ML19087A051
| ML19087A051 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/28/2019 |
| From: | Bologna R FirstEnergy Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML19087A050 | List: |
| References | |
| L-19-060 | |
| Download: ML19087A051 (14) | |
Text
FENOC FirstEnergy Nuclear Operating Company Richard D. Bologna Site Vice President March 28, 2019 L-19-060 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001
SUBJECT:
Beaver Valley Power Station, Unit No. 2 Docket No. 50-412, License No. NPF-73 180-Day Steam Generator Tube Inspection Report Beaver Valley Power Station P.O. Box 4 Shippingport, PA 15077 724-682-5234 Fax: 724-643-8069 In accordance with Beaver Valley Power Station, Unit No. 2 Technical Specification 5.6.6.2, "Unit 2 SG [Steam Generator] Tube Inspection Report," FirstEnergy Nuclear Operating Company hereby submits the steam generator tube inspection results obtained during inspections conducted during the fall 2018 refueling outage (2R20).
There are no regulatory commitments contained in this submittal. If there are any questions or if additional information is required, please contact Mr. Phil H. Lashley, Acting Manager, Nuclear Licensing and Regulatory Affairs, at 330-315-6808.
Sincerely,
~>>;,~
Richard D. Bologna
Enclosure:
Unit #2 - 2R20 Steam Generator 180 Day Report cc: NRC Region I Administrator NRC Resident Inspector NRC Project Manager Director BRP/DEP Site BRP/DEP Representative
Enclosure L-19-060 Unit #2 - 2R20 Steam Generator 180 Day Report (85 pages follow)
FIRST ENERGY NUCLEAR OPERATING COMPANY Technical Services Engineering Department Nuclear Engineering Programs Section Beaver Valley Power Station Unit #2 - 2R20 Steam Generator 180 Day Report Prepared by: -==G=a::..L--.:...;A=lb=e=rt=i;...._£.__.!....,..-~'4-1--..:::...:::...:........::..,,__ __
Date: oJ/12/11 Steam Generator Reviewed by: Brian Prinkey L
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Supervisor, Nuclear Programs \\
Date:
3/1-t.. It, Approved by: ~S~ea~n~P!::!::ad~e:'..!:.tt~.LIJ.J.~..J,......J.~1------
Date: "3.,, 1?-/'7 Manager, Technica
Unit #2 - 2R20 Steam Generator 180 Day Report Information Required by Technical Specification (TS) 5.6.6.2.1 Technical Specification 5.6.6.2.1 requires that a report be submitted to the Nuclear Regulatory Commission (NRC) within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Technical Specification 5.5.5.2, Unit 2 Steam Generator Program. For the fall 2018 refueling outage (2R20), the initial entry into MODE 4 occurred on November 12, 2018.
NOTE: Refer to the Definitions of Abbreviations, Codes and Reporting Terminology section (Page 11) for abbreviations, 3 letter codes and other nomenclature used throughout this report.
Per Technical Specification 5.6.6.2.1.a through 5.6.6.2.1.h, the following information is to be submitted to the NRC:
TS 5.6.6.2.1.a The scope of inspections performed on each SG:
Primary Side:
Bobbin Coil Probe (0.720 inch diameter probe utilized unless stated otherwise) 100 percent of the inservice tubes, full length, tube end to tube end, ( except Row 1 through 4 U-bend regions as noted below) in non-sleeved tubes per Generic Letter (GL) 95-05, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking," dated August 3, 1995 100 percent of the inservice tubes, from the hot leg tube end to the 8th hot leg TSP (straight length) in non-sleeved tubes in Rows 1 through 4 100 percent of the inservice tubes, from the cold leg tube end to the 8th cold leg TSP (straight length) in sleeved and non-sleeved tubes in Rows 1 through 4 100 percent of the inservice tubes, from the cold leg tube end to the top of the tubesheet sleeve on the hot leg side in sleeved tubes Rows 5 and higher I 00 percent of the inservice tubes, from the top hot leg TSP (8th) to the top cold TSP (8th) in Row 3 and 4 U-bend regions using a 0. 700 inch probe l 00 percent of the hot leg sleeved tubes in Rows 3 and 4 from the top of the sleeve to the 8th hot leg TSP using a 0.630 inch wide groove probe
+Point Probe 100 percent of Row 1 and 2 U-bend regions 100 percent of the hot leg TTS (from 6 inches above the TTS to 3 inches below the TTS) in non-sleeved tubes NOTE 1 100 percent of TSP DSI/DNI indications with a bobbin coil voltage > 2.0 volts 100 percent of TSP OSI indications with a bobbin coil voltage > 1.0 volt 100 percent of TSP mix residual signals,::: 5 5 degrees and 2:. 1.25 volts 100 percent of TSP mix residual signals 2:_ 2.0 volts I 00 percent of dented hot and cold leg TSP's ~ 5.0 volts l 00 percent of dents~ 2.0 but< 5.0 volts at the 1st, 2nd, 3rd and 4th hot leg TSP's Page 2 of 12
Unit #2 - 2R20 Steam Generator 180 Day Report 100 percent of dents located at A VB intersections ( +/- 1 inch of A VB centerline) 100 percent of new A VB wear signals plus any previous wear with cycle growth> 6 percent 100 percent of freespan dings (All reported voltages) 100 percent of Row 3 through 10 U-bend regions in SG C 100 percent of BLG and OXP signals in the hot leg tubesheet below the F* distance but above the tubesheet neutral axis 100 percent of BLG and OXP signals above the cold leg TTS 0
100 percent of bobbin "I-codes", such as freespan differential signals meeting the change criteria (Change criteria: phase rotation> 10 degrees and/or voltage amplitude> 0.5 volts) 100 percent offreespan signals not resolved as MBMs or without a historical review I 00 percent of Westinghouse Alloy 800 hot leg tubesheet sleeves 25 percent of dents::::: 2.0 but< 5.00 volts at the S1h, 6th, 7th and 8th hot leg TSP's 25 percent of Row 3 through IO U-bend regions in SG A and SG B 25 percent of TSP mix residual signals> 1.5 volts but< 2.0 volts 20 percent of the cold leg TTS from 6 inches above to 3 inches below the TTS (SG B) NOTE 1 Bounding of historical plugged tubes due to foreign object wear at the TTS and newly reported PLP signals
+Point is a trademark or registered trademark of Zetec, Inc.
NOTE I - for those tube locations where the expansion transition is located deeper into the tubesheet, the inspection distance into the tubesheet was adjusted to 5 inches below the top of the tubeshcct to ensure adequate inspection coverage of the F* distance.
Page 3 of 12
Unit #2 - 2R20 Steam Generator 180 Day Report In accordance with the guidance provided by GL 95-05, the 2R20 inspection consisted of a 100 percent full length bobbin probe examination of the inservice non-sleeved tubes in all three SGs.
All hot and cold leg TSP intersections were inspected using a 0.720 inch diameter bobbin probe.
The only exception to the use of the 0.720 inch diameter bobbin probe for GL 95-05 applications is the straight length section above the Alloy 800 hot leg tubesheet sleeves in Rows 3 and 4. Due to the thickness of the hot leg tubesheet sleeve wall (0.048 inch) which reduces the inside diameter of the sleeve and the inability of a 0. 720 inch diameter bobbin probe to traverse the U-bend region of Rows 3 and 4, a 0.630 inch diameter wide groove bobbin probe was used to inspect the straight length section of the Row 3 and 4 tubes above the hot leg tubesheet sleeve including the TSP intersections.
During the 2R20 outage, two DSI indications were reported with the 0.630 inch wide groove probe; both in SGB, R4 C36 at 04H and R4 C48 at 03H. Both of these TSP intersections were re-examined with a +Point probe.
The DSI at R4 C36 (04H) was confirmed to be a single axial indication (SAI) with a +Point amplitude of 0.14 volts, while DSI at R4 C48 (03H) was characterized as no defect found (NDF) after being inspected with a +Point probe. Both tubes have remained in service.
GL 95-05 states that smaller or larger diameter probes can be used to inspect tubes when it is impractical to utilize a nominal-size probe provided that the probes and procedures have been demonstrated to give an equivalent voltage response and detection capability when compared to the nominal (in this case 0.720 inch) probe. Probe equivalency testing between the nominal 0.720 inch bobbin probe and 0.640 inch wide-groove bobbin probe has been performed. It was demonstrated that the wide-groove probe met the equivalency requirements of Appendix Hof the EPRI Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 8". Due to thick walled sleeves at Unit 2, an electrically similar 0.630 inch wide-groove bobbin probe was used in place of the 0.640 inch probe. The 0.630 inch wide groove probe has demonstrated similar detection capabilities when compared to the 0.640 inch probe.
Currently, there are 24 inservice tubes in Rows 3 and 4 with hot leg tubesheet sleeves installed. The straight length section of these tubes above the tubesheet sleeve will be examined with 0.630 inch wide groove bobbin probe in future outages when applying GL 95-05 requirements.
Primary Side Visual Examinations Westinghouse Plug-in-Plug (PIP) - There are 9 hot leg and 9 cold leg tube locations (SG A - 4; SG B - 2; SG C - 3) which contain Alloy 600 plugs repaired with the Westinghouse PIP technique.
These locations are visually examined each outage to assess the condition of the tack weld which holds the PIP in place. No degradation was observed in any of the tube plugs. All tube plugs were accounted for and all were verified to be in their proper location. No sign of cracking was reported in any of the eighteen PIP tack welds.
Page 4 of 12
Unit #2 - 2R20 Steam Generator 180 Day Report 0
Westinghouse Nuclear Safety Advisory Letter (NSAL) 12-1 (Revision 1)- A remote visual inspection of the area around the channelhead drain line was performed in each hot and cold leg channelhead to meet the requirements of Westinghouse NSAL 12-1 (RI), "Steam Generator Channel Head Degradation". Included in this examination was (a) the divider plate to stub runner weld, (b) the tubesheet to stub runner weld, (c) the divider plate to channelhead weld (d) channelhead to tubesheet weld and ( e) entire clad surface of the channel head bowl. This inspection looked for evidence of gross defects such as indications in welds, missing weld filler material, a breach in the weld metal, and unusual discoloration of the weld metal and/or cladding imperfections. All inspections were determined to be acceptable. No sign of cladding breach, cracking, missing filler metal was observed. In the cold leg of SG C, a small area of discoloration (non-rust color) was observed approximately 1 foot from the divider plate. Subsequent review of previous channelhead videos showed no change in this area of discoloration. Follow on visual examinations of this area will be performed each time the SG C cold leg channelhead is opened.
Tube Plugs - 100 percent of the tube plugs are visually examined (as-found and as-left condition) each time the primary side is opened to document the condition of the hot and cold leg channelheads.
This process also includes tube plug accountability. During 2R20, as well as in prior outages, the examinations verified that the correct number of tube plugs were present and in the proper tube locations. Installed tube plugs were examined and determined to be acceptable. No signs of degradation were observed.
Secondary Side Visual Examinations:
Foreign Object Search and Retrieval (FOSAR) - A visual inspection of the secondary side tubesheet face, annulus and tube lane was performed during 2R20 in all three steam generators.
FOSAR confirmed the presence of three metallic foreign objects within the tube bundle. Two of the objects (small wire and gasket) were located in SG A and a piece of weld slag was located in SG C. No tube wear was detected as a result of these objects. FOSAR efforts could not retrieve the two objects in SG A as the wire and piece of gasket material were "fixed" in place. Five tubes surrounding these objects were preventatively plugged and stabilized. The weld slag in SG C broke apart during retrieval efforts and was dispositioned as being acceptable to be left in the SG for the upcoming operating cycle. Several sludge rocks were also observed but not retrieved.
Sludge rocks are not considered foreign material as they are indigenous to the operation of the component.
Possible Loose Part Indications - For those tube locations where possible loose part indications were reported during the 2R20 eddy current examinations and no visual inspections were performed at those particular tube locations, the +Point probe was used to verify that no degradation or tube wall wear was present. These tubes remained in service.
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Unit #2 - 2R20 Steam Generator 180 Day Report TS 5.6.6.2.1.b Degradation mechanisms found:
The following degradation mechanisms were reported during 2R20:
0 Axial ODSCC at non-dented TSP intersections 0
Axial ODSCC in the hot leg sludge pile freespan regions and expansion transition regions Circumferential ODSCC at the hot leg TTS expansion transitions Axial ODSCC at freespan dings < 5 volts Circumferential ODSCC at freespan dings Axial ODSCC in the freespans Axial ODSCC in the U-bend region 0
Axial ODS CC at I st hot leg TSP (Flow distribution baffle)
Wear at AVB intersections Wear at 151 hot leg TSP (Flow distribution baffle)
Foreign object induced wear Historical freespan volumetric indications TS 5.6.6.2.1.c Nondestructive examination techniques utilized for each degradation mechanism:
For the degradation mechanisms observed during 2R20, the bobbin coil probe was used as the primary method of detection except at or below TTS and in Row 1 and 2 U-bends where the bobbin probe is not qualified. In these areas, the +Point probe was employed. The +Point probe is also used to re-examine any ambiguous bobbin coil signals that were reported.
The 2R20 examination techniques were qualified, for detection and sizing (as applicable) of the existing and potential degradation mechanisms listed in the 2R20 degradation assessment. This qualification was in accordance with Appendices Hand I of the EPRI, "Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines:
Revision 8".
Site-specific ETSS's are developed prior to each steam generator inspection for each existing and potential degradation mechanism identified in the 2R20 degradation assessment. The site-specific ETSS's are developed in accordance with Appendices Hand I of the EPRI, "Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines:
Revision 8."
The examination techniques utilized during 2R20 are considered "Site Validated" as defined in the EPRI, "Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 8," for each existing and potential degradation mechanism listed in the 2R20 degradation assessment.
Axial ODSCC in the U-bend region is limited to Row 3 through Row 9 due to the bending technique used for those tube locations.
Page 6 of 12
Unit #2 - 2R20 Steam Generator 180 Day Report 2R20 Examination Techniques Used for Degradation Detection/Sizing Dee:radation Mode Tube Location Probe EPRI ETSS*
Existine: Dee;radation Mechanisms Axial ODSCC Sludge pile, expansion transitions Bobbin 128413 3 Coil +Point 128424 Circumferential ODSCC Tubesheet expansion transitions 3 Coil +Point 21410.1 Axial ODSCC Non-dented and dented TSP's Bobbin 128411 Bobbin < 5 volts, +Point > 5 volts 3 Coil +Point 22401.1 Axial ODSCC Freespan dings< 5 volts Bobbin 24013.1 Freespan dings > 5 volts 3 Coil +Point 22401.1 Axial ODSCC Row 3 through 9 U-bends (SG C)
Bobbin 128413 Single Coil +Point 128424 Axial PWSCC Tubesheet & expansion transitions 3 Coil +Point 20511.1 Circumferential PWSCC Tubesheet & expansion transitions 3 Coil +Point 20510.1 Axial PWSCC Dented TSP's < 2 volts Bobbin 96012.1 Dented TSP's > 2 volts 3 Coil +Point 96703.1 Circumferential ODSCC Freespan dings 3 Coil +Point 21410.1 Oblique PWSCC Row 3 through IOU-bends (SG C)
Single Coil +Point 96511.2 Wear A VB locations Bobbin 196041.1 Volumetric Entire tube length Bobbin 128412 Expansion transitions 3 Coil +Point 21998.1 Potential Dee;radation Mechanisms Axial ODSCC H/L freespan, C/L above sludge pile, Bobbin 128412 non-ding locations Axial PWSCC Row 3 through 10 U-bends Single Coil +Point 9651 l.2 Axial ODSCC Dented A VB locations Single Coil +Point 22401.1 Oblique/Circumferential Row 3 through 10 U-bends Single Coil +Point 96511.2 PWSCC (SG A and B)
Axial/Circumferential Row I and 2 U-bends Mid freq +Point 96511.2 PWSCC High freq +Point 99997.1 Axial ODSCC Row 3 through 9 U-bends Bobbin 128413 (SG A and B)
Single Coil +Point 128424 Thinning C/L TSP's Bobbin 96001.1 Loose Part Wear TTS, periphery & tube lane Bobbin 27091.l 3 Coil +Point 21998.1 Pitting Sludge pile Bobbin 96005.2 3 Coil +Point 21998.1
- The applicable EPRI Examination Technique Specification Sheet (ETSS) is listed for reference only.
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Unit #2 - 2R20 Steam Generator 180 Day Report TS 5.6.6.2.J.d Location, orientation (if linear), and measured sizes (if available) of service-induced indications:
The 2R20 SG Examination Results section (Page 12) lists information that includes the location, orientation and measured sizes of service-induced indications. Further explanation of the information provided in the results section is given below:
Bobbin probe indications reported as "I-codes" (DNI, DSI, DTI or NQI) were re-inspected with the +Point probe.
Bobbin probe indications reported as PSI were re-inspected with the +Point probe. If the +Point probe indicated a possible TSP ligament breach existed (CSJ), it was further evaluated by the original equipment manufacturer (OEM) engineering group. All ligament breach extents were found to be acceptable for continued plant operation.
New AVB indications reported from the bobbin probe listed as PCT were inspected with the
+Point probe. If the +Point probe indicated no crack-like flaws were present within the wear scar, a wear call (WAR) was assigned to the +Point report.
+Point indications reported as "I-codes" (SAi, SCI, MAI or MCI) were either (a) removed from service via plugging, (b) left in service by installing hot leg tubesheet sleeves or ( c) left in service if the indications qualified under the requirements of GL 95-05.
For hot leg top of tubesheet circumferential indications that could not be sleeved, a stabilizer was installed prior to plug installation.
TS 5.6.6.2.1.e Number of tubes plugged or repaired during the inspection outage for each degradation mechanism:
The following tables list the number of tubes plugged or repaired for each existing degradation mechanism reported during 2R20. This is the fifth consecutive outage where the alternate repair criteria of GL 95-05 have been implemented.
For the following Tables:
The Hot Leg Sludge Pile column includes indications located above the top-of-tubesheet
(+ 0.01 inch TTS or greater).
Circumferential indications recorded above the top-of-tubesheet are still within the expansion transition region of the tube.
The Hot Leg Expansion Transition (Exp Trans) column includes indications located at or below the top-of-tubesheet (0.00 inch or negative measurement).
2RCS-SG21A Degradation Mode Hot Leg Sludge Hot Leg Exp Hot Leg Total Tubes Pile Trans TTS Axial ODSCC 3
4 7
CircODSCC 4
79 83 Mixed Mode I
1 Administrative 5
5 Total 7
84 5
96 Page 8 of 12
Unit #2 - 2R20 Steam Generator 180 Day Report Notes for 2RCS-SG2 l A:
I) 79 tubes were repaired with Alloy 800 tubesheet sleeves, 17 tubes were plugged. Five of the 17 tubes plugged were administratively removed from service due to irretrievable foreign material located on the secondary face of the tubesheet. These tubes were stabilized in the hot leg prior to being plugged. No tube wear was reported from any of these tube locations.
2RCS-SG21B Degradation Hot Leg Hot Leg Free Flow Total Sludge Exp Freespan Span AVB Mode Pile Trans Ding Baffle Tubes Axial ODSCC 1
5 I
1 8
Circ. ODSCC 10 83 1
94 Wear 2
2 Total 11 88 I
1 2
1 104 Notes for 2RCS-SG21 B:
I) 94 tubes were repaired with Alloy 800 tubesheet sleeves, IO tubes were plugged.
2RCS-SG21C Degradation Hot Leg Hot Leg Freespan Free Span U-bend Total Mode Sludge Pile Exp Trans Ding Region Tubes Axial ODSCC I
I 1
3 Circ. ODSCC 5
46 51 Total 5
46 1
1 1
54 Notes for 2RCS-SG2 l C:
I) 43 tubes were repaired with Alloy 800 tubesheet sleeves, 11 tubes were plugged.
TS 5.6.6.2.1.f The number and percentage of tubes plugged or repaired to date, and the effective plugging percentage in each steam generator:
The following table lists the required information for each steam generator as of the end of 2R20:
SG Tubes Plugged Percent Sleeves Plug/Sleeve Effective Plu22ed 2R20 Tubes to Date Plu22ed Inservice Equivalency Plu22ing %
2RCS-SG2IA 17 351 10.397 247 8.82 I 0.658 2RCS-SG21B IO 324 9.597 169 6.04 9.776 2RCS-SG21C 11 284 8.412 65 2.32 8.481 TOTAL 38 959 9.469 481 17.18 9.638 Page 9 of 12
Unit #2 - 2R20 Steam Generator 180 Day Report TS 5.6.6.2.1.g The results of condition monitoring, including the results of tube pulls and in-situ testing:
Condition Monitoring All tubes were shown to satisfy the structural and leakage integrity performance criteria at 2R20.
The relative severity levels of the degradation observed during 2R20 were judged to be consistent with or bounded by the levels associated with previous outage inspection results. Based on the indications observed during 2R20, the SG tubing is expected to meet all operational, structural and leakage integrity requirements at End-of Cycle 21. None of the indications reported during 2R20 represented a leakage potential at postulated main steam line break conditions.
Tube Pulls No tubes were pulled (removed) from the SG's during 2R20.
In-Situ Pressure Testing No In-Situ pressure testing was required during 2R20.
TS 5.6.6.2.1.h Repair method utilized and the number of tubes repaired by each repair method:
Westinghouse Alloy 800 leak limiting sleeves A total of 218 sleeves were installed in 218 tubes for degradation reported at the hot leg top of tube sheet.
During the 2R20 sleeve installation process, two sleeved tubes were taken out of service:
One sleeve in 2RCS-SG2 l A (R 11 C60) was administratively plugged due to the hydraulic expansion pressure being on the high side of the acceptable limit. This tube was stabilized in the hot leg prior to plugging.
One sleeve in 2RCS-SG2 l B (R36 C4 7) was plugged due to the required distance between the hydraulic expansions being below the minimum tolerance. This tube was stabilized in the hot leg prior to plugging.
Sleeves Sleeves Sleeves Total# of SG Installed Plugged Previously Sleeves 2R20 2R20 Installed Inservice 2RCS-SG21A 80 1
168 247 2RCS-SG21B 95 1
75 169 2RCS-SG21C 43 0
22 65 TOTAL 218 2
265 481 Page 10 of 12
I Unit #2 - 2R20 Steam Generator 180 Day Report Definitions of Abbreviations, Codes, and Reporting Terminology 3 Letter Code Definitions Term I
Bobbin Coil Probe BLG Bulge DNI Dent/Ding with a Possible Indication OSI Distorted Tube Support Plate Signal with Possible Indication DTI Distorted Tubesheet Signal with Possible Indication MBM Manufacturer's Burnish Mark NQI Non-Quantifiable Indication OXP Over Expansion PCT Percent Through Wall PSI Possible Tube Suooort Plate Indication (Ligament Breach)
TSP Tube Support Plate Term
+Point Probe CSI Confirmed Tube Support Plate Indication (Ligament Breach)
DIS Distance Between Hydraulic Expansions Not Met MAI Multiple Axial Indications MCI Multiple Circumferential Indications NDF No Degradation Found SAi Single Axial Indication SCI Single Circumferential Indication VOL Volumetric Indication WAR Wear Additional Definitions Term Definition AVB Anti-Vibration Bar C/L Cold Leg (Outlet)
DENT Observed within a Tube Suooort Plate DING Observed in Free-Span Region of the Tubing EPRI Electric Power Research Institute SG Steam Generator H/L Hot Leg (Inlet)
NSAL Nuclear Safety Advisory Letter ODSCC Outside Diameter Stress Corrosion Cracking PLP Possible Loose Part PWSCC Primary Water Stress Corrosion Cracking TSP Tube Support Plate TTS Top ofTubesheet Page 11 of 12 I
Unit #2 - 2R20 Steam Generator 180 Day Report 2R20 SG Examination Results Attachments A, B, and C provide the examination results for tubes with service-induced indications in the Beaver Valley Power Station, Unit No. 2 SG's.
NOTE: The majority of the data contained in the Attachments comes from the production analysis process however, some data has been re-sized or re-profiled to address structural integrity concerns.
Therefore, variations in the dimensions of a given indication (length, angular extent, voltage) may exist between this document and any documents previously submitted to the NRC in support of the fall 2018 outage (2R20). Regardless of the source of the data being provided, tubes that exceeded the plugging or repair limit were properly dispositioned prior to returning the steam generators to service (MODE 4).
Refer to the following tables for a description of terms used in these attachments.
Description of Column Headings and Data Abbreviations Used in Steam Generator Examination Results Report Header Definitions Term Definition ROW/COL Row & column designation of tube location IND Type of indication LOC Location of nearest support structure INCH Indication distance from nearest support structure o/oTW Measured percent through wall of an indication LENGTH Field measured length of an indication ANGLE Measured angular extent of an indication around the tube WIDTH Measured width of an indication VOLTS Measured voltage amplitude of an indication PHASE Measured angular rotation of an indication CHAN Recording channel of an indication FROM Starting point of examination TO End point of examination Examination Extent Definitions (FROM - TO)
Term Definition 0IC I si Tube Support Plate on Cold Leg Side 0IH I si Tube Support Plate on Hot Leg Side AVBI I st Anti-Vibration Bar (Numbered Hot Leg to Cold Leg)
SBH Bottom of Sleeve - Hot Leg STH Top of Sleeve - Hot leg TEC Tube End - Cold Leg TEH Tube End - Hot Leg TSC Cold Leg Tubesheet (Secondary Face)
TSH Hot Leg Tubesheet (Secondary Face)
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