. 37 103 153 38

.13 154 38 104 155 38 111 156 39 11

U. S. Nuclear Regulatory Commission

%t 3F0305-03 Attachment B Page 9 of 13 B-OTSG TUBETUB COUNT

- ROW TUBE 157 39 27 158 39 31 159 39 70 160 39 86 161 39 108 162 40 15 163 41 38 164 41 46 165 41 102 166 41 111 167 41 113 168 42 13 169 42 31 170 42 54 171 42 63 172 42 106 173 42 111 174 43 14 175 43 28 176 43 47 177 43 107 178 43 108 179 43 110 180 43 111 181 44 7

182 44 12 183 44 14 184 44 29 185 44 32 186 44 109 187 45 8

188 45 15 189 45 29 190 45 32 191 45 85 192 46 6

193 46 14 194 46 15 195 46 16 196 47 14 197 47 25 198 47 33

.199 48 14 200 48 31 201 48 34 202 48 50 203 48 62 204 49 9

205 49 16 206 49 17 207 49 23 208 49 58 209 49 59

.,,TUBE iCOUNT ROW TUBE 210 49 62 211 50 6

212 50 113 213 50 115 214 50 115 215 50 120 216 50 122 217 51 112 218 51 116 219 51

.117 220 51 117 221 51 119 222 51 120 223 51 122 224 52 7

225 52 13 226 52 30 227 52 53 228 52 110 229 52 111 230 52 114 231 52 116 232 52 120 233 53 5

234 53 119 235 53 120 236 54 6

237 54 16 238 54 108 239

54 114 240 54 115 241 55 4

242 55 25 243 55 47 244 55 115 245 55 121 246 55 122 247 55 123 248 55 123 249 56 5

250 56 5

251 56 17 252 56 26 253 56 53 254 56 55 255 56 118 256 56 121 257 57 5

258 57 13 259 57 16 260 57 71 261 57 122 262 57 125

.:TUBE

,.touwrB ROW

'.TUBE',

263 58 17 264 58 114 265 58 117 266 58 119 267 58 120 268 59 38 269 59 113 270 59 117 271 59 121 272 59 122 273 60 26 274 60 116 275 60 122 276 60 126 277 60 127 278 61 121 279 61 123 280 62 34 281 62 123 282 63 26 283 63 37 284 63 121 285 64 27 286 65 69 287 65 121 288 66 4

289 66 9

290 66 10 291 66 16 292 66 50 293 66 111 294 66 120 295 67 52 296 68 26 297 69 10 298 69 22 299 69 54 300 69 107 301 70 50 302 71 4

303 71 42 304 71 43 305 71 51 306 71 67 307 72 39 308 72 105 309 72 122 310 73 77 311 73 104 312 74 40 313 74 108 314 75 53 315 75 57

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 10 of 13 B-OTSG TUBE' -

RO.-.--I coUwT ROW TUBE 316 75 61 317 78 34 318 78 50 319 78 57 320 79 67 321 80 111 322 81 85 323 82 8

324 82 50 325 83 126 326 84 9

327 84 54

.328 84 59 329 85 9

330 85 41 331 85 53 332 85 58 333 85 86 334 86 8

335 86 13 336 86 55 337 86 60 338 87 7

339 87 107 340 88 9

341 88 49 342 89 7

343 89 7

344 89 8

345 89 9

346 89 21 347 89 41 348 90 7

349 90 8

350 90 11 351 90 13 352 90 20 353 92 7

354 92 8

355 92 21 356 92 24 357 92 126 358 93 6

359 93 7

360 93 7

361 93 20 362 93 30 363 94 21 364 94 29 365 97 7

366 97 8

367 97 122 368 98 6

TUBE ROW l TUBE.

COUNT 369 98 7

370 98 48 371 98 123 372 98 124 373 99 2

374 99 5

375 99 5

376 99 6

377 99 6

378 99 20 379 99 124 380 100 5

381 100 12 382 100 31 383 101 4

384 101 9

385 102 5

386 102 106 387 103 4

388 103 5

389 103 31 390 104 5

391 104 18 392 105 3

393 105 4

394 105 4

395 106 9

396 106 10 397 107 2

398 107 3

399 107 10 400 107 104 401 108 10 402 109 1

403 109 13 404 110 2

405 110 30 406 110 34 407 111 12 408 111 18 409 111 64 410 112 1

411 112 2

412 112 13 413 113 31 414 114 12 415 114 17 416 114 101 417 115 7

418 115 8

419 115 12 420 115 27

.421 115 32 TUE lROW TUBE.

COUNT' 422 115 40 423 115 43 424 116 9

425 116 27 426 116 92 427 117 18 428 117 25 429 117 26 430 117 73 431 117 77 432 117 87 433 117 88 434 117 89 435 17 102 436 117 103 437 118 17 438 119 26 439 119 32 440 119 33 441 119 40 442 119 87 443 119 88 444 120 8

445 120 13 446 120 26 447 120 30 448 120 36 449 120 65 450 120 100 451 121 18 452 121 23 453 121 25 454 121 26 455 121 28 456 121 31 457 121 38 458 121 87 459 121 89 460 122 5

461 122 12 462 122 17 463 122 26 464 122 29 465 122 32 466 122 36 467 122 38 468 122 57 469 122 61 470 122 76 471 122 87 472 122 88.

473 122 89.

474 123 6

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 11 of 13 B-OTSG OtUB ROW.

TUBE CbOUNT 475 123 6

476 123 10 477 123 11 478 123 17 479 123 18 480 123 22 481 123 28 482 123 30 483 123 37 484 123 74 485 124 16 486 124 26 487 124 29 488 124 98 489 125 4

490 125 6

491 125 11 492 125 19 493 125 23 494 125 29 495 125 39 496 125 69 497 125 73 498 125 82 499 125 83 500 125 95 501 126 10 502 126 25 503 126 26 504 126 30 505 126 31 506 126 62 507 126 63 508 126 70 509 126 71 510 126 72 511 126 79 512 126 83 513 127 10 514 127 15 515 127 19 516 127 24 517 127 34 518 127 37 519 127 62 520 127 63 521 127 75 522 127 80 523 127 83 524 127 85 525 127 89 526 128 6

527 128 8

Cot e'r ROW

TUBE, 528 128 9

529 128 10 530 128 12 531 128 17 532 128 18 533 128 19 534 128 23 535 128 24 536 128 37 537 128 69 538 128 78 539 128 81 540 128 84 541 129 6

542 129 10 543 129 12 544 129 20 545 129 23 546 129 27 547 129 29 548 129 68 549 129 70.

550 129 76 551 129 77 552 129 79 553 129 80 554 130 5

555 130 9

556 130 10 557 130 22 558 130 23 559 130 27 560 130 28 561 130 31 562 130 36 563 130 40 564 130 74 565 130 78 566 130 79 567 131 7

568 131 11 569 131 14 570 131 16 571 131 18 572 131 20 573 131 21 574 131 22 575 131 23 576 131 25 577 131 30 578

. 131 35 579 131 45 580 131 58 TUBE COUNT ROW

- TUBE 581 131 63 582 131 68 583 131

-74 584 131 77 585 131 78 586 131 84 587 132 9

588 132 13 589 132 14 590 132 23 591 132 26 592 132 28 593 132 29 594 132 30 595 132 33 596 132 46 597 132 55 598 132 61 599 132 71 600 132 73 601 133 8

602 133 9

603 133 12 604 133 13 605 133

.14 606 133 15 607 133 16 608 133 16 609 133 20 610 133 29 611 133 44 612 133 47 613 133 66 614 133 72 615 133 74 616 133 75 617 133 75 618 133 76 619 134 7

620 134 15 621 134 16 622 134 16 623 134 18 624 134 20 625 134 22 626 134 22 627 134 25 628 134 28 629 134 32 630 134 40 631 134 53 632 134 65 633 134 72

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment B Page 12 of 13 B-OTSG TUBE courT l ROW TUBE 634 134 73 635 134 74 636 135 12 637 135 13 638 135 14 639 135 15 640 135 16 641 135 23 642 135 26 643 135 27 644 135 33 645 135 53 646 135 59 647 135 69 648 135 70 649 135 72 650 136 4

651 136 8

652 136 14 653 136 19 654 136 21 655 136 27 656 136 27 657 136 40 658 136 46 659 136 56 660 136 61 661 136 65 662 136 70 663 136 71 664 136 72 665 136

-74 666 136 75 667 137 8

668 137 9

669 137 10 670 137 11 671 137 14 672 137 17 673 137 17 674 137 18 675 137 24 676 137 25 677 137 28 678 137 29 679 137 39 680 137 40 681 137 66 682 137 67 683 137 68 684 137 69 685 138 6

686 138 9

--TUBE L

cou r ROW l TUBEl 687 138 9

688 138 10 689 138 11 690 138 13 691 138 14 692 138 14 693 138 16 694 138 17 695 138 21 696 138 23 697 138 25 698 138 30 699 138 31 700 138 37 701 138 38 702 138 63 703 138 69 704 138 70 705 139 7

706.

139 10 707 139 12 708 139 12 709 139 13 710 139 14 711 139 16 712 139 17 713 139 18 714 139 22 715 139 26 716 139 27 717 139 30 718 139 37 719 139 41 720 139 43 721

. 139 48 722

.139 50 723 139 64 724 140 7

725 140 9

726 140 10 727 140 11 728 140 12 729 140 15 730 140 16 731 140 18 732 140 19 733 140 20 734 140 20 735 140 22 736

. 140 23 737 140 24 738 140.

33 739 140 36

.TUBE-Coumt lROW TUBE'.

740 140 47 741 140 48 742 140 56 743 140 60 744 140 63 745 141 7

746 141 7

747 141 9

748 141 9

749

. 141 10 750 141 14 751 141 17 752 141 18 753 141 18 754 141 19 755 141 19 756 141 27 757 141 33 758 141 X34 759 141 35 760 141 36 761 141 40 762 141 49 763 142 12 764 142 16 765 142

.17 766 142 17 767 142 18 768 142 21 769 142 26 770 142 27 771 142 32 772 142 33 773 142 34 774 142 45 775 142 47 776 142 49 777 143 7

778 143 11 779 143 12 780.

143 13 781 143 14 782 143 15 783 143 16 784 143 18 785 143 20 786 143 21 787 143 24 788 143 25 789 143 30 790 143 32 791 143 41 792 143 42

U. S. Nuclear Regulatory Commission a1 3F0305-03 Attachment B Page 13 of 13 B-OTSG TUBE RO'TB

. SC UT RO;W l tUBE-l 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 I LICENSE NUMBER DPR-72 ATTACHMENT C REVISION OF REFUELING OUTAGE 12 (12R),

MODE 4 REPORT, TABLE 3

U. S. Nuclear Regulatory Commission 3F0305-03 Attachment C 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 thel3R inspection and the preparation of the 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 Leaka e L Leakage Leakage Contribution at Contribution at Contemperat Total Leakage at OTSG Room Temperature Room Temperature Room Temperature From In-Service fom nd TW for Accident TEC Assuming 1

T Conditions Indications Based on 100% TW POD 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 Contribution at ge Total Leakage at OTSG ConTriuinat Room Temperature Room Temperature S Rfrom Undetected From In-Service 100% TW for Accident TEC Ass n

Indications Based on POD of 0.84 A

0.626 gpm 0.120 0.746 gpm B

0.625 gpm 0.169 0.794 gpm