ML050730197

Ltr., FPL Conference Call Summary on SL2-15 Refueling Outage (Tac No. MC5538)

ML050730197
Person / Time
Site:	Saint Lucie
Issue date:	04/08/2005
From:	Moroney B NRC/NRR/DLPM/LPD2
To:	Stall J Florida Power & Light Co
Moroney B, NRR/DLPM, 415-3974
Shared Package
ML051030078	List: ML050730197 ML051030178 ML051030263
References
TAC MC5538
Download: ML050730197 (20)

Text

April 8, 2005 Mr. J. A. Stall Senior Vice President, Nuclear and Chief Nuclear Officer Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420

SUBJECT:

ST. LUCIE UNIT 2

SUMMARY

OF CONFERENCE CALLS WITH FLORIDA POWER AND LIGHT COMPANY REGARDING THE 2005 STEAM GENERATOR INSPECTION (TAC NO. MC5538)

Dear Mr. Stall:

On January 14 and January 17, 2005, the U.S. Nuclear Regulatory Commission (NRC) staff participated in conference calls with Florida Power and Light Company (FPL) representatives regarding the steam generator inspection activities at St. Lucie Unit 2 during the SL2-15 refueling outage. Enclosed is a brief summary of the conference calls prepared by the NRC staff. The materials provided by FPL in support of the calls are attached to this summary.

If you have any questions regarding this material, please contact me at (301) 415-3974.

Sincerely,

/RA/

Brendan T. Moroney, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-389

Enclosure:

As stated cc w/enclosure: See next page

ML050730197 Enclosure E: ML051030178 NRR-106 OFFICE PD II-2/PM PD II-2/LA EMCB/SC PD II-2/SC NAME BMoroney BClayton LLund by memo dtd MMarshall DATE 03/ 22 /05 03/ 22 /05 02/ 10/ 05 04/ 08 /05 Mr. J. A. Stall ST. LUCIE PLANT Florida Power and Light Company cc:

Senior Resident Inspector Mr. G. L. Johnston St. Lucie Plant Plant General Manager U.S. Nuclear Regulatory Commission St. Lucie Nuclear Plant P.O. Box 6090 6351 South Ocean Drive Jensen Beach, Florida 34957 Jensen Beach, Florida 34957 Craig Fugate, Director Division of Mr. Terry Patterson Emergency Preparedness Licensing Manager Department of Community Affairs St. Lucie Nuclear Plant 2740 Centerview Drive 6351 South Ocean Drive Tallahassee, Florida 32399-2100 Jensen Beach, Florida 34957 M. S. Ross, Managing Attorney David Moore, Vice President Florida Power & Light Company Nuclear Operations Support P.O. Box 14000 Florida Power and Light Company Juno Beach, FL 33408-0420 P.O. Box 14000 Juno Beach, FL 33408-0420 Marjan Mashhadi, Senior Attorney Florida Power & Light Company Mr. Rajiv S. Kundalkar 801 Pennsylvania Avenue, NW. Vice President - Nuclear Engineering Suite 220 Florida Power & Light Company Washington, DC 20004 P.O. Box 14000 Juno Beach, FL 33408-0420 Mr. Douglas Anderson County Administrator Mr. J. Kammel St. Lucie County Radiological Emergency 2300 Virginia Avenue Planning Administrator Fort Pierce, Florida 34982 Department of Public Safety 6000 Southeast Tower Drive Mr. William A. Passetti, Chief Stuart, Florida 34997 Department of Health Bureau of Radiation Control 2020 Capital Circle, SE, Bin #C21 Tallahassee, Florida 32399-1741 Mr. William Jefferson, Jr.

Site Vice President St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957-2000

JANUARY 14 AND 17, 2005, CONFERENCE CALL

SUMMARY

2005 STEAM GENERATOR TUBE INSPECTIONS ST. LUCIE, UNIT 2 DOCKET NO. 50-389 On January 14, and January 17, 2005, the Nuclear Regulatory Commission (NRC) staff participated in conference calls with St. Lucie, Unit 2, representatives regarding their 2005 steam generator (SG) tube inspection activities. A summary of the information provided during the calls is provided below.

St. Lucie Unit 2 has two Combustion Engineering Model 3410 steam generators. The mill annealed Alloy 600 steam generator tubes have an outside diameter of 3/4-inch and a nominal wall thickness of 0.048-inch. The tubes are explosively expanded for the full depth of the tubesheet at each end and are supported by a number of carbon steel lattice grid (i.e.,

eggcrate) tube supports, diagonal bars, and vertical straps.

On September 20, 2004, the NRC staff met with St. Lucie representatives to discuss the licensees plans for their November 2004 outage (which was subsequently rescheduled to January 2005). A summary of the meeting was provided on September 24, 2004 (ML042720215). On January 14, 2005, the staff held a conference call with St. Lucie Unit 2 representatives to discuss the results of their ongoing steam generator tube inspections. The discussion focused on the topics provided to the licensee in a letter dated January 12, 2005 (ML050110453).

In support of the January 14, 2005, conference call, the licensee provided three documents:

responses to the discussion points in the January 12, 2005, letter (Attachment A), a description of their in situ testing screening procedures (Attachment B), and the status of their eddy current testing (ECT) as of January 14, 2005 (Attachment C). Additional clarifying information, and information not included in the documents provided, is summarized below:

OXP is a code used to indicate that a tube has not been expanded for the full depth of the tubesheet. There are 21 OXP indications in steam generator A and 1 in steam generator B.

The inside diameter (ID) axial and circumferential indications and the outside diameter (OD) circumferential indications listed in the Confirmed Pluggable section on the ECT status sheets are located at the hot-leg expansion transition (or in the tubesheet region).

Rotating probe examinations were conducted to a depth of 13-inches below the top of the tubesheet and all service related degradation in this region will be plugged on detection. All crack-like indications will be plugged on detection. Wear indications are sized and left in service provided they are less than the technical specification plugging limit. If a tube has wear attributed to a loose part and the part is not removed, the tube is plugged; however, if the part is removed (or no longer present), the size of the flaw is ENCLOSURE

evaluated and the tube may be left in service. If a loose part is not removed and there is no tube wear, the need for plugging the tube(s) surrounding the part is evaluated on a case-by-case basis. If a loose part is known (or suspected) to exist and left in the steam generator, an engineering evaluation is performed to confirm that tube integrity will be maintained.

If in situ pressure testing needs to be performed, consideration will be given to adding the largest voltage indication and the longest indication to the list of test candidates. In general, the larger indications are ranked based on their structural and leakage integrity and consideration is given to adding these to the in situ candidate list even if they do not meet the predefined screening criteria.

Steam generator tube bundle flushing, tubesheet sludge lancing, and foreign object search and retrieval are scheduled to be performed.

Several axial indications were detected with a rotating probe that were not detected by the bobbin coil. These indications were detected when the rotating probe was pulled out of the tube after a higher elevation location with a bobbin indication was tested with the rotating probe. Since the rotating probe examination at the area of interest (i.e., the bobbin indication) was complete, the pullout speed of the rotating probe was greater than the qualification testing speed for the rotating probe. As a result, the required sampling rate (based on the qualification testing) was not achieved. The voltages from the rotating probe associated with these indications were small (0.1 to 0.3 volts with a maximum of 0.4 volts). The length of some of the indications, however, approached 2-inches. While inspecting 273 tube locations, an additional 78 indications were identified. Most of these indications are at the lower eggcrate supports and are found in tubes with other indications (many of which will result in the tube being plugged). At the time of this conference call, the licensee was still evaluating whether these indications (i.e., those not detected during the bobbin coil examination) were valid flaw indications (given that they were found with a nonqualified technique). In addition, they were evaluating whether these indications, if valid, were a result of an eddy current data analysis performance issue or an expected result from the detection probability associated with a bobbin coil (i.e., all flaws are not detected with a bobbin coil, especially smaller, less significant flaws).

At the end of the call, the licensee was asked to inform the staff if: (1) a tube leaked during an in situ pressure test or did not have adequate structural integrity, (2) a new degradation mechanism was identified (including an existing mechanism at a different location), (3) an engineering analysis was performed to support not expanding the inspection (e.g., for cracks in the U-bend region), (4) or if other unexpected results were identified (e.g., degradation of steam generator internals, large indication at the dent voltage where rotating probe examinations are performed, etc.).

In addition, the staff requested another conference call with the licensee to discuss their analysis of the potential indications found with a rotating probe and not detected with the bobbin coil. The call was tentatively scheduled for January 16, 2005, and subsequently rescheduled for January 17, 2005.

In support of the January 17, 2005, conference call, the licensee provided two documents: the status of their ECT as of January 17, 2005 (Attachment D), and several slides updating the staff on the status of their evaluation of the rotating probe indications that were not detected with the bobbin coil probe (Attachment E). Additional clarifying information, and information not included in the documents provided, is summarized below. The text is ordered based on the order of the presentation by the licensee (i.e., the order of the slides).

The information provided on Slide 7 is more recent than the information provided in the other slides in support of the call (as a result, the numbers on Slide 7 may not match those on other slides).

The wear indication that will be plugged measures approximately 42 percent through-wall.

The number of tubes to be plugged for flaws at the expansion transition are consistent with previous results.

No circumferential indications were found at tube supports.

Approximately 70 percent of the bobbin indications at tube supports are being confirmed as flaws with the rotating probe. This is consistent with past outages.

A MIZ-30 was used to acquire the eddy current data during the previous inspection outage, and a MIZ-70 was used during the 2005 outage. Although no significant changes were made to the testing parameters used during the 2005 outage (i.e., drive voltage, gain, etc.), rotating probe data was acquired at higher rotation speeds using the MIZ-70. Since the probe is pulled through the tube while the probe head is rotating, more eddy current data per unit length can be acquired when the rotation speed is increased (for a given pull speed). As the probe is withdrawn from a tube, it is pulled out at a faster rate than when it is used to inspect the location of interest, resulting in less data per unit length (i.e., less data per unit length than for the examination of the location of interest). Since the probe head was rotated at higher speeds with the MIZ-70, more eddy current data could be obtained (per unit length) as the probe was pulled out of the tube. The probe was pulled out of the tube at the same speed during the previous and current outages. As a result, more data were acquired when the probe was pulled out of the tube during the 2005 outage than in the prior outage.

The three letter eddy current code, RCL, stands for retest for clarification. The rotating probe is pulled through the location of interest at 1.3 inches per second (ips) and pulled out of the tube at a rate of 10 ips.

The analyst training and testing materials were improved by adding more eggcrate and lower voltage eggcrate indications to the testing material.

Circumferential primary water stress corrosion cracking was observed for the first time at the expansion transition. The indication in the one affected tube was present (based on hindsight) in the last inspection outage; however, it was not present in the data from the outage preceding the last outage. The amplitude of the indication in the previous outage was approximately half that observed during 2005.

Slide 11 contains the voltage distribution for both confirmed and nonconfirmed bobbin indications.

A few axial indications were found at the diagonal strap on the cold-leg side of the steam generator. This is the first time that axial indications were found at this location.

The indications were found with a bobbin coil and confirmed to be flaw-like with a rotating probe. These indications are not associated with a wear scar. As a result of finding these crack-like indications, the scope of the rotating probe examinations performed at cold-leg wear scars will be expanded (given the potential for cracking to occur in the cold-leg). At the time of the call, no cracks were found in wear scars this outage.

The 2005 bobbin voltage distribution for the distorted support indications (DSIs) is similar to that observed in 2003.

The in situ screening criteria for axial cracks are used to screen circumferential cracks, even though the screening criteria for circumferential cracks could be less restrictive.

Slide 18 contains a plot of bobbin indications confirmed as flaw-like with a rotating probe. Historically (prior to the 2005 outage), steam generator B had more degradation than steam generator A. The 2005 outage data suggests that the level of degradation in steam generator A is approaching that observed in steam generator B. Some of the indications that are below the in situ screening curves in the figures are profiled to further confirm the adequacy of the screening criteria.

Two hurricanes affected the plant during the last operating cycle. As a result of a vent cap being removed from a water storage tank (and subsequent water intrusion), the chloride levels in the secondary side of the plant became elevated. The plant was shut down at the time of this excursion. The chloride levels were reduced to within acceptable limits before the plant returned to power.

On Slide 20, all of the RCLs plotted were re-inspected with a qualified technique (i.e., at the appropriate pull speed). Two of the RCLs in steam generator A were greater than 0.5 volts and all of the RCLs in steam generator B were less than 0.5 volts. The trends in terms of the number of indications (DSIs and RCLs) at various axial elevations is similar. The bobbin indication associated with the RCLs is difficult to discriminate from the eggcrate signal.

On Slide 21, all of the RCLs plotted were re-inspected with a qualified technique. Data are still being added to this figure and it is expected that the upper tail of the DSIs will be shifted toward the RCLs (i.e., as more DSIs are profiled, it is expected that their burst pressures will be higher, shifting the upper part of the curve to the right).

Slides 22 through 26 are intended to provide the basis for which RCLs should be inspected with a qualified technique (i.e., at a rotating probe speed of 1.3 inches per second) to ensure that the most limiting RCLs are profiled and evaluated from a structural and leakage integrity standpoint. The variability on Slide 23 was not expected to be as high as measured, indicating that the voltages for the RCL indications using the nonqualified technique differ from the voltages obtained with the qualified technique

(i.e., analyst variability does not explain the differences observed in the voltage readings obtained at a pull speed of 10 ips from those observed at 1.3 ips). The mean and standard deviation of the plotted distribution are listed in the parentheses after the word NORMAL.

At the time of the call, approximately 163 RCLs had been identified in steam generator A and 129 in steam generator B.

The RCLs tend to be shallower than the DSIs confirmed with a rotating probe.

Slide 35 does not include RCLs or nonconfirmed DSIs.

Out of the 81 initial RCLs that were inspected at a qualified speed, all but 5 had voltages less than 0.35 volts. The RCLs with the three lowest calculated burst pressures had the highest RCL voltages.

The discovery of the RCLs may have resulted in additional DSIs being called by the bobbin coil.

All of the RCLs are axially oriented and at the eggcrates.

Slide 41 plots the end-of-cycle 14 (rather than end-of-cycle 15) depth distribution for steam generator B. The projected curve on this slide only includes the population of indications expected to be detected. The measured data points on this slide are for only bobbin DSIs that were confirmed to be flaw-like with a rotating probe.

Slide 42 plots the end-of-cycle 14 (rather than end-of-cycle 15) depth distribution for steam generator B. The projected curve on this slide is plotting the flaws that would be expected to be found with a rotating probe after the bobbin DSIs are removed from service (i.e., it illustrates the flaw sizes that would be found if the rotating probe was used to inspect the tubes following plugging of all bobbin confirmed DSIs).

Approximately 15 to 16% of the tubes inspected with a rotating probe are exhibiting RCLs.

At the end of the January 17, 2005, conference call, the NRC staff made the following observations:

The RCL indications were attributed to probability of detection associated with the bobbin coil. Rather than comparing the outcome of the multicycle computer algorithm to the depth/voltage of the RCLs in making this determination, a more direct comparison may be to look at the bobbin voltage associated with the 2005 RCLs and compare it to the 2003 bobbin voltage associated with the 2005 confirmed DSIs. The distributions should be similar. Since the bobbin data is used to determine the growth rates (based on look-back analysis) such an analysis should be consistent with the growth rate methodology.

For probabilistic analysis, both the number of indications and the size of the indications are important. The number of RCLs/DSIs should also be consistent with your models.

If the number of RCLs is larger than expected (i.e., the undetected population is underpredicted), additional inspections may be needed in 2005 to ensure condition monitoring limits are met in 2005 and for justifying a full cycle of operation.

A few of the indications are greater than 2-inches in length. It would be useful to assess how many, if any, of the indications are growing outside the eggcrate support.

It would be useful to evaluate all chemical excursions for the prior operating cycle to ascertain whether this could have resulted in the increased amounts (number and severity) of indications.

To confirm the adequacy of the screening criteria for determining when RCLs should be inspected with a qualified technique, it would be useful to look at the burst pressures associated with the RCLs to see if they support the 0.35 volt screening criteria (i.e., do any of the lower voltage RCLs have low burst pressures).

If the RCLs are a result of the probability of bobbin coil detection, then it should be confirmed that the distribution of RCL indications at various tube support elevations are consistent with the distribution of DSIs.

Following the January 17, 2005, conference call, the licensee provided the following additional information:

A freespan axial indication was reported in the square bend of steam generator B in the tube at Row 44 Column 130 (R44C130) approximately 0.66-inches above the diagonal bar on the hot-leg side of the steam generator (DHT+0.66). The maximum depth was 54 percent (based on +PointTM) and the length was 0.53-inch. The indication was reported during both the primary and secondary analysis of the bobbin data and was 1.3 volts in amplitude by the bobbin probe. The entire straight length of this tube was tested with a rotating probe (+PointTM) on the hot-leg side, and the adjacent square bends were tested at the same elevation. No additional indications were reported as a result of these inspections. This is the first observation of cracking in a square bend. In situ pressure testing was not required for this indication. This tube will be plugged. The bend radius of the square bends in Combustion Engineering steam generators are not considered to be low row or tight radius bends, as the bend radius is equivalent to approximately a row 10 U-bend. A history review shows the indication was present in the bobbin data at approximately one-third this amplitude in the April 2003 inspection. A precursor indication was also present in the November 2001 bobbin data at a lesser amplitude. Freespan cracking in Combustion Engineering designed steam generators has affected several units. The freespan cracking typically observed, however, has affected longer portions of a given tube with multiple indications along its length. It also appears to be deposit driven, which can degrade the probability of detection associated with such indications. St. Lucie Unit 2 data, however, is excellent quality with respect to interfering deposits, and the axial indication detected in the square bend in this inspection is a discrete single indication. The licensee is not aware of similar indications in the square bends of other Combustion Engineering designed steam generators.

A circumferential indication was reported in the tack roll of the tube in R49 C67 in steam generator B (approximately 0.32-inch above the hot-leg tube end). The indication was

reported during a diagnostic test of another indication (approximately 5.05-inches above the hot-leg top of tubesheet). The data acquisition continued through the entire depth of the tubesheet of this tube. Inspection of the lower portion of the tube near the tube end was not planned. According to a license amendment request (Florida Power and Light letter L-2004-245 dated November 8, 2004), inspection or plugging of flaws in this region of the tube in the tubesheet is not required. However, since this amendment is not approved at this time, this tube will be plugged. The location of this indication would not permit in situ pressure testing, and is considered unlikely to exceed the screening and structural analysis that would require such testing.

The only crack reported in the U-bend region of the low row tubes (i.e., rows 1 through

18) was associated with a ding and was identified during the 2001 inspection. The affected tube was in row 13. No additional cracks have been reported in the U-bend region of the low row (1-18) tubes at St. Lucie Unit 2. In the 2005 inspection, no cracks have been detected in the U-bend region of the low row tubes.

The total number of tubes scheduled to be plugged for all mechanisms during the 2005 outage is 1635 (798 in SG 2A and 837 in SG 2B). The approximate number of axial eggcrate indications and number of tubes plugged for this mechanism is shown below.

Approximately thirteen of these tubes also require plugging for other mechanisms at other locations.

Axial Eggcrate Indications SG 2A SG 2B Number of indications 1184 1266 Number of tubes to be plugged 779 820

STEAM GENERATOR TUBE INSPECTION DISCUSSION POINTS ST. LUCIE UNIT 2 - JANUARY 2005 (SL2-15)

The following discussion points have been prepared to facilitate the phone conference arranged with the licensee to discuss the results of the SG tube inspections to be conducted during the refueling outage. This phone call is scheduled to occur towards the end of the planned SG tube inspection interval, but before the unit completes the inspections and repairs.

The staff plans to document a brief summary of the conference call as well as any material that is provided in support of the call.

1. Discuss any trends in the amount of primary-to-secondary leakage observed during the recently completed cycle.

Reply - Leakage has been less than detectable throughout Cycle 14.

2. Discuss whether any secondary side pressure tests were performed during the outage and the associated results.

Reply - No secondary side pressure tests were performed during SL2-15.

3. Discuss any exceptions taken to the industry guidelines.

Reply - The only exception taken is for voltage normalization methodology for the bobbin probe technique. The methodology used at St. Lucie Unit 2 normalizes voltage at 5 volts using the 4 20% flat bottom holes on the calibration standard. This compares with normalizing voltage at 4 volts as recommended in the EPRI S/G Examination Guideline. The method used for St. Lucie Unit 2 predates the EPRI guideline and is view as conservative such that indications are measured at comparatively larger voltages. For example, an indication measuring 0.4 volts with the EPRI method would be measured at 0.5 volts using the St. Lucie Unit 2 method. The voltage normalization method has been maintained for St. Lucie Unit 2 due to the extensive inspection history and on-going degradation. The voltage normalization practice will be adjusted to the EPRI method when the St. Lucie Unit 2 S/Gs are replaced.

4. For each steam generator, provide a description of the inspections performed including the areas examined and the probes used (e.g., dents/dings, sleeves, expansion-transition, U-bends with a rotating probe), the scope of the inspection (e.g., 100% of dents/dings greater than 5 volts and a 20% sample between 2 and 5 volts), and the expansion criteria. Also, discuss the extent of the rotating probe inspections performed in the portion of tube below the expansion transition region (reference NRC Generic Letter 2004-01, Requirements for Steam Generator Tube Inspections).

Reply - For Inspection Scope and Inspection Probes please refer to slide 10 and 11 in the Power Point presentation provided to NRR in White Flint on September 20, 2004.

Expansion Criteria are summarized on slide 14 of this presentation.

Attachment A

The extent of the rotating probe inspections performed in the portion of tube below the expansion transition region will be in accordance with FPL Letter L-2004-245 dated 11/8/04, which submitted a license amendment request to define the depth of required tube inspections and clarify the plugging criteria within the tubesheet region of the original steam generators. FPL has selected a depth of 13 below the top of the tubesheet to ensure that the required length of 10.1 is examined (i.e., 10.1 below the top of tubesheet or the expansion transition, which ever is lower).

5. For each area examined (e.g., tube supports, dent/dings, sleeves, etc), provide a summary of the number of indications identified to-date of each degradation mode (e.g.,

number of circumferential primary water stress corrosion cracking indications at the expansion transition). For the most significant indications in each area, provide an estimate of the severity of the indication (e.g., provide the voltage, depth, and length of the indication). In particular, address whether tube integrity (structural and accident induced leakage integrity) was maintained during the previous operating cycle. In addition, discuss whether any location exhibited a degradation mode that had not previously been observed at this location at this unit (e.g., observed circumferential primary water stress corrosion cracking at the expansion transition for the first time at this unit).

Reply - Refer to the St. Lucie Unit 2 - EOC14 Steam Generator ECT Status Report Confirmed Pluggable Tubes section for a summary of the number of indications by damage mechanism.

Please refer to the separate file provided titled

SUMMARY

OF IN SITU PRESSURE TESTING SCREENING PROCEDURES FOR ST. LUCIE UNIT 2 for a discussion of how bobbin indications are screened to determine if detailed profile measurements are required to assess the need for in situ pressure testing. At the present stage of this inspection, diagnostic +Pt inspection of the bobbin I-Code indications remains largely incomplete and, therefore, the screening process continues. The attached bar charts provide a summary of bobbin voltages for indications requiring diagnostic +Pt inspection.

Historically, a total of 54 indications have been in situ pressure tested during prior inspections at St. Lucie Unit 2 and none of the test resulted in leakage or burst.

Further, no new degradation modes have been observed to date in this inspection.

6. Describe repair/plugging plans.

Reply - Tube plugging is expected to start on January 18th and end January 23rd.

7. Describe in-situ pressure test and tube pull plans and results (as applicable and if available).

As discussed above, indications are screened and, if necessary, in situ pressure tested in accordance with industry guidance.

8. Provide the schedule for steam generator-related activities during the remainder of the current outage.

9. Discuss the following regarding loose parts:

1. what inspections are performed to detect loose parts

2. a description of any loose parts detected and their location within the SG

3. if the loose parts were removed from the SG then describe indications of tube damage associated with the loose parts and the source or nature of the loose parts if known No secondary side inspections have been conducted at this time. A small number of foreign objects are being tracked from prior inspections and are evaluated for their impact on continued operation by engineering evaluation.

10. If steam generators contain thermally treated tubing (Alloy 600 or 690), discuss actions taken (if any) based on Seabrooks recent findings (Reference Information Notice (IN) 2002-21).

This question is not applicable. St. Lucie Unit 2 has Alloy 600 mill annealed tubing.

SUMMARY

OF IN SITU PRESSURE TESTING SCREENING PROCEDURES FOR ST. LUCIE UNIT 2 SCREENING METHOD The screening method integrates the procedures of EPRI In Situ Pressure Test Guidelines with integrity requirements for the Structural Integrity Performance Criterion and Accident Leak Integrity Criterion, as defined in NEI 97-06 and the EPRI Tube Integrity Guidelines.

The combination of the multiple requirements for screening is shown in Figure 1. This flowchart illustrates the general logic for screening NDE results for axial degradation.

Both voltage screening and screening based on as-measured indications are used to establish the candidate tube list for in situ pressure testing (ISPT) for burst and/or leakage testing. For indications with voltages less than 0.5 volts (Plus Point volts), no action is required for either burst or leak testing following the EPRI In Situ Pressure Test Guidelines.

The indications are also sized and evaluated to the structural and leakage performance criteria for condition monitoring using screening charts; example is shown in Figure 2.

Indications that plot below or to the left of the screening limit curves, i.e., Region 1 in Figure 2, do not require further evaluation. Indications that fall above or to the right of the burst screening limit curve, i.e., Region 2, will be subsequently detailed Plus Point profiled for depth versus length and evaluated for burst and leakage potential. Indications that fall to the left of the TW Structural Limit line and above the leak screening curve, Region 3 in Figure 2, will also be detailed Plus Point profiled and evaluated for leakage.

The evaluation for leakage potential for axial degradation involves three exclusive screens as shown in Figure 1: 1) probability of leakage screen set at 25%, 2) probability of pop through set at 10%, and 3) calculated leakage exceeding the testing limit (smallest measurable leak for the testing system). Indications with calculated leak probabilities or leak rates exceeding any one of these screen limits will require a leak test to be performed.

A similar screening logic diagram and charts have been developed for circumferential degradation.

SCREENING CHARTS The structural and leakage limits for each tube degradation mechanism are calculated prior to the outage and displayed in the form of screening charts like that as shown in Figure 2.

The observed indication sizes (as-measured) are plotted on these charts to establish the condition monitoring performance as NDE data are processed during the tube examination. These charts aid in the selection of indications for detailed Plus Point depth profiling and candidates for in situ pressure testing.

Attachment B

The screening charts include material, relational, and sizing uncertainties following EPRI Tube Integrity Guidelines. Material strengths are based on specified minimum properties for the tube material corrected for temperature at 600oF. Burst model relational uncertainty is evaluated at the lower 95% tolerance limit value. Depth sizing uncertainty is evaluated at the upper 95% tolerance limit value based on EPRI ETSS data. Correlations between maximum depth and structural minimum depth are derived from historical detailed profile data and the 95% lower tolerance value (or lowest observed) is used in construction of the curves. The treatment of uncertainty is conservative and exceeds the EPRI Integrity Guideline requirements.

The burst screening curve is based on maintaining 3xNOPD structural limit over the range of degradation sizes (maximum depth and length, or PDA). The length for a completely TW crack that would meet 3xNOPD is also computed and plotted as a vertical dotted line in each screening chart. This line delineates the general region where short deep cracks would not impact the 3xNOPD criterion for tube burst, but could possibly challenge the leakage criterion. Leakage screening is based on preventing ligament rupture under MSLB conditions (i.e., no pop-through) with a maximum indication depth not to exceed 85% TW. For degradations lengths of less than 0.1 inch, or 20 degrees, burst and leakage evaluation is not required following the current EPRI In Situ Pressure Testing Guidelines.

EXAMPLE OF SCREENING CHART FOR ODSCC AT EGGCRATE TUBE SUPPORTS An example of screening ODSCC indications detected at eggcrate tube supports is shown in Figure 3. This example is for St. Lucie Unit 2 outage in April 2003 and is for the B steam generator. Indications are plotted (measured maximum depth versus length) in two groups based on 0.5-volt screen limit. Subsequent evaluations of the detailed profiles and ISPT demonstrated that all indications met condition monitoring.

VOLTAGE DISTRIBUTION OF BOBBIN INDICATIONS Figure 4 and 5 provide a voltage distribution for bobbin indications in each S/G for indications reported in the April 2003 and January 2005 inspections. A cumulative probability distribution function (CDPF) is included in each graph.

2

No VM > 0.5 Volts ?

Yes Determine L and MD from +PT No L and MD Contained in Region 2 or Region 3

?

Yes Evaluate Detailed Evaluate Leakage Profiles with Potential with OPCON ProfilerAx OPCON ConMonAx No No No No MSLB MSLB AD > ADTHR-P ? POL > 25% POPT > 10% Leak Rate

?  ? > Test Limit

?

Yes Yes Yes Yes Proof Test Required Leak Test Required No Action Required Figure 1 ISPT Screening Logic Diagram for Axial Indications 3

Axial OD Corrosion ISPT Screening Limits 100 Leak Screening 90 Burst Screening Region 3 TW Structural Limit 80 70 Region 2 60 50 40 30 Region 1 20 10 0

0.0 0.2 0.4 0.6 0.8 1.0 1.2 Axial Degradation Length, L (in)

Figure 2 Example of Axial Indication ISPT Screening Chart 4

PSL 2 S/G B - Axial ODSCC at Eggcrates (April 2003) 100 Leak Screening 90 Burst Screening TW Structural Limit

<0.5 Volts 80 >=0.5 Volts 70 Maximum Depth, dmax (%TW) 60 50 40 30 20 10 0

0.0 0.5 1.0 1.5 2.0 2.5 Axial Degradation Length, L (in)

Figure 3 Axial ODSCC at Eggcrates for PSL-2 (April 2003) 5

Voltage Distribution for DSIs PSL-2 SGA 01/05 SL2-15 500 1.0 400 0.8 Number of DSIs 300 0.6 CPDF Number of DSIs 200 0.4 SL2-15 CPDF SL2-14 CPDF 100 0.2 0 0.0

<=0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 >2 Bobbin Volts Figure 4 - Voltage Distribution for Bobbin Indications SG 2A 6

Voltage Distribution for DSIs PSL-2 SGB 01/05 SL2-15 500 1.0 400 0.8 Number of DSIs 300 0.6 CPDF Number of DSIs 200 0.4 SL2-15 CPDF SL2-14 CPDF 100 0.2 0 0.0

<=0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 >2 Bobbin Volts Figure 5 - Voltage Distribution for Bobbin Indications SG 2B 7