ML080740050

Response to Request for Additional Information Related to 2006 Steam Generator Tube Inspections

ML080740050
Person / Time
Site:	Palo Verde
Issue date:	03/05/2008
From:	Mims D Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-05822-DCM/SAB/RJR
Download: ML080740050 (10)

Text

L A M A subsidiaryof Pinnacle West CapitalCorporation Dwight C. Mims Mail Station 7605 Palo Verde Nuclear Vice President Tel. 623-393-5403 P.O. Box 52034 Generating Station Regulatory Affairs and Plant Improvement Fax 623-393-6077 Phoenix, Arizona 85072-2034 102-05822-DCM/SAB/RJR March 05, 2008 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

Subject:

Palo Verde Nuclear Generating Station (PVNGS)

Unit 2 Docket No. STN 50-529 APS's Response to the NRC's Request for Additional Information Related to the Unit 2, 2006 Steam Generator Tube Inspections By letters dated February 9, and May 3, 2007, Arizona Public Service Company (APS) submitted information related to the 2006 inservice inspection examination conducted at PVNGS, Unit 2. These inspections were performed during the thirteenth refueling outage of Unit 2 that was conducted from September 30 to November 14, 2006. The Nuclear Regulatory Commission (NRC) staff reviewed the information provided and determined that additional information is required in order to complete their evaluation. The request for additional information was documented in NRC letter dated January 9, 2008. The enclosure to this letter contains the APS response to the NRC request for additional information.

This letter contains no new commitments. If you have any questions, please telephone Glenn A. Michael at (623) 393-5750.

Sincerely, DCM/TNW/RJR/gat

Enclosure:

APS Response to the NRC Request for Additional Information Related to the Unit 2, 2006 Steam Generator Tube Inspections cc: E. E. Collins, Jr. NRC Region IV Regional Administrator M. T. Markley NRC NRR Project Manager G. G. Warnick NRC Senior Resident Inspector for PVNGS A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• South Texas Project 0 Wolf Creek LA"A

Enclosure APS Response to the NRC Request for Additional Information Related to the Unit 2, 2006 Steam Generator Tube Inspections

Enclosure Response to Unit 2 SG Inspection RAI NRC QUESTION 1:

Section 3.0 of the May 3, 2007, SG Tube Inspection Report discusses the preoutage predictions from the Unit 2 cycle 13 (U2R13) operational assessment, which predicted a maximum through-wall (TW) depth for batwing-related tube degradation of 48 percent, based on a beginning-of-cycle value of 18 percent. The maximum measured batwing-related degradation in U2R1 3 was 49 percent. It appears that APS took the largest beginning-of-cycle measured indication and added a maximum or highly conservative growth rate to predict the maximum TW depth at the end-of-cycle. In consideration of the fact that the maximum measured TW depth was slightly larger than the predicted value, please discuss any corrective actions taken in response to this operating experience.

APS RESPONSE:

The approach described by the NRC staff is consistent with the methodology used by APS. This deterministic methodology is consistent with the requirements of the Electric Power Research Institute (EPRI) Steam Generator Integrity Assessment Guidelines for plugging based on sizing. The beginning-of-cycle (BOC) condition, adjusted for nondestructive examination (NDE) uncertainty, was combined with the maximum observed growth rate to project an end-of-cycle (EOC) condition. Two considerations were taken into account for Cycle 13:

1) Does the plugging criteria support a full cycle of operation? It should be noted that APS applied a conservative plugging criteria of 20% through-wall for this form of degradation. This is well below the 40% level specified by PVNGS Technical Specification 5.5.9(c) and ensures that degradation will not exceed structural integrity limits.

2) Do the actions, inspection, plugging, and assessment ensure that the performance criteria will be satisfied? As noted, the 49% flaw was slightly higher than projections.

The difference is within the uncertainty band of the eddy current technique. The allowable three times normal operating differential pressure (3NODP) structural limit at 95 percent probability at 50 percent confidence factor (95/50) for this form of degradation in the Unit 2 steam generators is greater than 67% through-wall. As such, the observed degradation was not a structural or leakage integrity concern.

The specific actions taken by APS in U2R1 3 to assess this form of degradation included:

• 100% full length inspection of the steam generator tubing (See response to Question 5).

0 Application of a 20% plugging criteria within the affected Batwing Stay Cylinder (BWSC) region of the steam generator, and Page 1

Enclosure Response to Unit 2 SG Inspection RAI Confirmatory inspection with Plus Point of all bobbin indications of potential tube wear within the BWSC region.

The results of the inspection were assessed for Unit 2 Cycle 14 (U2C14) and the structural and accident leakage performance were satisfied at 95/50 per the Operation Assessment performed in accordance with the EPRI guidelines.

NRC QUESTION 2:

Please discuss the scope and results of any secondary-side inspections, including foreign object search and retrieval. Please discuss the extent to which visual inspections were performed at possible loose-part indications identified through eddy current examinations and the results of these exams. Please discuss the extent to which loose parts were identified visually but not by eddy current examination.

APS RESPONSE:

To ensure the potential impact of loose parts is minimized; APS applies a combination of eddy current with visual inspection in critical regions of the steam generator. For the replacement steam generators at PVNGS, this includes a visual inspection at the tubesheet and the cold leg flow distribution plate (FDP) within the economizer (preheater) section of the steam generator. These inspections are performed even when sludge lancing is not conducted. This approach was applied in U2R13. The following is a description of the actions taken and findings from U2R13.

Foreiqn Object Search and Retrieval (FOSAR) - Hot and Cold Leg Tubesheet Region Tubesheet FOSAR was conducted using a power cart mounted with a remotely operated camera and retrieval tooling. A full 360 degree inspection of the tubesheet annulus region was performed. The cart was inserted into the Steam Generator through a tubesheet handhole and driven from one side 180 degrees around the periphery of the tubes to the opposite side in both hot and cold legs. The camera was able to see several rows into the tube bundle during the inspection.

As expected, little sludge was observed in either of the steam generator's tubesheet annulus regions. Several loose parts were identified. These are discussed below.

In SG 21 the FOSAR found 3 foreign objects. Two objects classified as sludge rocks (note: sludge rocks have never been observed to cause SG tube wear, however, APS identifies them and removes them when accessible) and one small wire. The sludge rocks were removed; however, the wire was not accessible for removal. The affected and adjacent tubes to the wire's location were inspected with Plus Point and there were no indications of tube damage. Eddy current testing (ET) could not detect the presence of the small wire. In accordance, with the PVNGS loose part program and the EPRI Page 2

Enclosure Response to Unit 2 SG Inspection RAI Steam Generator Integrity Assessment Guidelines, the results are documented for future tracking of this location during the U2R14 inspection.

In SG 22 the FOSAR found 8 foreign objects (4 sludge rocks and 4 pieces of flexitallic gasket). Three of the sludge rocks and 3 of the flexitallic pieces were removed (see Figure 1). The other 2 items were inaccessible. Eddy current testing confirmed that there was no wear at those locations.

FIGURE 1 OBJECTS REMOVED FROM SG 22 In addition to the visual inspection findings, in SG 22, ET examinations found wear at tube locations R165C124 (24%), R167C124 (36%) and R166C125 (10%) at the tubesheet elevation. These findings suggested that a loose part may have resided at this location. Both ET and FOSAR, however, indicated that the object is no longer present. Although the PVNGS Administrative Plugging Guidelines do not require plugging if the part is no longer present, APS elected to preventatively plug and stake all three tubes.

Also, based on the FOSAR and ET findings with respect to the flexitallic gasket material, APS expanded the ET program to perform 306 additional Plus Point inspections around the periphery where the gasket material was found, to ensure no Page 3

Enclosure Response to Unit 2 SG Inspection RAI other wear was present (see Figure 2). No additional loose parts or loose part wear was identified as a result of this expansion. The presence of the gasket material has been entered into the corrective action program (CRDR 2933699) for further evaluation.

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FIGURE 2 COLD LEG TUBESHEET POSSIBLE LOOSE PARTS (PLP) PLUS POINT EXPANSION Note: Shaded areas indicate expansion region Foreign Object Search and Retrieval - Flow DistributionPlate Periphery Flow Distribution Plate (FDP) FOSAR was conducted using a wall crawler mounted with two cameras. A full 180 degree inspection of the FDP annulus region was performed.

The crawler was inserted into the Steam Generator through the FDP handhole and transversed the entire length of the FDP around the periphery during several passes.

The camera was able to see several rows into the tube bundle during the inspection.

As expected, little sludge was observed on either of the steam generator's flow distribution plates. No loose parts were identified in either steam generator.

Eddy Current Identification of Possible Loose Parts In accordance with Nuclear Administrative Technical Manual (NATM) Procedure 73TI-9RC01, Steam GeneratorEddy Current Examinations, the PVNGS ET inspection is required to identify possible loose parts (PLPs). Additionally, the PVNGS Degradation Assessment and certain exam requirements of 73TI-9RC01 are designed to focus inspections and expansions in regions typical for loose parts, including periphery locations and at locations with previous loose part signals. Finally, a bounding inspection with a Plus Point probe is completed when PLPs are identified to evaluate the presence, extent and potential significance of any PLP and the potential challenges to tube integrity. Lack of any wear indicates that the conditions to produce wear are not present and the PLP indication is considered to have no impact to tube integrity. The indication is then logged and trended in future inspections. This approach is consistent with the EPRI Guidelines.

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Enclosure Response to Unit 2 SG Inspection RAI In SG 21, there were 2 new locations identified as PLP indications without wear calls.

One location was a periphery location at 07H + 18 inches (tubes R151C56, R152C57).

The source signal was small with no evidence of wear.

The second location was also at a periphery tube (R58C7) in the free-span above the 08C tube support. No wear was identified and no PLP indications were observed on any of the adjacent tubes. The location on tube R58C7 could not be accessed for visual confirmation, however, based on the strength of ET signal for the PLP indication, PVNGS elected to preventatively plug and stake the affected tube as a conservative measure.

Although new PLP calls were made on tubes R143C150, R142C151, R144C151, R143C152, R144C153, R144C155, R143C156 and R145C156 in the freespan above the 02C support, this condition was evaluated as an existing, non-wearing location.

For SG 22, all PLP calls were observed in the previous inspections (U2R12) and continued to show no evidence of wear. Per the PVNGS SG Program, trending of these locations will continue in U2R14.

NRC QUESTION 3:

Please discuss the extent to which rotating probes were used to inspect dents/dings or other locations such as small-radius U-bends or top-of-tubesheet locations. Please discuss whether any distorted dent indications were detected during the inspections.

APS RESPONSE:

There were no distorted dent/ding locations identified during this outage. A small number of dents (1 in SG 21 and 8 in SG 22) were examined with rotating probes and that data was compared with the Preservice Examination (PSE) and U2R12 data. No change in ET signal or distortions were identified. It should be noted that all dents over 0.5 volts were examined with rotating probes during the last (U2R12) outage as part of the corrective actions associated with the Cycle 12 leakage event (APS Letter 192-01142, dated June 1, 2004, Licensee Event Report 2004-001-00).

Rotating probes were utilized to examine all bobbin "I"code and PLP indications (see response to Question 2). The majority of these examinations were conducted to validate bobbin wear indications around the batwing stay cylinder area and to evaluate and bound bobbin PLP indications.

There were no planned inspections this outage to examine the tube sheet transition area or short radius U-bends with rotating probes. All short radius U-bends (Rows 1 through 3) are planned to be performed during the next outage (U2R14).

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Enclosure Response to Unit 2 SG Inspection RAI NRC QUESTION 4:

Please provide the cumulative effective full power months of operation for each refueling outage, or SG inspection outage, since the steam generators were installed.

APS RESPONSE:

Replacement Steam Generators Initial Installation - U2R1 1 (End of Cycle 11)

Cycle 12 -472.8 EFPD (1.30 EFPY)

Cycle 13 -496.1 EFPD (1.36 EFPY)for a cumulative total of 968.9 EFPD (2.66 EFPY)

Cycle 14 - In progress.

NRC QUESTION 5:

In Table 1, "Examination Summary," of the SG Tube Inspection Report, APS provides the number of exams performed. Appendix E, "Plug Lists, Plug Maps, Plug History,"

indicates that APS performed a bobbin exam of 100 percent of the tubes. Please clarify whether all tubes were examined full length (using a combination of bobbin or rotating probe techniques). It is not apparent from the NRC staff's review of Table 1 that all tubes were inspected in the "U-bend" region.

APS RESPONSE:

Table 1 "Examination Summary" documents the full length examinations and those examined for the straight sections of each of the hot and cold legs. Tubes were examined from either the hot or cold side to the top support on the other side. When added together, the examination extent from both the partial and full length examination is that all tubes were examined over their full length, except for the Row 1 through 3 short radius U-bends. These were examined from the tube end to the top support on both legs. Note 1 of the table was intended to clarify this.

The Appendix E table was intended to document that 100% of the tubes were tested over their full length with bobbin (with the exception of the short radius U-bends in Rows 1 through 3 as noted above).

It should be noted, that this inspection scope is significantly beyond the requirements of the EPRI guidelines. The required scope based on EPRI guidelines would have been a 100% inspection of the BWSC region (approximately 350 tubes per steam generator).

However, based on the new steam generator design, APS elected to inspect essentially 100% of the steam generator tubing with the exception of the Row 1-3 U-bends.

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Enclosure Response to Unit 2 SG Inspection RAI NRC QUESTION 6:

In Table 2, "Indication Summary," of the SG Tube Inspection Report, four volumetric indications were reported in SG 22. Since Note 2 of Table 2 states that this is the number of tubes and not indications, please discuss the nature of the volumetric indications in the tube that was not plugged and the basis for not plugging this tube.

APS RESPONSE:

Table 2 specifies that 4 tubes were identified with volumetric type indications (SVI).

One of these tubes had 2 SVI calls. A detailed list is given below showing the tube number and associated SVI locations and the last column represents a comment field.

The 3 plugged tubes were due to a loose part wear indication, but the loose part was not adjacent to the tube as denoted by the comment NO PLP (See also the discussion in response to Question 2). The remaining SVI was evaluated as a small tube manufacturing anomaly typically referred to as a LAP. This indication is very small, measures less than "0 %" and is below bobbin detectability on the required mix channel.

The indication was reviewed against the PSE and U2R12 data with no change being indicated.

SG - 22 SVI Calls Palo Verde 2 U2R13 PVNGS2 20061001 10/26/2006 08:24:27 IROW COL VOLTS DEG IND PER CH8 LOCH INCH1 INCH2 CRLEN BEGT ENDT PDIA PTYPE CAL L COM I

+ . . .. *.. . ...------. -.. .--. .--.. . ..-.----------------------

+-..--.-. . .. -.--. . . .. . - ..-- - -- ..--- - --. - .- --. .+

137 48 .65 97 SVI 12 P3 VSI 4.52 VS1 VS2 .580 ZPUFZ 61 HILAP I 165 124 1.56 70 SVI 24 P3 TSC .37 TSC TSC .600 ZPSHZ 74 CINO PLPI 167 124 2.78 68 SVI 36 P3 TSC .40 TSC TSC .600 ZPSHZ 74 CIHO PLPý S166125 .54 94 SVI 10 P3 TSC .03 TSC TSC .600 ZPSHZ 74 CdNa PLPI 166 125 .53 88 SVI 10 P3 TSC .59 TSC TSC .600 ZPSHZ 74 CINO PLPJ ROW COL

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VOLTS v ----- 8T DEG IND PER CR8 LOCH INCHI

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CAL L COM I NRC QUESTION 7:

In SG 22, the tube in row 39 column 86 was preventively plugged and stabilized, since it was next to a non-stabilized tube that was plugged for wear. Please discuss why this one tube was plugged and stabilized but other adjacent tubes do not appear to have been plugged and stabilized.

APS RESPONSE:

R37C86 was plugged during the baseline inspection due to a manufacturing dent/gouge detected above the second horizontal support on the cold leg side (2C). At that time, APS was not expecting BWSC area wear to be an active degradation mechanism in the replacement steam generators and, as such, the tube was not staked. This was consistent with the APS staking criteria.

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Enclosure Response to Unit 2 SG Inspection RAI In U2R13, R39C86 was found to have wear (6%). At that time, it had been determined that the BWSC wear had become an active degradation mechanism in the Unit 2 replacement steam generators. Rather than unplug and inspect R37C86, APS elected to preventatively plug and stabilize the next tube in the column (R39C86). This practice is in accordance with the stabilization criteria applied to the original steam generators and other Combustion Engineering (CE) designed steam generators susceptible to BWSC wear (e.g., APS Letter to the NRC 102-03931, dated May 9, 1997, Operational Assessment).

The approach taken in U2R13 is considered conservative based on evidence that the current wear mechanism is less likely to result in tube severance than the BWSC wear mechanism in the original steam generators. The BWSC wear in the original steam generators was impacted by a twisting of the batwing support resulting in a tapered wear scar, whereas the current wear appears to be classic flat bar wear caused by

'fluttering' of the support bar. It should also be noted that the 'front-line' tube in the adjacent column, R38C87 contains a stabilizer.

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