DCL-11-053, One Hundred Eighty-Day Steam Generator Report - Sixteenth Refueling Outage

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One Hundred Eighty-Day Steam Generator Report - Sixteenth Refueling Outage
ML111160101
Person / Time
Site: Diablo Canyon Pacific Gas & Electric icon.png
Issue date: 04/21/2011
From: Becker J
Pacific Gas & Electric Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
DCL-11-053
Download: ML111160101 (11)
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Text

Pacific Gas and Electric Company James R. Becker Diablo Canyon Power Plant Site Vice President Mail Code 104/5/601

p. O. Box 56 Avila Beach, CA 93424 805.545.3462 April 21,2011 Internal: 691.3462 Fax: 805.545.6445 PG&E Letter DCL-11-053 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Docket No. 50-275, OL-DPR-80 Diablo Canyon Unit 1 One Hundred Eighty-Day Steam Generator Report for Diablo Canyon Power Plant Unit 1 Sixteenth Refueling Outage

Dear Commissioners and Staff:

Pursuant to Diablo Canyon Power Plant (DCPP) Technical Specification (TS) 5.6.10, a report shall be submitted within 180 days after initial entry into Mode 4 (Hot Shutdown) following completion of steam generator (SG) inspections performed in accordance with TS 5.5.9. The enclosure provides the 180-day report for SG inspections performed during the DCPP Unit 1 Sixteenth Refueling Outage.

There are no new commitments in this report.

If there are any questions or if additional information is needed, please contact John Arhar at 805-545-4629.

d ngd/4955/64003959 Enclosure cc/enc: Elmo E. Collins, NRC Region IV Michael S. Peck, NRC Senior Resident James T. Polickoski, NRR Project Manager Alan B. Wang, NRR Project Manager State of California, Pressure Vessel Unit cc: Diablo Distribution A member of the ~TARS (Strategic Teaming and Resource Sharing) Alliance Callaway

  • Comanche Peak
  • Diablo Canyon
  • Palo Verde
  • San Onofre
  • Wolf Creek

Enclosure PG&E Letter DCL-11-053 ONE HUNDRED EIGHTY-DAY STEAM GENERATOR REPORT FOR DIABLO CANYON POWER PLANT UNIT 1 SIXTEENTH REFUELING OUTAGE Pacific Gas and Electric Company (PG&E) performed eddy current inspections of the Diablo Canyon Power Plant (DCPP) Unit 1 steam generators (SGs) during the DCPP Unit 1 Sixteenth Refueling Outage (1 R16) in October 2010. The inspections were conducted in accordance with DCPP Technical Specification (TS) 5.5.9.

These were the first inservice inspections conducted on the Unit 1 SGs since they were replaced in the DCPP Unit 1 Fifteenth Refueling Outage. The four replacement SGs are Westinghouse Model Delta 54 (the same as the Unit 2 replacement SGs). The SG fabricator was ENSA, and the tube manufacturer was Sandvik.

Pertinent design features include:

  • 4444 tubes per SG
  • Tube nominal diameter of 0.75 inch outer diameter (OD)
  • Tube nominal wall thickness of 0.043 inch
  • The tubes are arranged in a triangular pattern of 96 rows and 119 columns, with a triangular pitch of 1.144 inches.
  • The tubesheet is 23.55 inches thick, including the 0.30-inch cladding.
  • The eight tube support plates (TSP) are stainless steel (Type 405) and are 1.125 inches thick. All TSPs have trefoil-shaped holes, produced by broaching.
  • In the U-bend, the tubes are supported by three sets of "V" shaped, rectangular stainless steel (Type 405) anti-vibration bars (AVB). The AVB assemblies stiffen the U-bend region of the tube bundle and facilitate proper tube spacing and tube alignment while mitigating tube vibration. The lowest, middle, and upper set of AVB assemblies supports the tubes in rows 8 through 96, rows 22 through 96, and rows 43 through 96, respectively.
  • The tubes are full depth hydraulically expanded within the tubesheet. The end of each tube is tack expanded using a urethane plug expansion process.
  • The tubes in rows 1 through 16 were full-length stress relieved following bending. Row 1 has the smallest U-bend radius of 3.25 inches.

Pursuant to TS 5.6.10, a report shall be submitted within 180 days after initial entry into Mode 4 (Hot Shutdown) following completion of an inspection performed in accordance with TS 5.5.9. The report shall include:

a. The scope of inspections performed on each SG,
b. Active degradation mechanisms found,
c. Nondestructive examination techniques utilized for each degradation mechanism,
d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,
e. Number of tubes plugged during the inspection outage for each active degradation mechanism, 1

Enclosure PG&E Letter DCL-11-053

f. Total number and percentage of tubes plugged to date, and
g. The results of condition monitoring, including the results of tube pulls and in situ testing.

PG&E's response to each item is provided below.

a. The scope of inspections performed on each SG.

TS 5.5.9.d requires inspection of 100 percent of the tubes in each SG during the first refueling outage following SG replacement. In 1R16, the first refueling outage following SG replacement, 100 percent of the tubes in each SG were inspected full length by bobbin coil.

Plus Point rotating probe inspections were conducted on the following bobbin indications reported in 1R16:

  • 100 percent of bobbin indication ("1") codes, which included DNI (dent/ding with possible indication), ADI (absolute drift indication), DSI (distorted support indication), distorted tubesheet indication (DTI), and NQI (non-quantifiable indication)
  • 100 percent of ~1 volt dents
  • 92 percent of ~1 volt dings
  • 100 percent of manufacturing burnish mark (MBM) signals
  • 100 percent of tube to tube proximity (PRO) indications (PRO indications are discussed in Section g.2 of this enclosure)
  • 100 percent of bobbin coil reported potential loose part (PLP) indications (PLP indications are discussed in Section g.2 of this enclosure)
  • 100 percent of bobbin coil reported MBM indications
  • 100 percent of through-wall indications reported by bobbin coil No degradation was reported, with the exception of one wear indication as discussed in Section b of this enclosure. The number of bobbin indications inspected with Plus Point is provided in Table 1.

Plus Point rotating probe inspections were conducted on the following indications that were reported in preservice inspection (PSI):

  • Three tubesheet locations where permeability variation (PVN) signals were reported in PSI. During PSI, Scotch-Brite was utilized in three tubesheet locations to remove, or diminish, a PVN signal. These tubesheet locations were inspected with Plus Point (mag bias) in 1R16.

The 1R16 bobbin and Plus Point exams did not report any PVN signal or any degradation in these locations.

  • One tubesheet bulge was reported in PSI. A tubesheet bulge in SG 1-4 Row 30 Column 44 (R30C44) at tube end hot (TEH) + 6.73 inches was 2

Enclosure PG&E Letter DCL-11-053 reported in PSI with a bobbin amplitude of 202.4 volts with an extent of about 1.25 inches. The location was Plus Point inspected in 1R16, and no degradation was reported.

b. Active degradation mechanisms found.

Tube wear at an AVB intersection was found on one tube. AVB wear was identified as a potential degradation mechanism in the 1R 16 Degradation Assessment. AVB wear in the DCPP Unit 1 SGs is the first reported AVB wear in Westinghouse Model 54 SGs. Because of this, PG&E informed the NRC of the AVB wear in a phone call on October 15, 2010.

c. Nondestructive examination techniques utilized for each degradation mechanism.

The tube wear indication was detected by the bobbin probe. Detection and depth sizing of wear at AVB structures using the bobbin probe is qualified in accordance with EPRI examination technique specification sheet (ETSS) 96004.1. Plus Point rotating probe inspection of the indication was also performed and confirmed the indication as single sided volumetric wear.

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications.

The location of the AVB wear indication described in sections band c above is in SG 1-3 Row 95 Column 57 (R95C57), at AV4, which is the outermost (third) AVB set. The tube is supported by three AVBs, so there are six potential AVB contact locations on this tube. The measured depth of the indication is 5 percent through-wall (TW) as sized by bobbin. The indication is volumetric, not linear. The tube wear indication was left in service because the 5 percent TW depth is less than the 40 percent TW plugging criteria defined in TS 5.5.9.c, and because SG tube integrity will be maintained until the next SG inspection based on performance of an operational assessment.

e. Number of tubes plugged during the inspection outage for each active degradation mechanism.

No tubes were plugged in 1R16.

f. Total number and percentage of tubes plugged to date.

No tubes are plugged in SG 1-1, SG 1-2, SG 1-3, and SG 1-4.

g. The results of condition monitoring (CM), including the results of tube pulls and in situ testing.

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Enclosure PG&E Letter DCL-11-053 There were no tube pulls or in situ testing performed in 1R16.

A CM evaluation of the SG tube bundles is performed to verify that the condition of the tubes, as reflected in the inspection results, is in compliance with the structural and leakage integrity requirements.

g.1 CM Assessment of Tube Wear During 1R16, tube wear at an AVB intersection was found on one tube. AVB wear was identified as a potential degradation mechanism in the 1R 16 Degradation Assessment. As evaluated below, CM is satisfied for both structural integrity performance criteria (SIPC) and accident-induced leak rate performance criteria (AILPC).

The tube wear indication was detected by the bobbin probe. Detection and depth sizing of wear at AVB structures using the bobbin probe is qualified in accordance with EPRI ETSS 96004.1. Plus Point rotating probe inspection of the indication was also performed and confirmed the indication as single sided volumetric wear, with an axial length of 0.48 inch and circumferential extent of 0.20 inch (35 degrees). The Plus Point voltage of the AVB wear indication is 0.27 volts.

The location of the AVB wear indication is in SG 1-3 Row 95 Column 57, at AV4, which is the outermost (third) AVB set. The tube is supported by three AVBs, so there are six potential AVB contact locations on this tube. The measured depth of the indication is 5 percent TW as sized by bobbin. The tube wear indication was left in service because the 5 percent TW depth is less than the 40 percent TW plugging criteria defined in TS 5.5.9.c, and because SG tube integrity will be maintained until the next SG inspection based on performance of an operational assessment.

Before 1R16, DCPP SIPC calculations were performed using the EPRI Flaw Handbook to develop DCPP tubing-specific limits for CM and operational assessment applicable to AVB wear. The limits were defined at the 95 percent probability and 50 percent confidence (95/50), at three times normal operating pressure differential (3dPNO), applying the regression equation of bobbin ETSS 96004.1. The CM limits for AVB wear were calculated to be 53.5 percent TW and 50.9 percent TW for Rows 39 through 96 and Rows 8 through 38, respectively.

eM was accomplished by conservatively assuming that the wear indication was 0.80 inch long, which is the bounding contact length between the AVB and tube for Rows 39 through 96. This length bounds the reported wear scar length of 0.48 inch. The AVB wear depth (5 percent TW) is well below the CM limit (53.5 percent TW), thereby demonstrating significant margin to the SIPC.

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Enclosure PG&E Letter DCL-11-053 In accordance with Section 9.6.3 of the EPRI Steam Generator Integrity Assessment Guidelines, Revision 3, for pressure loading of volumetric degradation that is predominantly axial in character with a circumferential extent that is less than 135 degrees (which is the case for AVB wear), the onset of pop-through and burst is coincident. Therefore, since the AVB wear satisfies SIPC at 3dPNO, leakage integrity at lower accident differential pressures (main steam line break) is also demonstrated.

The DCPP AILPC is satisfied if the total accident-induced leak rate from indications in all SGs, combined with operational primary-to-secondary leakage in all SGs, is less than or equal to 0.54 gpm (room temperature condition) at main steam line break differential pressure. There was no operational leakage in the prior cycle, and the 1R 16 AVB wear is not capable of accident-induced leakage as evaluated above. Therefore, the AILPC is satisfied for CM.

g.2 Assessment of Other Relevant Non-Degradation Indications g.2.1 PRO Indications During the PSI bobbin coil inspection of the DCPP Unit 1 SGs conducted in the factory, four tubes were reported with tube PRO signals in the U-bend region. These U-bend signals were attributed to the proximity of a given tube to another tube. Signals were reported in pairs of adjacent tubes in high rows in the same column at nearly the same axial location along the tube. This confirms that the signal pairs were related to each other in that each tube contributed to the signal in the other. Plus Point examination was conducted on these signals during PSI, confirmed the signals, and no degradation was detected.

During 1R16, these four tubes were examined with bobbin coil and the PRO signals were again reported. Plus Point inspections were conducted on the PRO locations and no tube wear was reported. Lead analyst review of the PSI and 1R16 signal characteristics concluded that there was no worsening of the condition compared to the PSI.

Table 2 provides a list of the tubes with PRO signals in 1R16, along with the location of the signals in the U-bend and the associated bobbin voltage. The signals occur in high radius U-bends.

Similar PRO signals were reported in Unit 2 during the PSI and 2R15. As discussed in PG&E Letter DCL-1 0-149, "Response to NRC Request for Additional Information Regarding the 180-Day Steam Generator Report for Diablo Canyon Power Plant Unit 2 Fifteenth Refueling Outage," dated November 24, 2010, the logical cause of the proximity indications is a 5

Enclosure PG&E Letter DCL-11-053 reduced tube-to-tube gap condition. A proximity signal can be generated on the bobbin coil if two tubes experience such a condition. A potential cause of a reduced tube-to-tube gap condition is manufacturing tolerances on a tube-to-tube basis, such as tolerances on U-bend profile and tube overall height.

A tolerance stack-up indicates that a reduced gap may occur but tube-to-tube contact is not possible. Manufacturing tolerances on the U-bend profile are slightly larger in higher radius U-bend tubes.

g.2.2 Potential Loose Parts Bobbin coil inspection of SG 1-3 detected PLP signals in adjacent tubes R62C44 and R63C43 at 18 inches above the hot leg top of tubesheet (TTS).

Because the signal was on both tubes, the condition was indicative of a loose part that was lodged. Subsequent Plus Point coil inspection of these locations confirmed the PLP indications, and no tube wear was reported. As a result of the PLP signals, the pre-lance visual examination plan was augmented to include this location and visually confirmed the PLP indication as a lodged wire. Lancing was then performed using a higher rock angle in an effort to dislodge the object. After this lancing effort, bobbin exam was re-performed on these tube locations and the PLP signals were no longer there.

Thus, the wire had been dislodged and removed by the lancing effort. As discussed in Section g.3.4, the wire was a detached bristle from a wire brush.

g.2.3 Tube Ding/Scratch During bobbin coil inspection of R96C60 in SG 1-1, a PLP signal was reported that appeared to be a foreign object or conductive material located about 7 to 11 inches from the cold leg TTS. A ding signal was present within the same signal formation. This tube is the outermost tube in the SG periphery, located directly in front of the 90 degree hand hole where a sludge lance suction foot is installed during lancing. The tube was bobbin retested for clarification (RCL). Further investigation noted that the time stamp on the eddy current testing (ECT) data indicated that sludge lancing was being performed during both acquisitions of the tube. Subsequent Plus Point and bobbin inspections of this location were performed from the cold leg, after the lancing equipment was removed, and confirmed that the foreign object signal was gone. However, the ding signal was still present. PSI bobbin coil data evaluation indicated no presence of any ding in the affected tube at this location. Therefore, the tube ding had to occur sometime after the PSI and prior to the first inspection at 1R16. The reported ding voltage is 0.68 volts, less than the reporting threshold required by the analysis guidelines.

Visual inspection of the tube was performed through the 90 degree hand hole and indicated small surface scratches on the affected tube. These scratches were not deep enough to be detected by either bobbin or Plus Point. Surface scratches are not a long term tube integrity or degradation issue for this tube.

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Enclosure PG&E Letter DCL-11-053 Industry experience with Alloy 600 tubing (susceptible material) has shown that OD-initiated intergranular attack can occur in deep scratches which create a stress riser where initiation could occur. Because the DCPP SG tubes are Alloy 690 thermally treated, which has significant resistance to service induced corrosion degradation, coupled with the shallowness of the surface scratch on the 00 of tube R96C60, there is no risk for initiation of corrosion in the future. There are no additional future inspection requirements to monitor this tube separately from the rest of the tube population.

The suspected cause of the tube scratch is that the sludge lance suction foot stainless steel elbow or hose clamp came in contact with the tube during lancing. Both the hose clamp and the elbow, because they are metal and conductive, would cause an ECT signal response if in contact with the tubes.

The suction foot hose clamp contains sharp edges that could cause a scratch/ding if contact with a tube occurs.

In order to perform an extent of condition, all of the other potentially affected tube locations in each SG (tubes that are adjacent to each 90-degree handhole) were reinspected by bobbin coil after the suction feet were removed from the SGs. No signals of tube dings or tube damage were reported. In addition, visual inspections of the potentially affected tube locations were performed through the 90-degree hand hole. Signs of small surface scratches were identified in some locations. However, as noted above, no signals of tube dings or tube damage were reported by ECT in .

these tubes.

g.3 Assessment of SG Secondary Side Integrity In accordance with EPRI SG Integrity Assessment Guidelines, Revision 3, CM shall include aspects of the secondary side inspection that affect tube integrity such as secondary side inspections performed, foreign material removed, and foreign material remaining in the SGs.

This section describes the CM of the SG secondary side, covering aspects of the 1R16 SG TTS secondary side cleaning, TTS visual inspections, and results achieved. The hand hole covers (4) on each SG were removed to facilitate this maintenance. The secondary manways were not removed and no upper internals inspections were conducted.

g.3.1 Pre-Lance Visual Inspection In all SGs, prior to sludge lancing, in-bundle visual inspections were conducted in the center 10 columns of the hot leg top of TTS region to determine the as found condition of the top of tubesheet. The exams showed a relatively clean tubesheet with no hard collaring. Small foreign objects 7

Enclosure PG&E Letter DCL-11-053 were noted in-bundle, which were subsequently removed by sludge lancing and observed in the sludge lance filters. No retrievals were attempted.

g.3.2 Sludge Lancing Sludge lancing was conducted in each SG. In SGs 1-1, 1-2, 1-3, and 1-4, the weight in pounds of sludge removed was 3, 3, 2.5, and 3, respectively.

Loose parts that were collected in the sludge lance trailer filter system were assessed. The objects are evaluated in Section g.3.4.

g.3.3 TTS Foreign Object Search and Retrieval (FOSAR)

After sludge lancing, in each SG, a TTS FOSAR exam was conducted. The exam consisted of the following elements:

  • Insertion of an in-bundle guide tube inspection system through the no tubelane handholes. A 5 mm video probe was inserted into a guide tube to perform in-bundle inspections. The in-bundle inspection scope was the center 10 columns of the hot leg TTS region, and columns 20, 40, 60, 80, and 100 in both legs.
  • Insertion of a wheeled cart with integrated camera through a hand hole and into the trough. The trough region is a peripheral 4-inch wide secondary side groove with a depth of 3.75 inches below the TTS, extends around the entire tubesheet, and has two drain holes that connect to the integrated blowdown line. The cart was pushed in the trough around the periphery of the tube bundle, inspecting 100 percent of the trough region and 100 percent of the outer periphery tubes. The camera inspected several rows into the peripheral tube region.

No loose parts or tube collaring were found by the in-bundle exams.

One small wire was found during the trough exams, located on the TTS in SG 1-1 between columns 112 and 113 in the periphery. The in-bundle guide tube system was reinserted and the wire was retrieved. The wire was 1 inch long with a diameter of 0.010 inch, with insignificant mass.

g.3.4 Tube Integrity Evaluation of Loose Parts Loose parts that were collected in the sludge lance filter strainer were assessed. The strainer contents were emptied after completion of each SG lancing operation. All foreign material was of small dimension and mass.

The total weight of the objects was less than 0.5 ounce, such that the mass of each individual object was insignificant. Most of the objects were metallic.

The objects included the following: wires, weld slag splatter, weld drop-8

Enclosure PG&E Letter DCL-11-053 through remnants, pieces of perforated sheet metal, metal strapping, machine curl fragments, and a bristle wire section of a brush. As discussed in Section g.2.2, a detached bristle wire was found lodged between two tubes, and was subsequently dislodged and removed as part of sludge lancing.

The exact sources of the foreign material could not be conclusively determined. Possible sources could be from SG fabrication, or could have migrated from upstream systems and entered the SGs through the 0.27 inch diameter holes in the feedring spray nozzles. The bristle wire section was likely left in the SG during fabrication, as it was too large to pass through the 0.27 inch diameter feedwater ring spray nozzles. The weld splatter and drop-through remnants are also fabrication related and likely originated from the SG downcomer annulus because weld drop-through material was identified in the downcomer annulus during factory examinations of the Unit 1 SGs. As discussed and evaluated in Westinghouse Letter LTR-NCE-OB-160, prior to shipping the Unit 1 SGs to DCPP, remedial actions were taken to cut and remove weld material that exceeded a threshold criteria.

The foreign objects that were in the Unit 1 SGs in Cycle 16 did not cause tube damage. This is based on the small mass of the objects, and the results of 1R 16 eddy current tube inspections. No tube degradation by loose parts was detected in 1R 16 based on 100 percent bobbin coil exam, which supports the conclusions that the loose parts in Cycle 16 were small and not capable of causing tube wear. PLP indications that were reported did not have any associated tube degradation based on Plus Point inspection, and PLP signals were confirmed to be removed based on follow-up ECT inspection of the locations.

The standard bobbin exam was augmented by the following additional analyses: (1) a special PLP analysis of the outer periphery tubes was conducted from the TTS to the first TSP to detect potential loose parts that could be missed by the normal analysis process; (2) a bobbin "turbo-mix" (three frequency) evaluation at the TTS was conducted in order to detect potential tube degradation that could be missed by the normal analysis process.

In conclusion, CM for secondary side integrity was satisfied because no loose part wear was detected by eddy current inspections in 1R 16, and the loose parts removed from the SGs had insignificant mass.

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Enclosure PG&E Letter DCL-11-053 Table 1 Number of 1R16 Bobbin Indications Inspected with Plus Point SG 1-1 SG 1-2 SG 1-3 SG 1-4 Total (Note 1)

DSI 0 0 0 1 1 DNI 13 15 18 4 50 DTI 0 0 0 1 1 ADI 5 7 2 3 17 NQI 3 2 7 14 26 MBM 3 7 3 2 15 PRO 2 0 0 2 4

%TW 0 0 1 0 1 DNT ~1v 0 8 5 2 15 DNG ~1v o (Note 2) 3 4 4 11 PLP 1 0 2 0 3 Note 1: The number of tubes with indications may be less than the number of indications.

Note 2: There was one ~1 volt ding in SG 1-1, located in the cold leg, and Plus Point inspection of the ding would have required a manipulator move. Since a smaller Plus Point inspection sample of ~1 volt dings was allowed per the Degradation Assessment, this ding was not Plus Point inspected as approved by Engineering.

Table 2 1R16 Bobbin Proximity Indications (PRO)

Bobbin Bobbin SG Row Col Elevation From - To (in.)

Volts Indication 11 90 78 0.35 PRO AV5 5.00 TO+40.02 11 92 78 0.47 PRO AV5 5.04 TO+41.41 14 93 47 1.71 PRO AV2 10.99 TO+41.39 14 95 47 1.81 PRO AV2 13.57 TO+47.89 10

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