Text

Steam Generator Tube Inspection Report for Refueling Outage 20
	ML18095A116
Person / Time
Site:	Byron
Issue date:	04/05/2018
From:	Kanavos M; Exelon Generation Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	BYRON 2018-0027
	Download: ML18095A116 (39)
	v • d • e

Byron Generating Station Exe[on Generation Rd www.exebncorp.com April 5, 2018 LTR: BYRON 201 8-0027 File: 1.10.0101 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555-0001 Byron Nuclear Power Station, Unit 2 Facility Operating License No. NPF-66 NRC Docket No. STN 50-455

Subject:

Byron Station, Unit 2 Steam Generator Tube Inspection Report for Refueling Outage 20 In accordance with Technical Specification 5.6.9, Steam Generator (SG) Tube Inspection Report, Exelon Generation Company, LLC is reporting the results of the SG inspections that were completed during Byron Station, Unit 2 Refueling Outage 20 (B2R20).

If there are any questions regarding this submittal, please contact Mr. Doug Spitzer, Regulatory Assurance Manager, at (815) 406-2800.

Respecifully Mark Kanavos Site Vice President Byron Station M EKIP MC/LZ/rm

Attachment:

1)

Byron Station, Unit 2 Steam Generator Tube Inspection Report Refueling Outage 20, September, 2017 cc:

Regional Administrator, NRC Region Ill NRC Senior Resident Inspector Byron Station Illinois Emergency Management Agency Division of Nuclear Safety

Exelon Generation Company, LLC BYRON STATION UNIT 2 4450 North German Church Road Byron, Illinois 67010 COMMERCIAL OPERATION: August 27, 7987 BYRON STATION UNIT 2 STEAM GENERATOR TUBE INSPECTION REPORT REFUELING OUTAGE 20 October 2017 Mailing Address 4300 Winfield Road Warrenville, IL 60555 Page 1 of 38

TABLE OF CONTENTS Introduction 3

Steam Generator Inspection Scope (TS 5.6.9.a) 3 Degradation Mechanisms Found (TS 5.6.9.b) 5 Nondestructive Examination Techniques Utilized for Each Degradation Mechanism Found During B2R20 (TS 5.6.9.c) 7 Location, Orientation (if linear), and Measured Sizes of Service Induced Indications (TS 5.6.9.d) 7 Plugging Summary (TS 5.6.9.e and TS 5.6.9.f) 10 Results of Condition Monitoring (TS 5.6.9.g) 1 1 Primary to Secondary Leakage Assessment (TS 5.6.9.h and TS 5.6.9.i) 12 Results of Monitoring for Tube Axial Displacement (Slippage) (TS 5.6.9.j) 13 Attachment A Westinghouse Model D-5 Tube Support Configuration 14 Attachment B Anti-Vibration Bar Wear Indications 15 Page 2 of 38

Introduction Byron Station, Unit 2 operates with four (4) Westinghouse Model D-5 recirculating steam generators (SGs) in the four-loop pressurized water reactor system.

Each SG contains 4570 thermally treated Alloy-600 U-tubes that have a nominal outside diameter of 0.750 inches and a nominal thickness of 0.043 inches. The tubes are hydraulically expanded into the full depth of the tubesheet. The tubes are supported by stainless steel quatrefoil support plates (TSP5) and chrome plated Alloy-600 anti-vibration bars (AVBs). The tube support plates within the pre-heater region are 0.75 thick stainless steel drilled hole baffle plates. The lowest tube support plate (TSP 01) on the hot and cold leg sides is a flow distribution baffle that is also stainless steel of 0.75 thick with enlarged drilled tube holes to distribute the feed flow. See Attachment A, for a diagram of the D-5 SG tube support plate (TSP) and AVB Configuration.

Technical Specification (TS) 5.5.9.d provides the requirements for SG inspection frequencies and requires periodic SG tube inspections to be performed. TS 5.5.9.d requires that 100% of the Unit 2 tubes are to be inspected at sequential periods of 120, 96, and thereafter 72 effective full power months (EFPM). The first sequential period shall be considered to begin after the first inservice inspection of the SGs.

At the start of B2R20, the Byron Unit 2 SGs had accumulated a total of 27.05 EFPY, and 25.862 EFPY (310.34 EFPM) since the first inservice inspection (ISI) during B2R01.

Therefore, Unit-2 was at 22.34 EFPM of the 72 EFPM in the fourth sequential inspection period making B2R20 the second outage and first SG inspection of the four (4) outage inspection period.

The B2R20 SG inspections were performed consistent with the Electric Power Research Institute (EPRI) PWR Steam Generator Examination Guidelines: Revision 8, applicable interim guidance and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines Revision 3. The field inspection activities were conducted from October 4, 2017 through October 15, 2017 by the Westinghouse Electric Company LLC.

Steam Generator Inspection Scope (TS 5.6.9.a)

Byron Unit 2 Refueling Outage 20 (B2R20) was the second refueling outage of the second 72 EFPM period, the next SG inspection is planned for B2R22, which will be the fourth refuel outage within the second 72 EFPM period. The following inspections were performed during B2R20 to ensure that 100% of the tubes will be inspected during the period as required by TS 5.5.9.d.

Eddy Current Scope:

Bobbin Inspections 100% full length examination of all in-service tubes in all four (4) SGs.

V Tubes in Rows 1 and 2 were inspected from tube end to TSP 11 H/i 1 C. The U-bend portions were inspected as part of the Row 1 and Row 2 +POINTTM probe program.

Examined the hot leg and cold leg tubesheet region for tube slippage.

Page 3 of 38

MRPC/+Point Probe Inspections 50% Row 1 and Row 2 U-bend region from TSP 11 H to 11 C All tubes in the U-bend region containing manufacturing artifacts.

50% Dents/Dings >5.0 volts located in the hot leg, cold leg and U-bend.

50% Dents 2.0-5.0 volts located at TSPs 01 H, 01 C, 02C, 03C, 04C, 05C, and 06C 50% Dings 2.0-5.0 volts located below TSP 06C and TSP 01 H.

All bobbin coil I-code indications that are not resolved after history review.

Existing and new TSP wear indications based on bobbin inspection.

Inspection to bound (all surrounding tubes, at least 2 pitches removed) the tubes with potential loose part (PLP) signals identified during the current inspection as necessary to support the Operational Assessment.

All foreign object wear left in service from the previous inspection as specified Degradation Assessment.

All hot leg, cold leg, and U-bend dent/ding locations >2.0 volts and locations of tube wear in all in-service tubes potentially containing high residual stress (minus 2-sigma tubes).

Inspection of the following benign signal codes:

V BLGIOXP located outside the tubesheet or TSP X-Probe Inspections 50% hot leg TTS +3 inches/-14.01 inches.

50% hot leg bulges/overexpansions within TTS 14.01 inches (H* region).

50% preheater baffle plate expansions at TSP 020 and TSP 030.

100% preheater baffle plate expansions at TSP 02C in the corner peripheral tubes with hydraulic expansions in all four (4) SGs.

Hot leg peripheral tubes (tubes within high flow zone) from 01 H to 14.01 inches below the tubesheet.

Cold leg peripheral tubes (tubes within high flow zone and peripheral tubes two (2) tubes deep excluding T-slot and tube lane from TSP 01 C to 3 inches into the tubesheet.

100% hot leg and cold leg intersections in the in-service potentially high residual stress tubes (minus 2-sigma tubes).

100% hot leg and cold leg tubesheet expansion transitions +31-1 4.01 inches in the in-service potentially high residual stress tubes (minus 2-sigma tubes).

Foreign objects and tubes adjacent to tubes plugged due to foreign objects per Degradation Assessment.

Page 4 of 38

Other SG Inspections:

Visual Inspection of Installed Tube Plugs All previously installed tube plugs were visually inspected for signs of degradation and leakage. In addition, all plugs installed during B2R20 were also visually inspected, and the installation parameters were reviewed for acceptable installation.

SG Channel Head Bowl Visual Inspections-Each SG primary channel head was visually examined in accordance with the recommendations of Westinghouse NSAL 12-01 and NRC IN 2013-20 for evidence of breaches in the cladding or cracking in the divider to channel head weld and for evidence of wastage or cracking of the carbon steel channel head.

Secondary Side Visual Inspections A full foreign object search and retrieval (FOSAR) of the pre-heater baffle plate TSP 02C was performed in SG 2B & 2C preheater high flow regions on the pre-heater tube support baffle plate TSP 02C.

The high flow regions included the preheater Waterbox, rib and cap plate region.

During B2R20, SG 2A and 2C primary and secondary side moisture separator regions were visual inspected along with obtaining ultrasonic thickness measurements.

Chemical Cleaning and Sludge Lancing

- SG secondary side Chemical Cleaning using the Westinghouse Advanced Scale Conditioning Agent (ASCA) and HS sludge lancing was performed during B2R20.

Degradation Mechanisms Found (TS 5.6.9.b)

The Table below provides a summary of all the degradation, by mechanism, identified during the B2R20 inspections (all mechanisms were present during previous inspections). No evidence of any cracking was found.

Summary of B2R20 Degradation Indications by Mechanism Degradation Mechanism SG2A SG 2B SG 2C SG 2D Total AVB Wear 259 402 293 191 1145 TSPWear 0

7 6

6 19 New Secondary Side EQ 3

2 1

2 8

Wear Historical Secondary Side EQ 5

10 2

4 21 Wear_Remaining_In_Service Other Results:

Visual Inspection of Installed Tube Plugs No degradation or anomalies were found.

SG Channel Head Bowl Visual Inspections-No evidence of cladding or weld breaches, channel head wastage or cracking was identified.

Page 5 of 38

Secondary Side Visual lnslections

- All four (4) fit-up blocks under TSP 03C were found intact in both SGs inspected. The Waterbox vertical rib plates and target plate in both SGs inspected were found to be in acceptable condition with no indication of degradation, erosion or other anomalies.

During the B2R20 refueling outage at Byron Unit 2, a visual inspection of the preheater region of SG 2C found a loose part (backing bar) that was subsequently determined to have been generated from the steam generators Waterbox where the feedwater enters the steam generator. The loose part, which was located within the tube bundle at the 02C tube support plate was removed from the steam generator during FOSAR activities. This part, which turned out to be a backing bar had not caused detectable tube wear.

Based on a visual inspection of SG 20s Waterbox, it was determined that the source of the loose part was one of the two cut-outs made in the central locations of the Waterboxs cap plate region. These cut-outs were made in the cap plate during manufacturing of the steam generator to generate windows in the cap plate to permit access to the inside of the Waterbox. Following the completion of work internal to the Waterbox, the cut-out plates created from cutting out the two access windows were designed to be reinstalled in the cap plate by full-penetration groove welds on three sides of each cut-out plate. During the reinstallation welding of these cut-out plates, backing bars/tabs were used to frame the three sides of the cut-out plates where the full-penetration groove welds would be located in order to provide backing for the root passes of the welds. Each cut-out plate possessed three backing bars, with one backing bar being approximately 10.5 inches long and spanning the length of the cut-out plate and the other two backing bars being approximately 2.5 inches long and approximately 4 inches long and located on the ends of the cut-out plates. Thus, a total of six backing bars were utilized to re install the two cut-out plates during steam generator manufacture. These backing bars were intended to be fused to the full-penetration groove welds and remain permanently in place in the steam generator.

Evaluations concluded that the remaining backing bars pose no concern for tube integrity over the period until the next steam generator inspection. In the postulated event that any of the remaining backing bars or cut out plates become loose, ninety-one (91) tubes were preventatively plugged and stabilized to prevent the potential loose parts from contacting and damaging active tubes. This similar condition occurred in 2004 (ML042260202) in SG 2A Waterbox, which was repaired in 2005.

No other evidence of degradation or anomalies was reported in SG 2B & 20 preheater. Extent of condition was performed for the remaining SG preheaters, 2A preheater had similar degradation and was repaired in 2005, while the SG 2D preheater had no backing tabs and no degradation. The SG 2C Waterbox will be inspected during the next SG inspection (B2R22) and are developing long-term strategy for addressing the issue.

Inspection results for the SG 2A and SG 20 primary moisture separators in the steam drum still show signs Flow Accelerated Corrosion (FAC)/erosion wear and that it is progressing slowly. The minimum component thickness was the riser barrel, which had an ultrasonic thickness measurement of 0.143 inches compared to the nominal component thickness of 0.25 inches. No repairs were required, and it was concluded that operation until the next schedule inspection Page 6 of 38

is justified with no adverse consequences for the moisture separators in all 4 SGs.

Nondestructive Examination Techniques Utilized for Each Degradation Mechanism Found During B2R20 (IS 5.6.9.c)

All SG eddy current examination techniques used for sizing degradation (see Table below) were qualified in accordance with Appendix H of the EPRI PWR SG Examination Guidelines Revision 8. Each examination technique was evaluated to be applicable to the tubing and the degradation mechanisms found in the Byron Station Unit 2 SGs during B2R20.

EPRI APPENDIX H TECHNIQUES EPRI Technique Rev Probe Degradation Applicability ETSS Detection/Sizing Volumetric Wear at Foreign Object Wear 21998.1 4

+PointTM Locations and Freespan Flaws (Volumetric Indications) 96004 3 13 Bobbin Detection/Sizing Volumetric Wear at AVB5 Detection Volumetric Wear at Broached and Drilled TSPs Detection/Sizing Volumetric Wear at TSPs, Foreign 96910.12 11

÷PointTM Object Wear Locations, and Freespan Flaws (Volumetric Indications)

Notes: 1.

TSP Tube Support Plate AVB Anti-Vibration Bar PLP Possible Loose Part 2.

Extended technique detection and sizing of foreign object wear (with or without loose part present and similar TSP wear)

Location, Orientation (if linear), and Measured Sizes of Service Induced Indications (IS 5.6.9.d)

Anti-Vibration Bar (AVB) Wear Tube degradation was found during bobbin coil examination in the U-Bend region due to fretting of the AVB on the outer surface of the tube. A total of 1145 indications were reported. Two (2) tubes in SG 2A, R44-C81 & R41-C91 had indications of AVB wear exceeding 40% TW plugging limit, and the two tubes were removed from service by mechanical tube plugging.

The largest AVB wear indication found during B2R20 was measured at 42%

through-wall (TW). The Table below provides a summary of AVB wear degradation. Refer to Attachment B for detailed locations and sizing for all AVB wear indications.

Page 7 of 38

B2R20 AVB Wear Summary SG 2A SG 2B SG 2C SG 2D

oflnd.

otlnd.

oflnd.

oflnd.

10-39%TW 257 402 293 189

>=40%TW 2

0 0

2 TOTAL 259 402 293 191 Mechanical Wear at Tube Suprort Plates (TSPs)

Tube degradation attributed to wear in the quatrefoil (broached) TSPs and in the pre-heater TSPs, which are drilled support baffle plates was identified. A total of 19 indications in 15 support plate structures were identified as wear during B2R20. Additionally, 14 pre existing TSP wear was identified in the 2B, 2C, and 2D SGs and five newly identified TSP wear was found in the 2B and 2D SGs. The depth of the TSP wear ranged from 9% TW to 39% TW. The Table below provides a summary of the tubes that contain indications of pre-heater or quatrefoil TSP wear as identified during B2R20.

B2R20 TSP Wear Summary SG Row I Col Volts md Per Locn Inch 1 Wear Type Pre-Existing TSP Wear Indications 2A None 2B 15 91 0.16 PCT 12 06C

-0.24 Baffle Plate 2B 47 75 0.12 PCT 9

02C 0.45 Baffle Plate 2C 48 35 0.20 PCT 26 02C 0.53 Baffle Plate 2D 48 63 0.23 POT 14 05C 0.1 Baffle Plate 2B 46 50 0.46 PCT 22 0.35 Quatrefoil Land 2B 46 50 0.23 POT 13

-0.43 Quatrefoil Land 2B 47 54 0.45 PCT 22 070 0.21 Quatrefoil Land 2B 49 73 0.24 POT 14 070 0.42 Quatrefoil Land 20*

49 65 1.20 POT 39

-0.44 Quatrefoil Land 070-Quatrefoil Land 20*

49 65 0.56 POT 25 SP2

-0.50 2C 49 73 0.39 POT 20 070

-0.32 Quatrefoil Land 2C 48 63 0.48 POT 23 070

-0.39 Quatretoil Land 2C 49 64 0.94 PCT 34 07C 0.34 Quatrefoil Land 2D 48 63 0.44 PCT 22 070 0.51 Quatrefoil Land Newly_Identified_TSP_Wear_Indications 2B 49 64 0.19 PCT 12 070 0.05 Quatrefoil Land 2D 49 63 0.18 11 07C-0.00 Quatrefoil Land C-,

2D 49 63 0.29 POT 16 070-0.00 Quatrefoil Land SP2 2D 49 63 0.17 POT 070-0.00 Quatrefoil Land SP3 2D 49 70 0.33 PCT 22 050

-0.17 Baffle Plate

Note: Tube was preventativety plugged and stabilized during B2R20 Page 8 of 38

Foreiçn Object Wear A total of 29 jndjcatjons of EQ wear were identified during B2R20. Twenty-one (21) of the indications were historical and the remaining eight (8) were newly reported during B2R20. The indications ranged from 10%

TW to 35% TW. The historical FO wear shows no significant change in eddy current signal response. All EQ associated with the historical wear flaws were removed in a prior outage.

Two (2) tubes were preventatively plugged during the current inspection due to detecting volumetric indications located slightly below TSP 05H and aligned with the quatrefoil flow hole. Tube R35-C22 in SG 2A contained a new 18% TW indication at TSP 05H-0.79 inch with an associated PLP signal. Tube R40-C52 in the SG 2D contained a new 35% TW indication at TSP 05H -0.76 inch also with an associated PLP signal. While the depths of the indications did not exceed the 40% TW tube plugging limit, both tubes were preventatively plugged due to the EQ that caused the wear is still present that may cause continued tube wear.

The Table below lists the data record for the eddy current signals corresponding to foreign object wear indications detected during B2R20 B2R20 Foreign Object Wear Summary Affected Axial Circ Circ NDE SG Tubes TSP Legacy (inch)

Extent Ext Depth Comment Row Col Location or New (inch)

(deg) 2A 8

76 07H

-0.99 Legacy 0.23 0.33 51 19 Object Not Present 2A 39 50 02C 2.2 Legacy 0.19 0.2 31 14 Object Not Present 2A 45 67 02C 1.02 Legacy 0.22 0.32 49 18 Object Not Present 2A 45 67 02C 3.02 Legacy 0.22 0.22 34 22 Object Not Present 2A 47 67 02C 0.43 Legacy 0.22 0.21 32 26 Object Not Present 2B 37 74 07H

-1.01 Legacy 0.18 0.21 32 18 Object Not Present 2B 39 66 02C 0.91 Legacy 0.19 0.4 62 12 Object Not Present 2B 38 66 02C 1.44 Legacy 0.54 0.35 54 25 Object Not Present 2B 1

54 02C

-0.23 Legacy 0.13 0.23 35 25 Object Not Present 2B 38 35 05H

-0.58 Legacy 0.15 0.26 40 25 Object Not Present 2B 38 35 05H

-0.88 Legacy 0.21 0.23 35 12 Object Not Present 2B 29 26 01H 0.47 Legacy 0.19 0.32 49 17 Object Not Present 2B 29 25 O1H 0.62 Legacy 0.12 0.2 31 10 Object Not Present 2B 35 15 07H

-0.97 Legacy 0.15 0.24 37 17 Object Not Present 2B 14 4

05H 0.89 Legacy 0.09 0.32 49 10 Object Not Present 2C 16 18 O1H 0.46 Legacy 0.19 0.22 34 23 Object Not Present 2C 17 18 O1H 0.49 Legacy 0.19 0.24 37 14 Object Not Present 2D 6

44 08H

-0.59 Legacy 0.22 0.16 25 34 Object Not Present 2D 9

76 07H

-0.64 Legacy 0.11 0.18 28 18 Object Not Present 2D 24 65 02C 1.13 Legacy 0.26 0.25 38 34 Object Not Present Page 9 of 38

Affected TSP Legacy Axial Circ Circ NDE SG Comment Tubes Location or New (inch)

Extent Ext Depth 2D 25 65 02C 1.48 Legacy 0.15 0.27 42 12 Object Not Present Newly Reported Foreign_Object_Wear 2A 28 56 07H

-0.88 New 0.19 0.2 31 17 Object Not Present 2A 30 50 03H

-0.61 New 0.14 0.27 42 22 Object Not Present Tube Plugged in B2R20 PLP 2A 35 22 05H

-0.79 New 0.14 0.32 49 18 Present 2B 17 48 05H

-0.8 New 0.12 0.2 31 25 Object Not Present 2B 27 74 05H

-0.92 New 0.12 0.22 34 18 Object Not Present 2C 6

48 05H

-0.8 New 0.18 0.3 46 16 Object Not Present 2D 24 47 05H

-0.78 New 0.19 0.17 26 29 Object Not Present Tube Plugged in B2R20 PLP 2D 40 52 05H

-0.76 New 0.19 0.31 48 35 Present Plugging Summary (TS 5.6.9.e and TS 5.6.9.f)

As a result of the B2R20 SG inspections, performed in accordance with TS 5.5.9.d, the modes of tube degradation found were Anti-Vibration Bar (AVB) wear, tube support plate (TSP) wear, and secondary side foreign object (FO) wear. A total of ninety-six (96) tubes were removed from service by mechanical tube plugging. The ninety-six (96) tubes removed from service, are as follows:

Two (2) tubes were plugged due to having AVB wear exceeding 40% TW Technical Specification 5.5.9.c plugging criteria.

Two (2) tubes were plugged due to foreign object wear in the presence of a PLP indication.

One (1) tube was plugged and stabilized due to TSP wear that was projected to exceed the 40% TW Tech Spec plugging criteria before the next scheduled inspection.

Ninety-one (91) tubes were preventatively plugged and stabilized in SG 2C due to potential degradation of the internals of the Waterbox.

B2R20 Tube Plugging by Degradation Mechanism fTS 5.6.9.e)

Degradation Mechanism SG 2A SG 2B SG 2C SG 2D Total AVBWear 2

0 0

0 2

TSP/Pre-heater Wear 0

0 1

Axial ODSCC 0

0 0

FOWear 1

0 0

1 2

Preventative 0

0 91 0

91 Total Plugged during B2R20 3

0 92 1

96 Tube plugging was conducted in accordance with ASME Section Xl, 2007 Edition through 2008 Addenda. All tube plugging was performed by Westinghouse using an Alloy 690 mechanical tube plugging process in accordance with ASME Section Xl IWA 4713, Heat Exchanger Tube Plugging by Expansion. All plugging was performed in accordance with Westinghouse approved procedures. There are no approved tube repair methods for the Unit 2 SGs. No tube sleeving was performed.

Page 10 of 38

lube Plugging to Date Number and Percentage per SG) (TS 5.6.9.f)

SG 2A SG 2B SG 2C SG 2D Total Total Plugged during B2R20 3

0 92 1

96 Total Stabilized during B2R20 0

0 92 0

92 Total Pluggedthrough B2R20 159 142 166 42 509 Total Percent Plugged through 3.48%

3.11%

3.63%

0.92%

2.78%

B2R201 Note:

1) Plugging percent is based on 4570 tubes per SG for all 4 SGs.

Results of Condition Monitoring fTS 5.6.9.g)

A condition monitoring assessment was performed for each inservice degradation mechanism found during the B2R20 SG inspection. The condition monitoring assessment was performed in accordance with TS 5.5.9.a and NEI 97-06 Rev. 3 using the EPRI Steam Generator Integrity Assessment Guidelines, Revision 4. For each identified degradation mechanism, the as-found condition was compared to the appropriate performance criteria for tube structural integrity, accident induced leakage, and operational leakage as defined in TS 5.5.9.b. For each degradation mechanism a tube structural limit was determined to ensure that SG tube integrity would be maintained over the full range of normal operating conditions, all anticipated transients in the design specifications, and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst under the limiting design basis accident pressure differential. The structural limits for wear related degradation were performed in accordance with the EPRI Steam Generator Integrity Assessment Guidelines and the EPRI Steam Generator Degradation Specific Management Flaw Handbook, Revision 2 (Flaw Handbook).

The as-found condition of each tubing degradation mechanism found during the B2R20 outage was shown to meet the appropriate limiting structural integrity performance parameter with a probability of 0.95 at 50% confidence, including consideration of relevant uncertainties thus satisfying the condition monitoring requirements. The NDE measured flaw depths are compared to the structural integrity condition monitoring (CM) limits, which account for tube material strength, burst relation, and NDE measurement uncertainties with a 0.95 probability at 50% confidence. Therefore, the NDE measured flaw sizes are directly compared to the CM limit. No indications met the requirements for proof or leakage testing; therefore, no In Situ Pressure tests were performed during B2R20.

In addition, no tube pulls were performed during B2R20.

The sections below provide a summary of the condition monitoring assessment for each degradation mechanism found during B2R20.

AVB Wear-The two largest AVB wear indications found during the B2R20 inspection were 42% & 41% 1W in SG 2A, tubes R44-C81 and R41-C91 respectively as measured by the EPRI Appendix H qualified technique 96004.3, Rev. 13. This is below the AVB wear CM limit of 63.0% TW. The two tubes with these indications were plugged in accordance with TS 5.5.9.c SG tube plugging criteria.

Pre-Heater Baffle/TSP Wear-The maximum drilled hole baffle plate wear indication reported during B2R20 was in SO 2C tube R48-C35 TSP 020 measuring an NDE depth of 26% TW. All TSP wear, whether located at quatrefoil TSPs or drill hole baffle plate Page 11 of 38

supports was depth sized using the +Point Examination Technique Specification Sheet (ETSS) 96910.1 technique. This is a change in methodology from previous inspections where flat (non-tapered) quatrefoil TSP and drilled hole baffle plate wear were depth sized with bobbin coil technique 96004.3 and tapered TSP/baffle plate tapered wear was sized with the ÷Point probe technique. During this inspection, all TSP/baffle plate wear was sized with the +Point probe Technique 96910.1, regardless if the wear was tapered or flat.

None of the TSP/drilled hole baffle plate wear indications exceeded the CM limits. The maximum quatrefoil TSP wear indication reported during B2R20 was in SG 2C at R49-065 TSP 07C measuring an NDE depth of 39% TW with 25% TW wear on a second land at the same support. The quatrefoil wear is less than the CM limit for quatrefoil TSP wear of 51.3% TW for wear extending the entire support plate width. In addition, the maximum baffle plate wear (26% TW) is less than the CM limit for drilled hole baffle plate wear at 53.6% TW for wear extending the entire support plate width. Therefore, condition monitoring for structural and leakage integrity has been satisfied for both quatrefoil TSP wear and baffle plate wear.

Foreign Object Wear - The deepest foreign object wear indication found during the B2R20 inspection was 35% TW with axial extent of 0.19 inch and a circumferential extent of 0.31 inch (Tube R40-C52 in SG 2D). Note: Other wear flaws were longer and/or wider. Nevertheless, all historical FO wear and newly identified EQ wear falls within the bounds of the CM structural limit of 52.0% 1W defined by a 0.55 inch axial and 135 degree circumferential flaw.

Primary to Secondary Leakage Assessment (IS 5.6.9.h and TS 5.6.9.i)

Byron TS 5.6.9.h reporting requirement states:

For Unit 2, the operational primary to secondary leakage rate observed (greater than three gallons per day) in each steam generator (if it is not practical to assign the leakage to an individual steam generator, the entire primary to secondary leakage should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report, Byron Station, Unit 2 did not observe any operational SG primary to secondary leakage over the preceding cycle. This is based on chemistry sampling taken from the Steam Jet Air Ejector and liquid SG blowdown sample locations.

Byron IS 5.6.9.i reporting requirement states:

For Unit 2, the calculated accident induced leakage rate from the portion of the tubes below 14.01 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident induced leakage rate from the most limiting accident is less than 3.11 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined...,

Byron Station Unit 2 did not observe any SG primary to secondary operational leakage over the preceding cycle, therefore the calculated accident leakage rate from flaws below 14.01 inches from the ITS is not quantifiable.

Page 12 of 38

Results of Monitoring for Tube Axial Displacement (Slippage) (TS 5.6.9.j)

All in-service tubes were monitored for tube axial displacement (slippage) in both the hot and cold leg tubesheet region in accordance with industry developed guidance for the bobbin probe. This was performed to ensure tubes had not severed within the tubesheet in regions of the tubesheet that were not inspected with XProbeTM. The absence of tube sever indications (TSI) from the entirety of the collected bobbin coil and X-Probe inspection data confirms no tubes had tube slippage.

Page 13 of 38

ATTACHMENT A Westinghouse Model D-5 TSP and AVB Configuration AV2 dFW3 AV>fE7%\\P74f If H lull 09H IJUH UI H ufI H 03H 01 H ISH An*i-vlbrlon Nozzle Note: AVB bars are denoted as AV in the figure Page 14 of 38

ATTACHMENT B Anti-Vibration Bar (AVB) Wear Indications Page 15 of 38

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75 Page 20 of 38

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Page 38 of 38

v t e Letter Sequence Request
EPID:L-2018-LRO-0017, Steam Generator Tube Inspection Report for Refueling Outage 20 (Approved, Closed)
Initiation Request Acceptance... Administration Questions Answers Results Approval Other:
MONTHYEAR2018-04-05 [Table View]

BYRON 2018-0027, Steam Generator Tube Inspection Report for Refueling Outage 20

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Subject:

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BYRON 2018-0027, Steam Generator Tube Inspection Report for Refueling Outage 20

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