W3F1-2014-0041, 180 Day Steam Generator Tube Inspection Report for the 19TH Refueling Outage

180 Day Steam Generator Tube Inspection Report for the 19TH Refueling Outage

ML14314A032
Person / Time
Site:	Waterford
Issue date:	11/06/2014
From:	Jarrell J Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
W3F1-2014-0041
Download: ML14314A032 (19)

Text

-¢Entergy Entorgy Operation., Inc.

17265 River Road Killona, LA 70057-3093 Tel 504 739 6685 Fax 504 739 6698 jjarrel@entergy.com John P. Jarrell Manager, Regulatory Assurance Waterford 3 W3F1-2014-0041 November 06, 2014 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555

SUBJECT:

180 Day Steam Generator Tube Inspection Report for the 1 9 TH Refueling Outage Waterford Steam Electric Station, Unit 3 Docket No. 50-382 License No. NPF-38

Dear Sir or Madam:

Attached is the 180 Day RF 9 Steam Generator Tube Inspection Report for Entergy Operations, Inc (EOI) Waterford Steam Electric Station Unit 3. This report is being submitted in accordance with Technical Specification 6.9.1.5 and provides the complete results of the Refueling Outage 19 Steam Generator Tube Inspection.

There are no new commitments contained in this letter.

Please contact John Jarrell Regulatory Assurance Manager at (504) 739-6685 if you have questions regarding this information.

Attachments

1. 180-Day Steam Generator Tube Inspection Report for the 1 9TH Refueling Outage Abb(

'j V

W3F1 -2014-0041 Page 2 cc:

Marc L. Dapas Regional Administrator U. S. Nuclear Regulatory Commission Region IV 1600 East Lamar Blvd Arlington, TX 76011-4511 NRC Senior Resident Inspector Waterford Steam Electric Station Unit 3 Killona, LA 70066-0751 U. S. Nuclear Regulatory Commission Attn: Mr. M. Orenak Washington, DC 20555-0001 Louisiana Department of Environmental Quality Office of Environmental Compliance Surveillance Division P. O. Box 4312 Baton Rouge, LA 70821-4312 RidsRgn4MailCenter@nrc.gov Frances.Ramirez@nrc.gov Chris.Speer@nrc.gov Michael.Orenak@nrc.gov Ji.Wiley@LA.gov American Nuclear Insurers Attn: Library Town Center Suite 300S 2 9 th S. Main Street West Hartford, CT 06107-2445 to W3FI-2014-0041 180-Day Steam Generator Tube Inspection Report for the 1 9 TH Refueling Outage

Attachment I to W3F1-2014-0041 Page 1 of 16 Refuel (RF) 19 180-Day Special Report During this period of reporting, Waterford 3 had one inspection. In April 2014, Entergy performed the first in-service inspections on the replacement steam generators. These generators were installed during the refuel outage eighteen (RF-18) and were placed inservice in January 2013.

Waterford 3 (WF3) Technical Specification (TS) 6.9.1.5 requires Entergy Operations to submit a 180 day report to the NRC that outlines the details of the steam generator (SG) tubing inspections that were performed during the reporting period. The report shall include:

6.9.1.5 A. The scope of inspections performed on each steam generator.

B. 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 degradation mechanism.

F. The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator.

G. The results of condition monitoring, including the results of tube pulls and in-situ testing.

to W3F1-2014-0041 Page 2 of 16 DESIGN The replacement steam generators for Waterford 3 are a Westinghouse Delta 110 design. The tube bundle consists of 8968 U-tubes fabricated from thermally treated Alloy 690. The tubing material complies with the requirements of ASME Section II SB-163, ASME Section III, NB-2000. The nominal outside diameter (OD) of each U-tube is 0.75 in. The nominal tube wall is.044 inches thick for tube rows 1 and 2 and.043 inches thick for all other tube rows (rows 3 through 138).

The ends of the tubes are expanded the full depth of the tubesheet and welded to the cladding on the tubesheet primary side.

The tubes are supported on the secondary side by eight (8) tube support plates.

The tube support plate material is stainless steel (ASME SA-240, Type 405). All tube support plates have trefoil-shaped holes arranged on a triangular pitch, produced by broaching, to reduce the potential for tube dry out and chemical concentration in the regions where the tubes pass through the tube support plates.

Five (5) sets of anti-vibration bars (AVBs) are installed to provide support for the U-bend region of the tube bundle. The anti-vibration bar assemblies stiffen the U-bend region of the tube bundle and facilitate proper tube spacing and tube alignment while mitigating tube vibration. The first set of anti-vibration bar assemblies are installed into the U-bend to a depth of, and including, row five (5). The second set of anti-vibration bar assemblies are installed into the U-bend to a depth of, and including, row eighteen (18). The third set of anti-vibration bar assemblies are installed into the U-bend to a depth of, and including, row thirty-four (34). The fourth set of anti-vibration bar assemblies are installed into the U-bend to a depth of, and including, row fifty-five (55). The fifth set of anti-vibration bar assemblies are installed into the U-bend to a depth of, and including, row eighty-four (84), except for one special bar that is inserted to row eighty-three (83). Each anti-vibration bar assembly consists of a "V" shaped, rectangular bar of stainless steel (ASME SA-479, Type 405) and two (2) end caps of thermally treated Alloy 690 (ASME SB-166, Alloy UNS N06690). Each end of each anti-vibration bar assembly is secured to the U-bend peripheral retaining rings of thermally treated Alloy 690 (ASME SB-166, Alloy UNS N06690) by welding the corresponding end cap with SFA-5.14 CL. ERNiCrFe-7 weld metal. Twenty (20)

U-shaped retainer bars of chrome plated, thermally treated Alloy 690 (ASME SB-166, Alloy UNS N06690) are installed between several U-tubes. Both ends of the U-shaped retainer bar are welded with SFA-5.14 CL. ERNiCrFe-7 weld metal to the anti-vibration bar retaining ring of each anti-vibration bar set. These retainer bars provide support to the anti-vibration bar assemblies during seismic and postulated steam line break loading conditions.

to W3F1-2014-0041 Page 3 of 16 FIGURE 1 Waterford-3 Delta 110 Steam Generator Design

Attachment I to W3FI-2014-0041 Page 4 of 16 Table 1 Waterford 3 Steam Generator Primary Inspection Plan SG Inspection Sequential Notes Cycle Cumulative Period Inspection Outage Year EFPM EFPM EFPM Period RF19 2014 14.6 14.6 N/A N/A First ISI RF20 2015 17.3(est) 31.9(est) 17.3(est)

First No I

I__II__

IInspection RF21 2017 17.3(est) 49.2(est) 34.6(est)

First Inspect Waterford RSG Tubesheet Map Base Tubes

• Stayrods 140 130

• 130 0..0.

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to W3F1-2014-0041 Page 5 of 16 A. The Scope of Inspections Performed on Each Steam Generator.

The initial in-service inspection plan included:

0 100% 0.610 inch bobbin coil inspection full length Rows 3 and above; 100% Rows I and 2 straight legs only 100% 0.590 inch mid-range +Pt Rows 1 and 2 U-bends from top TSP to top TSP 100% bobbin coil inspection Rows 1 and 2 U-bends from top TSP to top TSP at 12 ips (1)

• +Pt inspection of hot and cold leg TTS +/- 3 inches for detection of PLPs (periphery, tube lane, central tube void region)

• +Pt special interest testing as necessary including:

Any freespan bobbin I-code

> Any bobbin I-code at a TSP intersection

- Any AVB wear indication >1 5%TW based on bobbin coil analysis

> Possible loose parts/foreign object (PLP) signals including all immediately surrounding tubes until PLP signals are no longer reported (i.e., "boxing")

> Freespan dings >5V (2)

TSP dents >2V (3)

> Bulge (BLG) with preferential selection based on bobbin coil 600 kHz signal amplitude >18V

> Over-expansions (OXP) above the TTS o Pancake coil RPC special interest testing of bobbin PRX signals >1V

• Channel head bowl visual inspection per NSAL-12-1 including divider plate to channel head juncture (1): The 0.610 inch diameter bobbin probe will be attempted first. If tangent point noise levels are judged excessive, the 0.600 inch diameter bobbin probe can be utilized.

(2): SCC at freespan dings is judged non-relevant, similarly, freespan wear is judged non-relevant in the absence of foreign objects. The recommended +Pt inspection of >5V dings is performed to satisfy the full length testing requirement and to establish that foreign objects are not present.

(3): As no industry qualification for the detection of wear in dented TSP intersections is available, the +Pt inspection of dented TSP intersections is performed to establish that no wear is present.

to W3F1-2014-0041 Page 6 of 16 Primary Bowl Examinations The hot leg and cold leg primary side channel heads in each SG were visually inspected during the current outage. The inspections were prompted by industry experience at two plants that identified wastage of the carbon steel channel head pressure boundary as result of a breach in the channel head stainless steel cladding and/or in the divider plate to channel head cladding. The visual inspection results did not identify any anomalies or degradation of the cladding or welds.

AVB position evaluation were completed during the W3 RSG preservice inspections in 2012. The AVBs are uniformly installed in all of the columns in accordance with the design.

to W3F1-2014-0041 Page 7 of 16 The Secondary Side Inspection and FOSAR:

The inspection plan was developed to specifically address the areas of potential degradation due to recent industry inspection results. These included:

a. FOSAR of annulus region at the top of the tubesheet

b. Visual inspections of the upper steam drum and support structures

c. Visual inspection of the feed ring, spray nozzles and support structures.

Steam drum region inspections performed at RF19 were quite extensive and included; Steam outlet nozzle venturis Mid-deck region Primary separator ID above swirl vanes Lower deck region Spray cans Feedring ID region Feedring structural supports Thermal sleeve to nozzle/pipe welds Sludge collector internals Visual inspection of the upper steam drum components listed above identified no anomalies. As the moisture separation equipment is constructed using carbon steels with measurable chrome content or nickel-based alloys, erosion/corrosion of these components is not expected.

Visual examination of the exterior of the spray cans and the ID of the feedring showed no foreign material present. The diameter of the holes in the spray cans is slightly less than the minimum tube-to-tube dimension in the pitch direction of 0.28 inch, and can effectively act as foreign material screens.

Due to observed feedwater pipe vibrations during Cycle 19 Entergy selected to perform a visual inspection of the feedring structural supports and thermal liner welds. No anomalies were noted.

Visual inspection of the inside of the sludge collector segments showed deposit accumulation, although attempts to measure the height of the deposit pile were not performed.

The general condition of the secondary side components showed a light magnetite coating, which is expected, and a positive indicator that local high velocity conditions are not present.

to W3F1-2014-0041 Page 8 of 16 At the TTS, many tube-to-tubesheet juncture locations showed an accumulation of deposit with oxidation of the deposit. As magnetite is primarily composed of iron, exposure to atmospheric conditions can result in general oxidation (rust).

to W3F1-2014-0041 Page 9 of 16 B. Degradation Mechanisms Found.

Non-Service Induced Wear at AVBs in SG 31 and 32 (PSI)

Table B Fabrication Indications SG Dings*

Proximity Bulge WAR 31 665 90 3

10 32 32 116 3

9

• Note - Dings were called with a threshold of_> 1.0 volts Table B-2: PSI Indications of Tube Wear SG31 SG32 Row Col Locn

%TW Row Col Locn

%TW 68 159 A07 3

46 5

A03 4

63 160 A04 5

46 5

A03 4

63 160 A07 4

63 160 A04(+)

1 56 161 A04 3

63 160 A04(-)

2 58 161 A04 3

63 160 A07 2

60 161 A04 3

51 164 A08 4

62 161 A04 4

46 165 A03 2

62 161 A07 3

46 165 A08 2

51 164 A03 2

46 165 A08 I

51 164 A08 2

1 Table B-2 identifies those tubes in each SG reported to contain wear-like indications in the PSI. These indications were reported from +Pt examination as part of the effort to monitor tube-to-AVB gaps. The initial bobbin analysis did not report these indications as flaw-like for all locations. In several cases the bobbin report was performed to provide a matching signal for the +Pt indication. As noted in Table B-2, the maximum reported indication depth is 5%TW.

At RF 9 no appreciable change in the bobbin coil signature was noted for these locations, suggesting little or no further advancement of the degradation, and that the mechanism is not associated with traditional tube vibration mechanisms. As a result, Entergy reclassified these indications as indication not reportable (INR) during the RF19 inspection.

The only Service Induced degradation was wear at AVB in SG31 and SG32.

These indications are provided in Table D-1 for SG31 and Table D-2 for SG32.

There were four tubes preventatively plugged (PTP) in SG32 which enables the Operational Assessment to successfully analyze a 2 cycle Operating Interval.

to W3F1-2014-0041 Page 10 of 16 C. Nondestructive Examination Techniques Utilized for Each Degradation Mechanism.

Summary of SG Tube Degradation Mechanisms and Inspection Requirements: Detection Information: Waterford RF19 Degradation EPRI Detection Appendix H Mechanism Location Probe Type Technique Variable or I Spection Pan ISheet (1)

Qualified Sample Plan Plan Existing Degradation Mechanisms:

Wear (not service AVBs 0.610 inch ETSS Phase Yes 100% full length No Expansion induced)

I I Bobbin 96004.1 Potential Degradation Mechanisms Wear (service AVBs, TSPs 0.610 inch ETSS Phase Yes 100% full length, both No Expansion induced)

Bobbin 96004.1 SGs (detection)

+Pt ETSS Phase Yes 100% bobbin No Expansion (confirmation) 21998.1 indications Volumetric Freespan 0.610 inch Mag ETSS 128413 Phase Yes 100% full length, both +Point boxing-in Degradation (not Bias Bobbin SGs to bound PLPs corrosion related) and General Tube 0.610 inch +Pt ETSS Phase Yes Any freespan bobbin No expansion Signal Identification 21998.1, I-code, any I-code at ETSS 128425 tube supports PLP Identification TTS (both 0.610 inch 3-coil ETSS Phase Yes Sampling of

+Point boxing-in and General Tube legs)

+Pt 21409.1 peripheral tubes, Hot to bound PLPs Signal Identification and Cold Leg TTS +/- and indications 3 inches

Freespan, 0.600 inch or ETSS 128413 Phase Yes (2) 100% full length, both No Expansion including U- 0.610 Bobbin SGs bends General Signal Row 1 and 0.580 inch U-ETSS Phase Yes 100% Row 1 and 2 No Expansion Identification 2 U-bends bend +Pt 96511.2 from 08H to 08C Potential All 0.610 inch Mag ETSS Phase Yes 100% full length, 3 No Expansion Manufacturing Buff Bias Bobbin 96010.1 SGs Marks 0.580 or 0.610 ETSS Phase Yes

+Point MBIs No Expansion inch +Pt 21998.1 (1): The Acquisition and Analysis Technique Sheets (ACTS and ANTS) detail the plant specific guidelines for application of the EPRI ETSSs.

(2): Existing bobbin coil qualification database does not include U-bend regions. This program is performed to establish a baseline condition for future bobbin inspection of Row 1 and 2 U-bends.

Attachment I to W3F1-2014-0041 Page 11 of 16 Summary of SG Tube Non-flaw Signal Disposition Categories Applicable Inspection: Waterford 3 RF19 Degradation Probe EPRI Detection Inspection Expansion Mechanism Location Type & No.

Technique Variable Sample Plan Plan Mechanism

__ocation

_Type_&_No.

Sheet Resolution for Classification of Extraneous Indications Dings, Dents, All 0.610 inch Mag ETSS 128413 Phase 100% full length, Expansion PVN Bias Bobbin Coil both SGs according to degradation 0.610 inch +Pt; ETSS 22401.1 Phase 100% Dings mechanism 0.610 inch Mag

>5V, Dents, 2V, confirmed Bias +Pt for PVN PVN >1V as needed Anomalous Tubesheet 0.610 inch 3-coil ETSS 20511.1 Phase BLG above TTS, Tubesheet expansion

+Pt DTI in tubesheet Signals joint Tube-to-Tube U-bends 0.610 inch Mag N/A, see Vertical 100% full length, None Proximity Bias Bobbin Coil Reference (A) maximum both SGs voltage and phase 0.580 inch N/A, see Vertical Bobbin PRX >IV None pancake coil Reference (A) maximum voltage and phase Tube-to-AVB U-bends 0.580 inch N/A, see Peak-to-Peak None Sampling may Proximity pancake coil Reference (A) voltage be performed based on inspection results A)

LTR-SGMP-12-42, Revision 1, "Waterford RSG Tube-to-Tube and Tube-to-AVB Proximity Testing Summary," July 2012

Attachment I to W3F1-2014-0041 Page 12 of 16 D. Location, Orientation (if linear), and Measured Sizes (if available) of Service Induced Indications.

Table D-1 "SG31 Service Induced Indications-Wear at AVBs" SG ROW COL VOLTS PER LOCATION COMMENT 31 57 74 0.11 7

A07

-0.05 31 99 76 0.15 8

A08 0

31 83 78 0.19 10 A07 0.11 31 68 83 0.19 9

A07 0.11 31 64 87 0.17 8

A03

-0.16 31 109 92 0.14 7

A05

-0.33 to W3F1-2014-0041 Page 13 of 16 Table D-2 "SG32 Service Induced Indications-Wear at AVBs" SG ROW COL VOLTS PER LOCATION COMMENT 32 99 72 0.2 10 A04 0

32 101 76 0.3 13 A08 0.06 32 112 79 0.17 9

A08 0

32 114 79 0.14 8

A08

-0.09 32 95 80 0.15 8

A05 0

32 99 80 0.19 10 A05 0.15 32 115 80 0.25 13 A05 0.2 32 117 80 0.13 7

A07

-0.05 32 112 81 0.21 11 A07

-0.28 32 122 81 0.19 10 A07

-0.09 32 107 82 0.12 7

A07 0

32 117 82 0.17 9

A08

-0.09 32 126 83 0.17 9

A05 0

32 103 84 0.12 7

A07 0

32 121 84 0.14 8

A06

-0.12 32 120 85 0.31 14 A06

-0.05 PTP*

32 99 86 0.12 8

A08

-0.1 32 129 86 0.3 15 A05 0

PTP*

32 131 86 0.19 12 A05

-0.08 32 122 87 0.22 11 A06 0.05 32 124 87 0.16 9

A04 0

32 124 87 0.12 7

A05 0.05 32 99 88 0.16 10 A05

-0.12 32 99 88 0.16 10 A06

-0.04 32 107 88 0.12 8

A06

-0.07 32 127 88 0.13 9

A07

-0.1 32 98 89 0.1 7

A06 0

32 114 89 0.1 7

A09 0.13 32 118 89 0.14 9

A02

-0.1 32 126 89 0.72 25 A05 0.32 PTP*

32 103 90 0.14 8

A04

-0.09 32 117 90 0.2 11 A05 0.08 32 125 90 0.33 14 A08 0

PTP*

32 104 91 0.26 13 A06 0.07 32 126 91 0.14 8

A04 0

32 93 96 0.13 7

A03 0

32 82 97 0.13 8

A02

-0.16 32 82 97 0.26 13 A03 0

• Preventative Tube Plug to W3F1-2014-0041 Page 14 of 16 E. Number of Tubes Plugged During the Inspection Outage for Each Degradation Mechanism.

Table E-1 Tube Status SG - 31 SG - 32 Tubes in service prior to RF19 8968 8968 Total Number of tubes previously removed from service 0

0 Repair Candidates from RF 19:

Service Induced Wear at AVBs 0

4 Total Candidate Tubes Repaired 0

4 Total Repair SG - 31 SG - 32 Total Stabilizers Installed - RF19 0

0 Total Tubes Plugged - Post RF19 0

4 Total SG % Plugged - Post RF19 0.0%

0.04%

to W3F1-2014-0041 Page 15 of 16 F.

Total Number and Percentage of Tubes Plugged to Date and the Effective Plugging Percentage.

Table F-I Total Number and Percentage of Tubes Plugged to Date Year Outage EFPY SG31 SG32 Total Cumulative Plugs Plugs Plugging 2012 Pre-Service 0

0 0

0 0

2014 RF19 1.20 0

4 4

4 Total Plugged to Date 0

4 4

4 Percent Plugged to Date 0

0.04%

Table F-2 Effective Plugging Percentage Generator

1. Plugged

% Pluqaed SG31 SG32 0

4 0%

0.04%

to W3F1-2014-0041 Page 16 of 16 G. The Results of Condition Monitoring, Including the Results of Tube Pulls and In-situ Testing.

Waterford 3 did not perform any tube pulls or in-situ testing during the RF19 inspection.

Based on the Waterford 3 RF19 inspection results, no tubes contained indications which represented a challenge to structural or leakage integrity and all condition monitoring requirements are satisfied.

No primary to secondary leakage is predicted for the eddy current indications observed during the baseline in the event of a postulated SLB event.

Waterford 3 has a current Plant Specific Leakage limit of 0.375 gallons per minute for an "accident-induced leakage limit". The predicted leakage is zero, thus the accident-induced leakage limit is met.

OVERALL CONCLUSIONS During the Waterford 3 first inservice steam generator tube inspection, no indications were found exceeding the structural integrity limits (i.e., burst integrity > 3 times normal operating primary to secondary pressure differential across SG tubes).

Therefore, no tubes were identified to contain eddy current indications that could potentially challenge the tube integrity requirements of NEI 97-06. Similarly, all operational assessment structural and leakage integrity requirements are satisfied.

Based on the observed indications, the Waterford 3 SGs are expected to meet all structural and leakage integrity requirements at EOC-21 when the second in-service inspection will be performed.