ML20062J258
| ML20062J258 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 08/31/1993 |
| From: | Redmond K, Sherburne P BABCOCK & WILCOX CO. |
| To: | |
| Shared Package | |
| ML20062J262 | List: |
| References | |
| NUDOCS 9309100170 | |
| Download: ML20062J258 (155) | |
Text
{{#Wiki_filter:- I , TsRAET I 1 Examination of Crystal River Unit #3 Steam Generator Tube Sections j TR-XXXXXX Research Project S413-06 Final Report, August 1993 L P Prepared by B&W NUCLEAR TECHNOLOGIES Special Products & Integrated Services Division and THE BABCOCK & WILCOX COMPANY Nuclear Environmental Services, Inc. , i Principal Investigators e P.A. Sherburne K.R. Redmond : Prepared for , Electric Power Research Institute l 3412 Hillview Avenue ; Palo Alto, California 94304 ; 4 and Florida Power Corporation t P.O. Box 219 l Crystal River, Florida 32623-0219 i EPRI Project Manager J.P.N. Paine i Steam Generator Reliability Project M Nuclear Power Division 7301/CD/ 20 ; 70 I L, t3 M3 j
(; P' ' ~ DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES This report was prepared by the organizations (s) named below as an account of work sponsored or cosponsored by the Electric 1%wer Institute, Inc. (EPRI). Neither EPRI, any member of EPRI, any cosponsor, the organizations (s) named below, nor any person acting on behalf of any of them: (a) makes any warranty or representation whatsoever, express or implied, (1) with respect to the use of any information, apparatus, method, process, or similar item disclosed in this report, including merchantability and fitness for a particular purpose, or (2) that su h use does not infringe on or interfere with privately owned rights, including any party's intellectual property, or (3) that this report is suitable to any particular user's circumstance; or (b) assumes responsibility for any damages or other liability whatsoever (including any consequential damages, even if EPRI or any EPRI representative has been advised of the possibility of such damages) resulting from your selection or use of this report or any information, apparatus, method, process, or similar item disclosed in this report. Organization (s) that prepared this report: B&W Nuclear Service Company The llahcock & Wilcox Company i
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( ABSTRACT , Portions of seven (7) tubes were removed from the "B" OTSG at CR-3 during Refuel 8 (late May 1992) and sent to the LTC for a laboratory evaluation. Six of the tubes contained low voltage ECT indications in the free span region between the LTSF and the 1st TSP. The objectives of the laboratory examination ; were to physically characterize any tube degradation for correlation with field eddy current data, l determine the effect of these defects on the pressure holding capability of the tubing, and establish the damage mechanism. ; The defects responsible for the low voltage eddy current signals in the first span region consisted of l small, relatively shallow, isolated patches of OD-initiated IGA. The IGA damage was associated with a non-uniform deposit pattern, concentrated in an area 8 to 18 inches above the secondary face of the i I lower tube sheet. The corrosion mechanism was attributed to low-temperature, reduced-sulfur attack, - which probably occurred at a point early in plant life when wet lay-up practices were more likely to have produced conditions favorable for this type of corrosion. The bobbin coil eddy current technique was l successful in detecting this damage, detecting all IGA patches with depths greater than 50% throughwall. ! The IGA had relatively low impact on the burst strength of the tubing. , i i
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;. s p m-ACKNOWLEDGEMENTS b.u[;N bI d [ u .. m The authors would like to acknowledge and thank Peter Paine of the Electric Power Research Institute (EPRI) and Rocky Thompson of Florida Power Corporation for their guidance throughout this project and for their patience during preparation of the final report. The authors would also like to acknowledge and thank the following people for their contributions to this project: Harry Smith, B&W Nuclear Service Company, and Kenji Krzywosz, EPRI NDE Center, for analysis and interpretation of eddy current data; Ross Davidson, Surface Science Western, for AES and XPS analysis; and Sidney (Tres)
Reeves, B&W Nuclear Environmental Services, metallography. l l l l l l l l l l 1 i l iii J
DRAFT TABLE OF CONTENTS Section Pare INTRODUCTION . ... ... . . . . 1-1 : 1 . . . . 1.1 Background Information . . .. . ... . ....... . . 1-1 1.2 Project Objectives .. .. . .. .. ... . . .. . 1-1 : 1.3 Technical Approach . . .................... .... 1-1 1.4 Results Summary ......... .. ................... 1-2 , 1.5 Report Organization . .. .............. .. ... 1-2 2 TUBE EXAMINATION . ... . ... . ..... . . ... 2-1 2.1 Nondestructive Examinations . . . . ....... .. .. . . 2-1 l 2.2 Destructive Examinations .. . . ... ........ 2-36 > 3 DATA ANALYSIS AND EVALUATION .. . ... . .... 3-1 . 3.1 Summary of Tube Degradation . . . . ................. 3-1 3.2 Correlation with Eddy Current Data . . .................. 3-1 , 3.3 Review of Prior Eddy Current Data . . . . ... ... .. 3-5 3.4 Effect of Defects on Pressure Holding Capability ... . ... 3-6 3.5 Plant Chemistry Data Review . . . . . . . . .... ........ 3-7 ; 3.6 Susceptibility of CR-3 Steam Generator Tubing to IGA . . . . . . . . . 3-8 , 4 DISCUSSION OF RESULTS . .. ................... ..... 4-1 5 CONCLUSIONS / RECOMMENDATIONS ..... .. . . ... 5-1 , 6 REFERENCES .. .. . .. .. ............. . . ... 6-1 l I i APPENDIX A EDDY CURRENT EXAMINATION OF PULLED STEAM GENERATOR TUBES .......... ....... . A-1 APPENDIX B EPRI NDE CENTER REVIEW OF ECT DATA . ........... B-1 l APPENDIX C C-1 (Adams & Hobart) . .... ... ........... ........ l i i t l t f f iv :
e l i h 11 LUSTRATIONS l Eigu.f_q Eagg 1-1 Tube Pull Diagram . . .. . . .... ... . .... 14 j 2-1 Tube Section 52-51-2, LTSF Region As-Received .. .. . . . 2-6 l 2-2 Tube Section 90-28-2, LTSF Region As-Received . . .. ............ 2-7 j 2-3 Tube Section 97-91-2, LTSF Region As-Received . ... . . .......... . 2-8 l 2-4 Tube Section 106-32-2, LTSF Region As-Received . . .. . 2-9 2-5 Tube Section 109-30-2, LTSF Region As-Received ... ... . . . . . . 2- 10 2-6 Tube Section 4144-2, LTSF Region As-Received . . .. .. .. . . 2-11 , 2-7 Tube Section 52-51-2, Freespan above LTSF As-Received . ..... .. 2-12 l 2-8 Tube Section 90-28-2, Freespan above LTSF As-Received . . .... . . . 2-13 , 2-9 Tube Section 97-91-2, Freespan above LTSF As-Received .. . . 2-14 , 2-10 Tube Section 106-32-2, Freespan above LTSF As-Received . . . . 2-16 2-11 Tube Section 109-30-2, Freespan above LTSF As-Received .. . . . 2-18 2-12 Tube Section 41-44-2, Freespan above LTSF As-Received . . . . .. 2-19 , 2-13 52-51-2, LTSF+ 19", Circular Band of Non-Uniform Deposits . ... ..... 2-21 1 2-14 52-51-2, Possible Pits and Non-Uniform Deposits above LTSF . . . ...... . . 2-22 2-15 52-51-3. TSP . . .. . . .. . ... 2-23 2-16 90-28-4, TSP .. .... ...... . .. . . .. ... . 2-24 ; 2-17 97-91-4, TSP . . . . .. . .. . 2-25 l 2-18 106-32-4, TSP .. . ... .. . . . . 2-26 2-19 109-30-4, TSP . . . .. .. . . . .. . . . . 2-27 - 2-20 41-44-4, TSP . ...... .. .... ... . . . .. . .... 2-28 2-21 52-51-3, Spalled Deposit at TSP-2%" Where Tube Was Bowed . ..... . 2-29 , 2-22 52-51-3, Typ. Deposit above TSP +9%" . .. . .. . .... .. . . . . 2-30 : 2-23 90-28-4, Axial Lines of Slightly Heavier Deposit . ...... . ..... . . . 2-31 ' - 2-24 97-91-4, Spalled Deposit 1st TSP-5 5/8" . . . . . . . . . . . . . ..... ........ 2-32 2-25 106-32-4, Typical Deposit above TSP .. ........... . ........ 2-33 2-26 106-30-4, Typical Non-Uniform Deposits Above and Below TSP . 2-34 2-27 41-44-4, Typical Deposit Above and Below Ist TSP . . .. . 2-35 + 2-28 LPI Results on Tube Section 97-91-2 . . .. ...... .... ....... 2-58 2-29 LPI Results on 106-32-2 . . . ... .. . ... .. . 2-59 ; 2-30 Mosaic of 106-32-2 After Being Burst .. . . . . . .... . 2-60 2-31 Mosaic of 97-91-2 After Being Burst . ... .... . . . . .. 2-61 . 2-32 Mosaic of 52-51-2 After Swelling .. . .... . ... .. .. .... 2-62 2-33 Stereovisual Result on 106-32-2 After Bursting . ..... .. . . . . . . 2-63 j 2-34 Stereovisual Result on 52-51-2 After Swelling . . .. .. ..... ... 2-64 , 2-35 Stereovisual Result on 90-28-2 After Swelling ....................... 2-65 ! 2-36 Sectioning Diagrams for 52-51-2 and 109-30-2 . . . . . . . . . . . . . . . . . . . . . . . 2-66 j 2-37 Sectioning Diagrams for 90-28-2 and 97-91-2 . . . . .................. 2-67 - 2-38 Sectioning Diacrams for 1%-32-2 . . . . . . . . . ..................... 2-68 ; 2-39 Specimen 109-30-2D, 8th Grind, IGA Patch at 280* .... .... ...... 2-69 3 2-40 Metallography Results on 52-51-2 (63X) . . . . . . ........ ........... 2-70 l 2-41 SEM/EDS Results on Specimen 52-51-2F OGA Patch at LTSF+8.8" and 350*) . . 2-71 2-42 SEM/EDS Results on Specimen 52-51-2P OGA Patch at LTSF+ 13.1" and 200*) . . 2-72_ 2-43 SEM/EDS Results on Specimen 90-28-2B OGA Patch at LTSF+5.1" and 315*) . . 2-73 2-44 SEM/EDS Results on Specimen 90-28-2N OGA Patch at LTSF+11.6" and 100*) . 2-74 2-45 SEM/EDS Results on Specimen 90-28-2N, OD Tube Surface . . . . . . . .... .. 2-75 l l v l
DR$ j ; ILLUSTRATIONS (Continued) i Pare FWure i
. . . 2-76 2-46 SEM/EDS Results on Specimen 109-30-2B,10th Grind,270* IGA Patch . . 2-77 3
2-47 SEM/EDS Results on Specimen 109-30-2B, 8th Grind, 80* IGA Patch . 2-78 2-48 SEM/EDS Results on Specimen 109-30-2D, 8th Grind, 80* IG A Patch . . 2-79 l 2-49 Typical Deposit Cross Sections (630X) . . . . . . . . .. ... 2-80 2-50 SEM/EDS Results on Specimen 109-30-2D,8th Grind,80* IGA Patch 2-81 1 2-51 SEM/EDS Results on Specimen 90-28-5,2nd Span . . . . . . . . 2-82
.. . . . l 2-52 SEM/EDS Results on Specimen 133-33-3B,1st Span . . .
. . 2-83 2-53 SEM/EDS Results on Specimen 133-33-3B,1st Span .. . 2-84 2-54 SEM/EDS Results on OD Deposit Flake from 52-51-2 .. 2 ,
2-55A Outer Deposit Flake Surface from Specimen 52-51-4 2-86 2-55B Inner Deposit Flake Surface from Specimen 52-51-4 . 2-87 ! 2-56A Outer Deposit Flake Surface from Specimen 133-33-3 .. !
. . . 2-88 2-56B Inner Deposit Flake Surface from Specimen 133-33-3 . ..... . .. ;
2-57 inner (Top) & Outer (Bottom) EDS Results on Deposit Flake Surfaces .. . . . 2-89 l
- from Specimen 133-33-9 . . . ....
2-58 Elemental Ratio of Chromium in Grain Boundary Corrosion Film
. . . . . . . . . 2-91 !
Relative to Base Metal . . . . . . . . . . . . . . . . . . . . . . . . . . . : 2-59 Elemental Ratio of Nickel in Grain Boundary Corrosion Film 2-92 i Relative to Base Metal ... 2-60 Elemental Ratio of Chromium & Nickel in OD Surface ... Corrosion Film
.... 2-93 !
Relative to Base Metal . . ... ..... ....... j 2-61 Elemental Distribution in OD Tube Deposits with respect to Steam
- .. . ... ..... ... . . 2-94
.' Generator Elevation ........
......... . .... 3-10 -l 3-1 Distribution of IGA Patch Depths (108 Defects) . l
. 3-11 3-2 Defect Frequency and Volume vs Axial Position . . . .. 3-12 i 3-3 Defect Volume vs Defect Depth . . . . . . . . . . . . . . . . . 3-13 i 3-4 Bobbin Coil Detectability vs Depth and Volume . . . . . ...
.. ... . . 3-14 l 3-5 MRPC Detectability vs Depth and Volume . ..... ..
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.. ...... .... .... ... 4-3 )
4-1 - (sludge profile) .. .. ......... 4-2 Nickel and Chromium Composition of Grain Boundary and Tube OD 4-4
..... ..... . .. . . ..... ... ..... l Surface Corrosion Films .
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TABLES - Table Page 1-1 Examination Outline . . .... . ... .. ... ... .. . .. . 1-3 2-1 Tube Receipt inspection Results . . .. . . .. . ...... 2-1 2-2 Results of Slow-Pull Bobbin Coil Inspection . . . .. . . . . 2-36 2-3 Liquid Penetrant Inspection Results . . . . . . . . . . ........... ........ 2-38 2-4 Swelled Tube Sections & Collected Deposits ...... ......... ....... 2-39 2-5 Other Collected Deposits ... .. . ....... ..... . ........ 2-40 2-6 Stereovisual Inspection Summary .... . . . .... .. .. . . . . . 2-41 2-7 Stereovisual Inspection Summary .. . .. ......... .. ... . . 2-42 2-8 Summary of Incremental Grind & Polish Data . . . . ... .. . . . 2-43 2-9 First Span Metallography Summary . . . . . . . . . . . . . . . .. .. .. ..... 2-44 2-10A SAM Results on Tube Specimen 52-51-2F1 Defect Surfaces - Area 1. . . . . . . . . 2 2-10B SAM Results on Tube Specimen 52-51-2F1 Defect Surfaces - Area 2 . . . . . 2-48 2-10C S AM Results on Tube Specimen 90-28-2N1 Defect Surfaces - Area 1 . ....... 2-49 2-10D SAM Results on Tube Specimen 90-28-2N1 Defect Surfaces - Area 2 . .... . 2-50 2-11 SAM Results on Tube OD Surfaces . . . . . . . . . ... ................ 2-51 2-12 SAM Results on OD Deposit Flake Surfaces . . . . . . . . . . . . ............ 2-52 2-13 Summary of Elemental Analysis Techniques and Purpose .... .. ....... 2-54 2-14 Deposit Analysis Results . . . . . . ..... . .. ..... . 2-56 2-15 Gamma Scan Results on ID Tube Deposits from Tube Section 133-33-3 . . . . . . . 2-57 3-1 Summary of Eddy Currer.t Distinguishable Defects ................ .. 3-2 3-2 Eddy Current Detectability Summary . . ........................... 3-4 33 Burst Test Data . ........ ................ ..... ....... 3-6 Vii
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SUMMARY
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Section 1 DRMT INTRODUCTION 1.1 Backcround Information Crystal River Unit 3 (CR-3) is an 821 MWe pressurized water reactor (PWR) plant owned and operated by Florida Power Corporation (FPC). The plant has been operating commercia!!y since March 1977. l CR-3 utilizes two (2) Model 177 FA once-through steam generators (OTSG) designed and fabricated by l j The Babcock & Wilcox Company. Each steam generator has 15,457 Alloy 600 tubes with nominal dimensions of 0.625 inch OD X 0.034 inch wall thickness. 1 Analysis of Refuel 7 field eddy current data revealed a significant number of indications along the tube free spans in the boiling regions of the steam generators. Many of these indications were just below the threshold of detection, and were difficult to distinguish from background noise. To investigate these I indications further, sections of 7 tubes were removed from the lower part of the "B" steam generator tube bundle during Refuel 8 in May 1992 and submitted for detailed laboratory examination. A sketch of the pulled tube segments and their approximate elevation in the CR-3 steam generator is provided in Figure 1-1. 1.2 Proiect Obiectives The objectives of the examination were as follows:
- 1. Physically characterize any tube degradation, particularly damage associated with low j
signal-to-noise ratio (S/N) indications in the boiling / free span regions, for correlation with field eddy current and ultrasonics data. This includes identification of the type of and extent of degradation and the degree of through-wall penetration. This data will be used to establish the baseline sensitivity and sizing accuracy of the NDE techniques for this type of defect.
- 2. Obtain burst pressure data to determine the effect of any significant defects on the pressure holding capability of the tubing. t
- 3. Attempt to establish the damage mechanism responsible for the eddy current indications.
- 4. Evaluate plant chemistry trends with respect to the degradation observed.
1.3 Iechnical Approach Since the sections of tubing removed from the steam generators are contaminated with activated corrosion products from the primary system, the bulk of the tube examination was conducted under controlled i conditions at B&W's Lynchburg Technology Center. The examination (Table 1-1) consisted of eddy current and ultrasonics testing, radiography, dimensional measurements, visual inspection and The photography, burst testing, extensive metallography, and corrosion film and deposit analysis. objective of the tube examination were to establish the damage mechanism responsible for the eddy !' current indications. l l-1 i i
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. WW l, if ij In parallel with the tube examination, a review of plant chemistry data and hideout return studie conducted by Adams & Hobart, Consulting Engineers. The purpose in conducting a review of the chemistry information was to look for a causal relationship of tube degradion with the steam generator environment.
In addition to the plant chemistry studies, independent reviews of eddy current test data (both his and present) were carried out by the EPRI NDE Center. The objectives in reviewing historic current data were (1) to establish the approximate date that tube defect indications were first obser and (2) to determine if the defect indications are changing in size or in number. The latter obje addresses whether the damage mechanism is active or inactive. , i 1.4 Results Summarv ! i The defects responsible for the low voltage eddy current signals in the first span region consisted! small, relatively shallow, isolated patches of OD-initiated IGA. The IGA damage was associate ; a non-uniform deposit pattern, concentrated in an area 8 to 18 inches above the secondary face of ' The corrosion mechanism was attributed to low-temperature, reduced-sulfur attack, lower tube sheet. which probably occurred at a point early in plant life when condensate polishing operations and w
- up practices were more likely to have produced conditions favorable for this type of corrosion.l bobbin coil eddy current technique was successful in detecting this damage, detecting all IGA patc{
with depths greater than 50% throughwall. The IGA had relatively low impact on the burst i the tubing. 1.5 Report Oreani7ation . t Results of the nondestructive and destructive tube examinations are described{ of the data and correlations with eddy current testing and plant chemistry information are included i; Section 3. All of the results are discussed in Section 4 and conclusions are presented in Section 5.I current information and individual reports by the EPRI NDE Center and by Adams & Hobart are included in Appendices A through C. i i I l i l p l 1-2 ,
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l TABLE 1-1: EXAMINATION OUTLINE , f TASK 1: NONDESTRUCTIVE PHASE 1 Receipt inspection
- i Visualinspection & Photography
- Eddy Current Testing" .
Ultrasonic Testing" X-Ray Radiography *
- j TASK 2: OESTRUCTIVE PHASE 52-514 133 33-3 97-91-2 52-51-2 133-33-2 Task 109 30-2 4144-2 90-28-5 133-33-9 106-32-2 90 28-2 Description X X X X' Hand-Puti ECT oD Descaling X Post-Clean ECT X Liquid Penetrant X X X X Tube Sectioning X X X Tube Swelling X Burst Testing X X X X Deposit Sampling X X X X X X X Stereovisual X X Tube Sectioning X X X X X X X SEM/EDS X X Metallography X X X SAM /XPS X 1-3
DRAFT f FIGURE 1-1: TUBE PULL DIAGRAM 133-33 " Sm tsp LTPF + 226 3 I 95 12
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13.0 1 4THTSP 30 3 10 _ Jp . 19 8! 9, 3RD TSP LTPF = LowerTube Sheet Primary Foco 16 5 D
+ -l 90-28 106-32 41-44 7 52-51 109-30 97-91 LTPF + 108.3
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q.. _ . 5 8' 16 8 e 5 5 5 23 0 24 0 4 20 0 33 23.1 l _ _ I _ t 8 LTPF +70.3 -
- 25 0 21 8 25 0 10.5 7,,
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_ , , ~ LTSF+ 3 s e;f_ 3 13.6 3 12.5 2 16 F 12 0 ~~ 43 -"3A F+ J hL F+ h LTSF+ E_LT5F+
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'*- 14 3 7g 95 ~
28 0 6- 92 9.2 3$ I ' - 69 80 I - 64 h 273 - - 21 6 2 , [ .
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1 .. TUBESHEET 1 17.8 g g
' 154 155 15.5 15.4 LW 1[ ji 151 15; -
1.5:: 4 1.5 : ' - 1.51 1.5 -- ' 15-.
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M k I Section 2 , TUBE EXAMINATI~N 2.1 Nondestructive Examinations 2.1.1 Receint inspections The CR-3 tube sections arrived at the Lynchburg Technology Center (LTC) on August 12,1992. Contact radiation levels on receipt were approximately 200 mR/hr y and smearable contamination levels were on the order of 500K dpm/100cm2 , requiring much of the initial work to be performed under Radiation Work Permits (RWPs). ' The tube segments were measured for length and visually inspected for orientation markings ~ and landmark features (e.g., lower tubesheet secondary face (LTSF) and tube support plate (TSP) regions) for comparison with tube removal records. Once the tube orientation relative to the steam generator tube array was established, each tube segment was notched at an arbitrary O' position at the bottom to preserve ! the orientation. Angular convention used throughout this report is clockwise looking at the bottom of the tube. Length measurements and the location of important landmarks were genera'ly verified to within 1/4 inch of the field reported data (see Table 2-1 for lab data). i i
- TABLE 2-1 TUBE RECEWF INSPECTION RESULTS ;
i Tube No. 52-51 Tube No. 90-28 Tube No.106-32 ', i Piece Length Landmarks Piece Length Landmarks ! Piece Length Landmarks 4 23.3 $ 23.1 5 23.1 , tsp (16.5) 4 21.8 tsp (9.4) 4 24.8 tsp (11.8) 3 79.1 3 4.3 diHS 13.5 3 12.6 3A .- , 2 27.9 LTsF (2.6) 2 30.8 LTsP p.5) 2 28.8 LTsF G.5) 15.4 1 15.4 , 1 19.9 1 weep
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DRAFI l p- , TABLE 2-1 sont.) TUDE RECEIPT INSPECTION RESULTS Tnbe No.109-30 Tube No. 4I-44 Tube No. 97-91 Piece Length Landmarks Piece Length Iindmarks Piece Length Landmarks 5 24.0 5 20.0 5 28.9 , tsp (9.5) 4 19.3 tsp G.5) tsp (10.6) 4 24.8 4 18.0 3 14.5 , 3 16.6 3 11.8 LTsF (7.5) 2 28.8 LTsF (5.0) f LTsF (7.5) 2 27.1 2 30.6 1 17.6 1 15.3 I 15.5 Tube No.133-33 , b Piece Length Landmarks Piece Length Landmots Piece Length Lar Amarks 9.8 i 4 8 16.5 ! 12 9.4 t tsp (6.8) 3 22.0 , 7 22.9 ii 13.0 2 21.4 LTsF (15.6) tsp
- 6 16.5 10 29.8 7.0 9 19.9 TSP (6.0) - 5 22.9 j tsp (8.3) 1
*Not verined due to extensive deposit spalling.
Note: Numbers in parentheses are inches to TSP center from tha tube bottori end (TBE). I 2.1.2 VisualInspection and Photocranhv Each tube segment was examined visually and selectively at low power (up to 40X) w stereomicroscope to characterize surface deposits, visible regions of degradation, dime , mechanical damage sustained during tube removal and other items of interest. Importa. examination were documented photographically. General Annearance In general, the freespan tube surfaces were covered with a relatively thin layer of b ' outer regions of the deposit were powdery and nonadherent, but the underlying deposit w ; tenacious (veri 6ed by scraping). These characteristics are typical of magnetite deposits l boiling surfaces in steam generators utilizing AVT water chemistry control. Minor scr nicks from the tube pulling operation were common to all tube sections as well. i 2-2
Lower Tubesheet Recion (All Tubes) j On all tubes, regions contained within the tubesheet were essentially free of deposits, although some light green deposits were noted on most tubes in the first few inches below the LTSF. The areas void of deposit typically ex.hibited a copper-colored sheen; this may simply have been due to a thin Ni-Cr oxide film on the metal surface. Some minor pitting was also typically observed within 2 to 3 inches below , the LTSF. The LTSF regions for all tubes except 133-33 are shown in Figures 2-1 through 2-6. 1st Freespan Recion frubes 52-51. 90-28. 97-91. 106-32. 109-30. 41-44) t For all tubes except 133-33, the deposits had a pronounced irregularly-shaped splotchy appearance, resulting from (1) spots where the deposit had spalled off exposing the tube metal and (2) areas where the deposit was thinner and darker than the surrounding bulk deposit giving a scalloped appearance (see l Figs. 2-7 through 212). There were some subtle tube-to-tube differences in the deposit character as l discussed below: Tube Section 52-51-2: 'Ihe scalloped patterns were less prevalent in the 1 0* orientation. Also, coarser scallop patterns were present along the 180* and 270' orientations. A half inch wide circumferential band of relatively smooth uniform deposit was noted 19 inches above the LTSF; l immediately adjacent to and on either side of this band, the scallop patterns were very coarse and appeared to have some significant depth (see Fig. 2-13). A 3/8 inch wide circumferential band of apparently deep scallop patterns was observed about 21 inches above the LTSF (see Fig. 2-14). Tube Section 90-28-2: The scalloped deposit patterns were generally coarser than 52-51-2 and were more prevalent in the 0* and 270* orientations. Also, there was large areas of spalled deposit. Tube Section 97-91-2: The deposits on this tube section were more unifcrm than the other tubes. The dark scalloped patterns were not l nearly as evident, although there were many tiny spots of spalled deposit. 1 1 Tube Section 106-32-2: The deposit patterns on this tube section were very similar to 52-51-2, except that coarser scalloped patterns were most apparent along the 90" orientation. l Tube Section 109-30-2: The deposit patterns on this tube sectionwere quite similar to 90-28-2, with the coarsest scallop patterns present in the O' oriedation. Tube Section 41-44-2: The deposit patterns on this tube section were very similar to 52-51-2, except that the scallop patterns were more uniformly coarse around the tube circumference. Also, an axial band of spalled deposit was observed along the 0* orientation. In any case, no defects were identified in any of these tube sections in the first freespan zone; particularly in the area immediately above the LTSF (i.e., the location of the field reported bobbin coil indications). 2-3 t.
DRMi 1st TSP Recion frubes 52-51. 90-28. 97-91. 106-32. 109-30. 41-44) In general, the support plate land contact positions were easily visible on the absence of deposit (see Figs. 2-15 through 2-20). There were no obvious signs of w TSP regions. The deposit patterns described previously generally persisted up on above. Tube-to-tube differences are discussed below. Tube Section 52-51-3: Tube section 52-51-3 was bowed rather severely - just below the TSP and the deposits were severely spalled in this area (see Fig. 2-21). This was probably a result of the tube pulling operation. Deposits above the TSP were similar to those described previously, except the scalloped patterns were much larger (see Fig. 2-22). There was extensive deposit spalling within the Tube Section 90-28-4: TSP region on this tube section. A typical deposit pattern above the TSP is shown in Figure 2-23). Tube Section 97-91-4: Deposit spalling within the TSP was also reasonably extensive on this tube. This tube section was different than the others in that the deposit was very uniform, with the exception of some occasional spalling. A typical area is shown in Figure 2-24. Tube Section 106-32-4: The scalloped deposits persisted above the TSP on this tube, but the patterns were coarser than those in the free span below the TSP. A typical area is shown in Figure 2-25. Tube Section 109-30 4: Similar to tube section 106-32-4 (see Fig. 2-26). Some possible, but very minor pitting was noted Tube Section 41-44-4: at the 30* land contact on this tube section. The deposit characteristics were very similar to tube section 10632-4 (see Fig. 2-27). Comments on Tube 133-33 In a few locations, the deposit in the first freespan zone on tube 133-33 il exhibited c to the other tubes, but in general it possessed a relatively uniform, thin deposit layer. T appeared to become somewhat thicker with increasing elevation in the ste TSP essentially all of the deposit had spalled off - probably a result of the tube r TSP land contact zones were not nearly as visible on this tube. 2.1.3 Laboratory Eddy Current Testine All tube segments containing TSP intersections, roll expansion transitions or ot defects were inspected by eddy current probes to characterize and i i to accurate to correlate the lab eddy current data with that obtained in the field. The probes d (2) used for were (1) Zetec 0.510" mag-bias universal long cone hig using Zetec DDA-4 and Eddynet software. 2-4
. .)
DRAH From the examination. two major observations were made: J (1) The defects presented a volumetric (non-cracklike) signature, similar to signals provided by shallow, outside diameter pitting. t (2) The majority of flaws reported in the field were confirmed in the laboratory -. No new or different modes of degradation were detected. Detailed results of the laboratory examination may be found in Appendix A. Note that for brevity, figures (lisajous plots and MRPC terrain maps) are not included in the Appendix, ! I 2.14 Ultrasonics Testine Tube segments containing areas with suspected defects were inspected by ultrasonics. BWNT's rotating l probe ultrasonic inspection system (UT-360) was used for both pre-tube pull and post-tube pull l examination. The objective was to determine if ultrasonic inspection is a viable technique for detecting l defects of the type present in the CR-3 steam generators. ) j Comparison of the UT (lab and field) data with ECT data showed good correlation between field and lab UT data, but no correlation with ECT data. Most defect indications found with the eddy current probes l were not detected with the ultrasonic inspection system. Results of the UT-360 examination are documented in Reference 1. 1 i 2.1.5 X-Rav Radiocraohv i j X-Ray Radiography was performed on the freespan areas containing eddy current indications and at the 1st TSP regions on all of the tube segments except 133-33. A Norelco 150 Model MG150 industrial ll radiographic unit with a 150 KV heavy duty double focus x-ray tube was used for this inspection. A l double wall radiography technique was used and each area of interest was radiographed in fciur (4) angular positions (i.e., 0*, 45*,90*, and 135*). Two sheets of 14" X 17" Type S(R) Kodak high resolution film were loaded into the cassettes to obtain two radiographs of slightly different density for each exposute. Front and back lead screens (5 mils thick) were utilized in the film cassette. For most of the radio-graphs, the exposure conditions were 150 KV tube voltage and 20 ma tube current for 0.9 minutes at a source-to-film distance of 35 inches. These parameters were chosen based on operator ) experience to obtain high film contrast and good sensitivity. All of the radiographs were carefully I inspected on a light box using a hand held magnifying glass. No defect indications were observed in any of the radiographs. Some tube sections exhibited wispy I indications, which may have been due to deposit patterns or residual water (from the ultrasonics testing) on the inside of the tubes. He observed wispy patterns were in no way related to the OD deposit patterns noted previously Since no service related defects were identified, prints of the x-ray film were not reproheed in this report, l I i i 2-5 l
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2.2 Destructive Phase - Methods & Results ; 2.2.1 Slow-Pull Bobbin Coil Eddy Current Testine The six tube sections containing eddy current indications in the region above the LTSF were reinspected by bobbin coil eddy current techniques. The axial position of each eddy current indication was more precisely determined by slowly pulling and centering the probe at each indication, then marking the probe sheath at the bottom end of the tube section at the 0" orientation and physically measuring the distance from the mark to the center of the coils. Prior to performing this test, the positioning capability of the ' probe was demonstrated using a calibration standard. The results are summarized below in Table 2-2: t Table 2-2 RESULTS OF SLOW-PULL BOBBIN COIL INSPECTION Section No. Defect Locations (inches above LTSF) 52-51-2 64 8.7 9.9 10.8 90-28-2 6.1 7.8 10.0 11.5 12.3 13.9 14.4 16.0 106-32-2 6.3 8.6 9.9 11.3 11.6 13.1 14.6 97-91-2 8.6 8.9 t2.0 14.4 109-30-2 6.0 B.4 9.0 9.6 41-44-2 6.3 7.6 12.4 16.1 2.2.2 Descaline of Tube Sections 97-91-2 & 106-32-2 Following eddy current testing, tube sections 97-91-2 and 106-32-2 were descaled using a two step . cleaning process consisting of a 4 to 8 hour soak in an alkaline permanganate (100 g/l NaOH and 30 g/l , KMnO4) solution at 90 to 95'C followed by a short (i.e., less than 10 minute) duration dilute acid (6N hcl inhibited with 2 g/l hexamethylene tetramine) rinse at ~60*C.' As a result of cleaning, the radiation and loose contamination levels on both tube sections were reduced to less than 2 mR/hr (contact y) and about IK dpm/100cm2 , respectively. The OD tube deposits were f completely removed, although light-colored " stains" were apparent, which general!y correlated with the , spalled deposit regions and darker scalloped areas noted previously during the visual inspection. 8 This process is not aggressive to the base metal, but is very effective in breaking down the spinel structure associated with corrosion films formed on Ni-Cr-Fe alloys in high temperature pure water. 2-36 1 I
~
DRAFT 2.2.3 Egil-Cleanine Eddy Current Testinc of Tube Sections 97-91-2 & 106-32-2 After descaling, tube sections 97-91-2 and 106-32-2 were reinspected by the bobbin coil eddy current technique described in Section 2.2.1 to establish any effect the OD deposits may have had on the eddy current signals. No significant deposit effect was observed. 2.2.4 Dve Penetrant Inspe.clion of Tube Sections 97-91-2 & 106-32-2 The two (2) descaled tube sections (97-91-2 and 106-32-2) were examined by fluorescent liquid penetrant inspection to identify defects which may not have been detected previously. Liquid penetrant indications were photographed to document their location and orientation, and further characterized by subsequent visual and/or stereovisual examinations. Other than minor pitting noted in a few locations, no significant defects were identified. There were localized areas exhibiting general surface roughness - possibly a result ofIGA. However, only a few of these indications were actually verified to be IGA after swelling and metallographic examination. The results of this inspection are summarized below in Table 2-3; pitting and suspect IGA areas are shown in Figures 2-28 (Section 97-91-2) and 2-29 (Section 106-32-2). 2.2.5 Burst Testine The two (2) descaled tube sections (97-91-2 & 106-32-2) were pressurized at room temperature to ; determine burst strength and open existing defects. The tube sections were installed in the burst test sytem . using standard Swagelok" fittings. A pneumatically driven, piston-type hydraulic pump was used to charge an accumulator to approximately 30,000 psi; pressure was applied to the test tube section through a metering valve to achieve pressurization rates on the order of 2,500 psi per second; time to burst the ! CR-3 tubing was less than 10 seconds. Tube pressure was monitored by a 0 to 30,000 psi Heise gage with an accuracy of 0.1 %. Also, a permanent record of each pressurization event was obtained via a pressure transducer connected to a x-y recorder. Both tube sections burst at relatively high pressures - 12,400 and 11,400 psi for sections 97-91-2 and 106-32-2, respectively. Both tube sections exhibited significant uniform plastic deformation; tube section 106-32-2 ruptured in classical " fishmouth" fashion, but tube section 97-91-2 exhibited a more localized pinhole failure. t i 2-37 i: t: 1:
a Table 2-3 1.iQUID PENETRANT INSPECTION RESULTS Tube Section 97-91-2: Pokkfo'n' kOSENE Description
-0.1 140' Superficial pittino below LTSF O.0 270' White surface deposit; no defect 8.4 90' Minor pittino adjacent to axial scratch 8.9 45' Superficial pitting 9.6 135* One small pit with white deposit inside 11.4 90' Small pits within an axial scratch 13.3 350' Superficial pittino and localized surface rouchness 13.8 0' Localized minor surface rouchness 14.5 0 Localized minor surface roughness Tube Section 106-32-2:
Pokkfo'n* kOMdh$ Description ,, 0.1 10' White surface deposit; no defect 0.1 315 White surface deposit; no defect 0.4 200' White surface deposit; no defect 6.4 70' Superficial pitting and localized surface rouchness*
- 6.4 280' Superficial pittino and localized surface roughness 8.6 90' Sinole pit with localized surface rouchness 8.8 90' Single pit with localized surface rouchness 9.0 90' Superficial pittino and localized surface roughness 9.8 200' Superficial pittino and localized surface rouchness 10.0 30* Superficial pitting and localized surface rouchness 11.4 10* Superficial pitting and localized surface rouchness 11.8 180' Superficial pittino and localized surface rouchness 13.2 150' Superficial pittino and localized surface rouchness 14.4 20' Superficial pitting and localized surface roughness 14.9 135' Localized surface roughness
- Relative to LTSF, inches
- Verified to be IGA after swelling or bursting, and subsequent metallographic examination, 2-38
2.2.6 Tube Swelljne & Deposit Collection , Seven (7) tube sections as identified in Table 2-4 below were pressurized at room temperature to achieve yielding and swell the tube sufficiently to spall off OD deposits and open up any existing defects. To prevent chemical contamination of surface deposits, deionized water was utilized as the working fluid. The tubes reached yield at pressures of about 6,500 psi, then were plastically swelled to a diametrical expansion of about 10%. The maximum pressure applied to each tube section was 8,400 psi, with the exception of number 90-28-2, which sprung a pinhole leak at 8,050; the leak location was LTSF + 10.2 i inch and 330*, which was within 1/4 inch of the uppermost field reported eddy current indication (see Fig.1-1). In general, the OD tube deposits spalled offin small flakes, leaving behind a relatively clean , surface; the deposits were collected and dried, then weighed to the nearest milligram. Table 2-4 SWELLED TUBE SECTIONS & COLLECTED DEPOSITS Tube Section Areas of Interest for Deposit Deposit Weight (mg) 52-51-2 Freespan area above LTSF 850 52-51-4 Freespan area above 1st TSP intersection 1697 , 90-28-2* Freespan area above LTSF 382 90-28-5 Freespan area above 1st TSP intersection 778 ; 133-33-3/2 Freespan area above LTSF 340 - 133-33 9** Freespan areas adjacent to TSP 321 , 133-33-9 " 3rd TSP intersection 1537
- This tube section sprung a pinhole leak at 8,050 psi.
" Highest available TSP intersection with visible deposits.
t Note: Prior to swelling tube section 52-51-2, a 2-3/4 inch long section was removed from the top due to a throughwall saw nick (from tube removal). Also, prior to performing any swelling of 52-51-4,90-28-5 and 133-33-3, ring sections were isolated near the top of each section for metallographic and SEM/EDS characterization of the OD deposits. In addition to tne deposit flakes collected from the swelled tube sections, other bulk deposit samples were collected as shown in Table 2-5 below. These additional deposit samples were obtained by scraping the tube surface with a razor knife thoroughly cleaned in ethanol. 2-39
1 i Table 2-5 ; OTIIER COLLECTED DEPOSITS Deposit Weight Tube Section Areas ofInterest for Deposit (mg) 52-51-2 Green deposits just below LTSF 4 l 90-28-2* Green deposits just below LTSF 7 133-33-3 Primary deposits
- 6
- Obtained after longitudinally splitting and clarr shelling a two inch long section of tube; the primary side deposit was extremely thin.
2.2.7 Post Burst / Swell Test Visual & Stereovisual Insnections i The burst / swelled tube sections were inspected visually and at low power (i.e., magnifications up to 40X) with a stereomicroscope to identify, precisely locate and further characterize any defects, which may have opened up. Representative mosaics of tube sections 97-0 3-2,106-32-2, and 52-51-2, are shown in Figures 2-30 through 2-32. As stated in Section 2.2 2, light-colored " stains" were present over much of the OD ! surface on the descaled tube sections: diese stains generally correlated with the spalled deposit regions l and darker scalloped areas noted previvisly during the visual inspection. The stereovisual inspection l revealed defects within some of these light stains. Most of the degradation was in the form of small IGA , patches, although some t nor pitting was occasionally observed. Some of the defects were located at l axial scratches; since these sections had been descaled, it was not possible to determine whether the scratches were pre-existing (i.e., from tube installation) or had been created during tube removal. A total of 17 and 56 potential defect areas were identified on burst tube sections 97-91-2 and 106-32-2, ; respectively. Representative defect areas are shown at higher magnification in Figures 2-33. All defect information is summarized in Table 2-6 below. i i l 1 2-40 l
Table 2-6: STEREOVISUAL INSPECTION
SUMMARY
Note: Axial position is given relative to the LTSF; axial extent is given in mils. Tube Section: 97 91-2 tb. Axfai[dhler AxiaWn" gular Desenption ib. Ax ai[d h"ular AxiaNn"dular Description AA 18.1 285' 9.1 0.4 Possibla minor pit M 7.1 320' 19.7 3.3 M;nor IGA patch Y 16.5 20' 5.9 0.7 Possible minor pit *K 6.6 225' 49.8 3.8 Small IG A patch
*W 14.1 105* 60.6 9.6 Smail lG A patch I 5.6 355' 5.7 0.9 Minor lGA patch U 11.6 245' 54.1 9.6 Small 1G A patch 'G 3.3 20* 13.1 0.7 Minor IG A patch 'T 11.5 90* 61.0 13.6 Smail lG A patch *E2 2.8 20* 2.6 1.1 Minor lGA patch 'S 11.4 95* 11.2 0.1 Minor pitting 'E1 2.8 285' 10.1 3.3 Minor IG A patch R1 9.3 350' 15.9 2.7 Minor IG A patch "D 2.6 350* 27.8 1.3 M^nor IG A patch *P 8.4 90* 73.2 15.2 Small IG A petch *B 1.1 285* 16.3 2.5 Minor pitting *O 8.1 15' 75.6 12.8 Small IG A patch
- Defects associated with axial scratches.
Tube Section: 106-32-2 tb. Axfai[dNg"ular AxiaNn"dular Dascription tb. Axfai[Ikh"ular AxiaNn"dular Description BG 16.6 90' 29.5 3.1 Smail lG A patch 'AG1 8.7 85' 9.8 1.5 SmallIG A patch BF 16.5 30' 34.6 4.5 SmaillGA patch AE 7.9 225' 63.7 11.5 SmaillGA patch BD 15.6 50' 32.2 6.4 Small IG A patch AD 7.7 60' 26.0 9.6 Smalf IG A patch BC 15.5 30' 31.3 6.4 Smail lG A patch AC2 7.6 220 97.9 6.4 Smali lG A patch BB 15.0 90* 30.4 5.8 Smail lG A patch AC1 7.5 60' 53.0 7.5 SmaillG A patch BA 14.9 35' 43.2 7.1 Small IG A patch AB 7.3 70* 53.9 4.0 Small IG A patch AZ 14.8 45' 32.4 5.1 Small IG A patch AA 7.1 200* 40.0 9.0 SmallIG A patch AY 14.6 220' 55.3 16.1 Sma!! !G A patch 2 6.9 180' 52.4 9.6 Smali lG A patch AX 14.3 30' 39.9 9.6 Small IG A patch Y 6.4 85* 14.5 1.6 Minor IG A patch AV 13.6 60' 39.8 9.6 Small IG A patch X2 6.3 65* 70.8 11.0 Minor IGA patch AU 13.4 45' 47.2 11.2 Small IG A patch X1 6.3 50' 16.0 7.8 SmallIGA patch AT 13.2 135' 59.8 10.3 Small IGA patch V2 5.3 125' 40.8 5.3 Small IG A patch
*AR 12.3 90' 44.9 12.8 Small IG A patch V1 5.2 45' 8.8 2.1 Minor pit AQ2 11.8 180' 46.7 11.2 Small IG A patch T 4.1 60* 6.6 1.0 Minor pit AQ1 11.6 90' 29.4 4.8 Small IG A patch R 0.0 290' 15.4 4.0 Minor IGA patch 'AP 11.3 20' 70.6 8.0 Smail lG A patch Q -0.6 190' 17.i 3.2 Smali pit 'AO 11.1 90' 25.3 6.4 Small IG A patch O -1.6 210' 2.9 3.1 Minor IG A patch AN 10.9 240' 32.4 8.7 Small IG A patch N -1.8 270' 5.4 1.0 Minor IGA patch 'AM3 10.9 0* 29.2 3.2 Small IG A patch M1 -2.3 305' 8.8 0.8 Minor IG A patch AM2 10.8 45' 16.1 3.0 Small IG A patch L -2.3 280' 29.1 8.8 Minor pitting AM1 10.7 180* 16.6 1.6 Small IG A patch K -2.4 310* 24.2 7.6 SmallIG A patch AM1 10.7 125* 25.8 2.9 Small IG A patch J -2.6 105* 9.5 5.8 Small pit AL2 10.5 25' 48.1 4.6 Small IG A patch 1 -2.8 40' 14.1 5.3 Small IG A patch AL1 10.4 75' 19.1 2.3 SmallIG A patches H - 2.9 1208 9.7 3.8 Minor IGA patch AK 10.0 25* 63.2 13.5 Small IG A patch *G1 -3.3 1608 8.3 6.5 Minor pitting AJ 9.7 190' 58.4 9.3 Small IG A patch F 3.4 160' 12.0 9.3 Minor IG A patches AH 8.9 69' 55.3 5.7 Small IG A patch E -3.9 145' 18.2 3.4 Small IG A patch ,
AG2 8.7 100' 62.3 7.3 Small IG A patch 'C -5.4 350' 6.7 4.9 Minor pitting I i l 2-41 l l 4
l , E For tube sections 52-51-2 and 90-28-2, the deposits spalled in such a manner that a splotchy pattern of adhering deposit remained on the tube surface. The adhering deposit areas correlated precisely with the thin, dark, scallop shaped deposits noted during the initial visual inspection. Additional patterns of dark ; stains, with essentially no associated deposit, were also noted; these areas appeared to correlate quite well with the spotty patterns of spalled deposit previously noted. The stereovisual inspection revealed defects , within some of the scallop shaped deposit regions. Essentially all the degradation was in the form of small ] IGA patches, although it is possible minor pitting as observed on the other two tube sections may not have been visible due to obstructing deposits. Several of the IGA patches were located at "old-appearing" axial scratches, which were most likely created during tube installation. A total of 17 and 24 potential defect areas were identified on tube sections 52-51-2 and 90-28-2, respectively (see Figs. 2-34 & 2-35); the defects are summarized in Table 2-7 below. Table 2-7: STEREOVISUAL INSPECTION
SUMMARY
Note: Axial position is given relative to the LTSF; axial extent is given in mils. Tube Section: 52-51-2 tb. Axfaikkg"ular g AxiaNn"dular Description Ib. Axfaikkg"ular AxiaNn"dular Dascription Z 18.0 270' 9.1 0.4 Possibia minor pit 'L 11.4 180' 33.5 1.4 Small IG A patch
'X 16.5 315' 40.3 2.0 small IG A patch 'K2 11.0 250' 27.3 2.1 Small IG A patch
'V 15.8 240' 60.6 3.6 Smail lG A patch *K1 10.9 180' 42.7 5.7 Smali lG A patch
'U 15.4 315* 32.7 4.8 Small IG A patch 'l2 10.0 330' 47.5 7.6 SmaillG A pat *h
'S 14.7 315' 63.7 8.3 Smail lG A patch 11 10.0 270' 52.9 7.6 SmaillG A pate( _ i
'R 14.1 250' 38.9 3.7 SmaillGA patch G 9.0 315' 36.9 7.2 SmaillG A patch
*P 13.1 200* 43.9 5.3 SmaillGA patch *F 8.8 350' 82.4 5.3 Small lG A patch f
'N2 12.5 190' 31.4 3.2 Smail lG A patch D 6.5 265* 60.0 8.4 Smali lG A patch N1 12.3 260* 35.8 1.4 Smn!! IG A patch B -0.8 10' 38.6 2.0 Minor IGA patches ,
Tube Section: 90-28-2 tb. Axfaikkg"ultr AxiaNn"dular Description fb. Axfaiko"ufer AxiaNn"dutar Description
'AF 17.2 150' 28.9 2.0 Smail lG A patch *S1 12.8 110' 27.8 1.5 SmaillGA patch l AD2 16.1 180* $ 2.4 3.5 Small IG A patch 'O 12.3 340' 59.2 3.1 SmallIG A patch *AD1 16.1 315' na na Small IG A patch "o 11.8 340* 51.7 1.5 SmalilG A patch AB 15.5 340* 54.4 8.3 SmaillG A patchea *N 11.6 100' 60.8 4.3 Smaff lG A patch Z 15.1 325' 38.2 1.3 Small IG A patch *M 11.4 290' 58.1 8.7 SmallIG A patch X2 14.6 340' 38.0 2.0 Smail lG A patch K 10.8 290' 31.8 3.6 SmaillGA patch X1 14.4 110' 53.1 0.7 Str.all IG A patch 1 10.4 200* 62.5 4.7 SmallIG A patch
- V2 14.1 270' 55.5 3.1 SmetilGA patch H 10.2 10' 58.7 4.5 SmaillG A patch V1 14.0 350' 51.9 4.4 Small IG A patch G 10.1 330' 79.1 8.1 Small IG A patch
'T2 13.2 110' 44.0 7.6 SmallIGA patch 'E 7.8 340' 70.9 7.9 SmallIGA patch T1 13.2 330' 28.5 0.1 Sme!! !G A patch C 6.2 20' 53.2 2.0 Smail lG A patch S2 12.9 350' 39.9 1.7 Smail lG A patch 'B 6.1 315' 63.0 4.1 Smail lG A patch 2.2.8 Tube Sectionine As defects were identified and selected for specific analyses, they were sectioned into smaller specimens of working size. Sectioning was performed with either a slow speed diamond saw or a high-speed ;
abrasive cut-off saw. For tube specimens which were to be used for deposit analyses, sectioning was performed dry or with deionized water to prevent chemical contamination of the deposits. Sectioned 2-42
DRAM ; specimens were stored in clearly labeled clean plastic bags to prevent loss and/or confusion of the samples. Sectioning diagrams were maintained for each tube section and defect area examined. All of the defect specimens from the first freespan region identified in Tables 2-6 and 2-7 were utilized for metallography, except specimens 52-51-2F and 90-28-2N, which were analyzed by SEM/EDS and S AM/XPS. In addition, two (2) specimens were isolated on 109-30-2 based on the laboratory slow-puli bobbin coil ECT data; these defect specimens correlated with the field reported bobbin coil indications at LTSF + 8 inches (27% TW; 0.94 V; Specimen B) and LTSF + 9.2 inches (S/N; 0.54 V; Specimen D) for metallographic examination by incremental grinding. Detailed sectioning diagrams for tube sections 52-51-2,109-30-2, 90-28-2, 97-91-2 and 106-32-2 are shown in Figures 2-36 through 2-38. Additional ring sections were taken from tube sections 52-51-4, 133-33-3 and 133-33-9 for ; characterization of the OD deposits by metallography and SEM/EDS. , 2.2.9 Metallocranhv Selected samples were mounted in Epomet (a thermoset resin), and prepared for metallographic examination using standard techniques. Deionized water was utilized as the grinding and polishing lubricant for preservation of corrosion product chemistry within defect regions on tube specimens subsequently used for microchemical analyses. The specimens were examined as-polished on the metallograph at magnifications up to 1,000X to characterize defects and deposit morphology. Selected grinding planes on specimens 109-30-2D and 109-30-2B were etched electrolytically in 5% nital solution to reveal the grain structure, then re-examined to establish the defect path relative to the grain boundaries. Steo Grindine Results (109-30-2D & 109-30-2B) IGA patches were identified on both of these specimens (see Figure 2-39). The IGA exhibited a classic thumbnail shape. The IGA had maximum depths of 40% and 50% throughwall for 109-30-2D and 109-30-2B, respectively. A summary of the metallography results for these specimens is provided in Table 2-8. Table 2-8
SUMMARY
OF INCREMENTAL GRIND & POLISII DATA Defect Extent Defect Extent ' Gnnd Axial Grind Axial Cire. Depth Vol. N o. Position Remarks Cire. Depth Vol. l No. Position Remarks i Extent (%TW) (10* **l Extent (%TW) (t o* in't Specimen 109-30-20: Specimen 109-30-2B: 8 10.00 IGA Patch at 285* 9' 24 % 6.3 10 8.3P IGA Patch at 275' 5 38 % 4.0 9 10.02 IG A Patch at 285' 9' 40 % 8.5 11 8.39 IGA Patch at 275' 11 46% 11.7 10 10.03 IG A Patch at 285' 6' 32 % 3.5 12 8.41 IGA Patch at 275' 12 50 % 13.8 11 10.04 IG A Patch at 285' 6' 40 % 5.9 13 8.42 IGA Patch at 275* 9 35% 9.1 12 10.06 IG A Patch at 285* 3' 40 % 2.7 14 8.44 IGA Patch at 275' 2 10 % 0.6 15 8.46 IGA Patch at 275' 2 3% o.1 Total: 26.9 Total: 39.2 i 2-43 l
l r or; ; d Results on Ist Freespan Reelons (52-51-2. 90-28-2. 97-91-2 & 106-32-2) ' He majority of defects identified by stereovisual inspection (as well as the type of damage) were confirmed by metallography (see Figure 2-40). Again, tube degradation was primarily in the form of small patches of " thumbnail-shaped" IGA. A total of 108 defects were confirmed, with maximum and minimum depths of 62% and I% throughwall, respectively, with an overall average depth of 28% and a standard deviation of 16%. Metallography data is summarized in Table 2-9. Table 2-9 FIRST SPAN METALLOGRAPHY
SUMMARY
52-51-2 90-28-2 97-91-2 106-32-2 ID Type Depth ID Type Depth ID Type Depth ID Type Depth ID Type Depth Z Pit NDD AF IGA 51 % AA Fit NDD BG IGA 11 % AG1 IGA N/A X IGA 32 % AD lGA 24 % Y Pit NDD BF IGA 17 % AE IGA 24% V IGA N/A AD IGA 49 % W IGA 54 % BD IG A 31 % AD IGA 25% U IG A 26 % AB IGA 30 % U lG A 48 % BC IG A 30 % AC2 IGA 22% S IGA 33 % Z IGA 30 % T IGA 44 % BB IGA 17 % AC1 IGA 18 % , R IGA 18 % X2 IGA 24 % S Pit 1% BA IGA 20 % AB IGA 18 % P IGA 33 % X1 IGA 62 % R1 IGA 4% AZ IGA ! 22% AA IGA 17 % N2 IGA 19 % V2 IGA 46 % P IGA 46% AY IGA 36% Z IGA 51 % N1 IGA 40 % V1 IGA 49 % /OE IGA S4N1 AX IGA 32% Y IGA 8% L IGA 13 % T2 IGA 53 % M IGA 16% AV IGA 29 % X2 IGA 49 % K2 IGA 19 % T1 IGA 46% K IGA 29 % AU IGA 39 % X1 IGA 27 % K1 IGA 45 % S2 IGA 28 % ! IGA 4% AT- IGA 31 % V2 IGA 14% 12 IGA 52 % S1 IGA 23 % G iG A 5% AR IGA 19 % V1 Pit NDD f 11 4GA 28 % O IGA 45 % E2 IGA 5% AQ2 IGA 46% T Pit NDD G IG A 34 % O IGA 45 % E1 IG A 5% AQ1 IG A 24 % R IGA NDD F' IG A 53 % N* IGA 60 % D IGA 8% AP IGA 42% - - D IGA 34 % M IG A 27 % B Pit 6% AO IGA 12% O Pit 7% K IGA 18 % - - - AN IGA 36% O IGA 3% B 38 % i 1GA 46% AM3 IGA 2 5 'A, N IG A 15% H IGA 37 % AM2 IGA 22 % M1 IG A 3% L O -: IGA 53% AM1 IGA 12 % L Pit 14% , E IGA 50 % AM1 IGA 16% K IGA 17% C IGA 56% AL2 IGA 16 % J Pit 5% B IGA 12% All 1GA 10 % I IGA 31 %
.- - - AK IGA 40 % H IG A 3%
AJ IGA 38 % G1 Pit 4% AH IG A 29 % F IGA 9% A02 IGA- 40%' E IGA 23 % C Pit 7% Ml Statistics: M nimum L IGA 13 % B IGA 12% S Pit 1% 0, M1, H IGA 3% Average 32 % 40 % 22 % 22% ; S. Dev. (a) 12% 14 % 21 % 13% NDD = No Detectable Degradation: N/A = Data not available; Boldf ace / Shaded = Burst location; - = LTSF
' Specimens utilized for SEM/EDS & S AM/XPS; depth estimated from SEM of fracture surface.
2-44 ,
i DRMI , 2.2.10 SEM/EDS/WDS Selected specimens were examined at higher magnifications in the SEM for characterization of defect and OD tube deposit micromorphology. De EDS (Energy Dispersive Spectrometer) and WDS (Wavelength Dispersive Spectrometer) attach-ments to the SEM were utilized for qualitative analysis of deposits and corrosion products to establish elemental composition and distribution within defect regions and other areas of interest. He examination included analysis of existing tube or defect surfaces, as well as - metallographically prepared cross sections. IGA Defect Surfaces (Snecimens 52-51-2F. P & 90-28-2B. N) i Typical IGA regions are shown after swelling in Figures 241 through 244. The intergranular nature of the fracture surfaces is readily apparent. At higher magnifications an obvious grain boundary film was noted (see Figs. 3-22 and 3-23). EDS analysis of the grain facets indicated chromium, oxygen and nickel were the major corrosion film constituents. However, significant levels ofiron, sulfur, aluminum, silicon and carbon were also detected. As noted previously, although th e majority of the deposit spalled away from the tube as a result of swelling, " stains" were left on the tube OD surface where the scalloped areas of dark thin deposit had been. It was noted that the IGA patches were contained entirely within these stained regions, although there were obviously large numbers of " stained" regions which had not developed IGA. A ring of deposit typically remained on the surface outlining each stain (see Fig. 2-45). EDS analysis indicated the heavier deposits in this surrounding ring were rich in aluminum, silicon and oxygen; lower levels of base metal elements were also detected. Within the ring of heavier deposit (i.e., within the stain itself) and on the tube surface outside of the stain, a EDS fimgerprint more typical of oxidized I-600 was observed, although the chromium appeared to be somewhat enriched relative to base metal composition. It was also noted that the area within the stain exhibited a higher oxygen peak and had slightly higher silicon and aluminum , levels than the tube surface outside of the stain. IGA Defect Cross-Sections (Snecimens 109-30-2B. D) One (1) grinding plane from each of these specimens was inspected by SEM/EDS. Typical patches of . IGA are shown in Figures 246 and 247. EDS analysis of the grain boundary corrosion products revealed very high sulfur levels (see also Fig. 2-48). Sulfur enrichment at the grain boundaries is further illustrated by the sulfur line scans in Figures 246 and 247. OD Deposit Cross-Sections (109-30-2. 52-514. 90-28-5.133-33-3 & 9) Metallography and SEM/EDS results on these metallography specimens revealed a relatively thin (about I mil thick or less) porous deposit layer. He deposits on specimen 133 33-3 were slightly thinner on ; average than the other specimens, while specimen 133-33-8 exhibited slightly thicker (up to 1.5 mil) deposits. Typical deposit cross sections are shown in Figure 2-49. The porosity levels were highest at the outer surface, giving the outer deposit a " fluffy" appearance, and decreased to very low levels near the deposit / tube interface. For the most part, the deposits appeared to be a single phase, with iron and oxygen as the major elemental constituents (see Figs. 2-50 through 2-53); trace levels of chromium, nickel, copper, and silicon were also detected. It was interesting to observe that a thin layer (perhaps on the order of 1 pm thick) of deposit at the tube / deposit interface was typically enriched in chromium and nickel relative to the bulk deposit (see esp. Fig. 2-52). Very infrequently, a copper-rich secondary phase, which was generally i 2-45 1
)
%QT) ~ Lf l MEdi present as discrete particles in the deposit, was observed on most of the samples. In specimen 109-30-2D a copper-rich particle appeared to be present as an oxide (see Fig. 2-50), while small particles of apparent metallic copper were observed in one location on specimen 133-33-8 (see Fig. 2-50 and 2-53). No sulfur )
was detected in the bulk deposit by EDS. l
)
OD Denosit Figkos (52-51-2. 52-51-4.133-33-3 & 9) i SEM/EDS results indicated the outer flake surfaces were rough and porous, giving the deposit a " fluffy" appearance (see Figs. 2-54 through 2-57). The outer surfaces were comprised chiefly ofiron and oxygen. The inner surfaces were smooth with the circumferential grinding marks replicated in the deposit surface; composition of the inner surfaces were also predominantly iron and oxygen, but enriched with chromium and nickel relative to the outer deposit surface. Traces of aluminum, silicon and titanium were also ! occasionally detected on the flake inner surfaces, but no significant amounts of sulfur were found. 2.2.11 SAM /XPS , Two (2) selected defect specimens were examined by SAM (Scanning Auger Microscopy) and focused XPS (X-ray Photoelectron Spectroscopy) for characterization of in-situ grain boundary and OD surface corrosion films. 'Ihe inner and outer surfaces of OD tube deposit flakes from a total of four (4) locations in both defect and non-defected regions were also analyzed by SAM /XPS. After spalling and light rinsing in ethanol, no additional specimen preparation was performed on the flake specimens prior to performing the analysis. Qualitative and semi-quantitative analyses were performed using both SAM and XPS to r establish elemental composition. The original sample surfaces were analyzed by SAM /XPS, sputtered to remove a few angstroms of deposit and then reanalyzed. Some additional sputtering and reanalyses 1 were performed to depth profile selected elements on the defect specimens. Electron binding energies for detected elements were determined by XPS to establish their oxidation states and subsequent inference of 'he chemical compounds present. IGA Defect Soecimens 52-51-2F1 & 90-28-2N1 l The major elemental constituents of the grain boundary corrosion film were nickel, oxygen, chromium, iron, and carbon (see Table 2-10A through 2-10D). Energy shifts in the XPS spectra for Ni, Cr and O indicated the bulk of the film was probably composed of Ni(OH)2, with significant levels of Cr2O3 as well. After short sputter times, the chromium content approached lents that would be expected in the base metal (i.e., chromium was not depleted significantly, see Fig. 2-58). Conversely, nickel was , generally depleted slightly relative to base metal composition (see Fig. 2-59). ' Ibis was also apparent in , the Ni/Cr ratios, which were generally slightly lower for the grain boundary film as compared to , reference spectra taken on fresh ductile fracture surfaces; average values were 3.0 (a = 0.6) and 4.5 (a
= 0.8) for the grain boundary film and ductile fracture surface, respectively.
Lower levels of sulfur and titanium, and trace levels of chlorine were also consistently detected throughout the grain boundary corrosion film. Generally, sulfur levels peaked after a sbort sputter at , levels of about 3 to 5 atom percent. XPS results indicated the sulfur was present predominantly as sulfate, but with appreciable quantitles of sulfide. Silicon was also detected in significant quantities, but - tended to be more prevalent near the OD tube surface and in the outer region of the film, indicating it , was probably a surface contaminant which washed into the defect region from the outside surface. Low ; to trace levels of copper, calcium and pinsphorous were only occasionally detected. : Auger spectra collected on tae OD tube surfaces indicated that areas with residual deposits were - predominantly composed of iron and oxygen, with significant levels of copper, nickel, silicon and carbon > 2-46
DRAR l l l (see Table 2-11). No chromium was detected in these regions. Low to trace levels of sulfur, chlorine ! and titanium were also detected. l Table 2-10A i SAM RESULTS ON TUBE SPECIMEN 52-51-2F1 DEFECT SURFACES - AREA 1 Sputter Elemental Composition (Atomic %) Re Time Depth Analysis Location (min) (nm) Ni Cr Fe O C S Si Cl Ti Ni/Ni, Cr/Cr, 0 0 10.0 3.4 1.0 24.0 52.0 0.4 9.1 0.1 0.3 0.1 0.2 1 30 22.0 7.5 1.9 26.0 30.0 4.3 7.7 0.9 0.3 0.4 Near OD 2 60 32.0 12.0 3.9 28.0 17.0 3.8 3.0 0.1 0.7 0.4 0.7 Surface 5 150 34.0 12.0 6.4 30.0 11.0 3.1 1.7 0.1 1.0 0.5 0.7 10 300 36.0 14.0 7.9 28.0 9.4 3.3 0.1 1.3 0.5 0.8 0 0 12.0 1.6 27.0 48.0 0.6 '.1.0 0.1 0.2 0.0 Mid-Crack 1 30 48.0 15.0 4.8 18.0 10.0 3.4 0.8 0.7 0.9
+
2 60 51.0 16.0 4.8 16.0 8.1 3.4 0.1 0.8 0.7 0.9 5 150 54.0 15.0 4.6 11.0 13.0 2.4 0.1 0.9 0.7 0.9 10 300 66.0 17.0 7.2 3.1 5.4 0.7 0.1 0.6 0.9 1.0 0 0 16.0 3.7 1.9 26.0 45.0 0.7 6.6 0.2 0.6 0.2 0.2 1 30 49.0 13.0 4.1 18.0 12.0 3.3 0.2 0.8 0.7 0.8 Crack Tip 2 60 49.0 16.0 5.4 16.0 9.1 3.0 0.1 1.8 0.7 0.9 5 150 58.0 13.0 5.9 9.6 10.0 2.0 0.3 1.4 0.8 0.8 10 300 60.0 17.0 6.5 4.8 8.0 1.2 0.3 2.3 0.8 1.0 5 putter Elemental Composition (Weight %) Ratin Analysis Location (min) (nm) Ni Cr Fe O C S Si Cl Ti Ni/Ni, Cr/Cr. 0 0 27.0 8.1 2.6 17.6 28.7 0.6 14.6 0.1 0.7 0.4 0.5 , 1 30 42.8 12.9 3.5 13.8 12.0 4.6 8.9 1.4 0.6 0.8 Near OD 2 60 51.7 17.2 6.0 12.3 5.6 3.4 2.9 0.1 0.9 0.7 1.1
$urface 5 150 52.5 16.4 9.4 12.6 3.5 2.6 1.6 0.1 1.3 0.7 1.1 10 300 52.6 18.1 11.0 11.2 2.8 2.6 0.1 1.6 0.7 1.2 0 0 31.9 4.0 19.6 26.1 0.9 17.4 0.1 0.4 0.0 Mid-Crack , 1 30 63.7 17.6 6.1 6.5 2.7 2.5 0.9 0.9 1.1 2 60 65.1 18.1 5.8 3.6 2.1 2.4 0.1 0.8 0.9 1.2 5 150 68.0 16.7 5.5 3.8 3.3 1.7 0.1 0.9 0.9 1.1 10 300 72.7 16.6 7.5 0.9 1.2 0.4 0.1 0.5 1.0 1.1 j 0 0 37.8 7.8 4.3 16.8 21.8 0.9 9.3 0.2 1.2 0.5 0.5 1 30 65.9 15.5 5.2 6.6 3.3 2.4 0.1 0.9 0.9 1.0 Crack Tip 2 60 63.2 18.3 6.6 5.6 2.4 2.1 0.1 1.7 0.8 1.2
.l 5 150 70.6 14.0 6.8 3.2 2.5 1.3 0.2 1.4 0.9 0.9 10 300 69.1 17.3 7.1 1.5 1.9 0.8 0.2 2.2 0.9 1.1 2-47
i' Table 2-10B , : SAM RESULTS ON TUBE SPECIMEN 52-51-2F1 DEFECT SURFACES - AREA 2 Sputter Elemental Composition (Atomic %) Ratios Time Depth Analysis Location (min) (nm) Ni Cr Fe O C S Si Cl Ti Ni/Ni, Cr/Cr. 0 0 10.0 3.3 1.4 26.0 47.0 0.6 12.0 0.1 0.6 0.1 0.2 1 30 29.0 10.0 3.1 31.0 17.0 4.2 4.4 0.2 0.7 0.4 0.6 Near OD 2 60 36.0 14.0 2.9 31.0 9.6 3.4 2.1 0.2 1.1 0.5 0.8 Surface 5 150 44.0 14.0 4.9 24.0 8.0 2.7 1.2 1.1 0.6 0.8 10 300 48.0 14.0 4.4 20.0 9.2 2.0 0.1 1.6 0.7 0.8 0 0 25.0 4.3 1.0 23.0 40.0 0.6 6.5 0.1 0.3 0.3 Mid-Crack 1 30 38.0 13.0 3.8 22.0 17.0 4.3 0.7 0.1 1.0 0.5 0.8 2 60 47.0 12.0 5.2 18.0 13.0 3.8 1.5 0.6 0.7 5 150 52.0 16.0 5.5 11.0 13 0 2.0 0.1 1.6 0.7 0.9 10 300 57.0 1 P.O 6.2 5.6 13.0 1.0 0.1 1.6 0.8 0.9 0 0 12.0 4.1 1.4 25.0 46.0 0.6 11.0 0.1 0.2 0.2 1 30 40.0 8.9 3.5 19.0 22.0 2.5 3.1 0.1 0.8 0.6 0.5 Crack Tip 2 60 45.0 12.0 3.9 18.0 15.0 3.7 1.3 0.1 1.4 0.6 0.7 5 150 48.0 15.0 4.9 14.0 14.0 3.7 1.1 0.7 0.9 10 300 48.0 16.0 5.0 14.0 12.0 3.3 0.1 1.2 0.7 0.9 Sputter Elemental Composition (Weight %) Rdos Time Depth Analysis Location (min) (nm) Ni Cr Fe O C S $1 Cl Ti Ni/M. Cr/Cr, 0 0 25.0 7.3 3.3 17.7 24.1 0.3 17.9 0.1 1.2 0.3 0.5 1 30 49.7 15.2 5.1 14.5 6.0 3.9 4.5 0.2 1.0 0.7 1.0 , Near OD 2 60 54.8 18.9 4.2 12.9 3.0 2.8 1.9 0.1 1.4 0.7 1.2 l l Surface 5 150 60.8 17.1 6.4 9,0 2.3 2.0 1.0 1.2 0.8 1.1 10 300 64.5 16.7 5.6 7.3 2.5 1.5 0.1 1.8 0.9 1.1 0 0 51.6 7.9 2.0 12.9 16.9 0.7 8.0 0.1 0.7 0.5 Mid-Crack 1 30 57.4 17.4 5.5 9.1 5.3 3.5 0.6 0.1 1.2 0.8 1.1 i 2 60 64.0 14.5 6.7 6.7 3.6 2.8 1.7 0.9 0.9 5 150 65.4 17.8 6.6 3.8 3.3 1.4 0.1 1.6 0.9 1.1 10 300 68.5 17.0 7.1 1.8 3.2 0.7 0.1 1.6 0.9 1.1 ; O O 29.9 9.1 3.3 17.0 23.5 0.8 16.3 0.1 0.4 0.6 1 1 30 61.7 12.2 5.1 8.0 6.9 2.1 2.9 0.1 1.0 0.8 0.8 Crack Tip 2 60 63.1 14.9 5.2 6.9 4.3 2.8 1.1 0.1 1.6 0.8 1.0 j 5 150 63.5 17.6 62 5.1 3.8 2.7 1.2 0.9 1.1 < 10 300 63.1 18.6 6.3 5.0 3.2 2.4 0.1 1.3 0.8 1.2 l 2-48 1 1
l DRAFT Table 2-10C < SAM RESULTS ON TUBE SPECIMEN 90-28-2N1 DEFECT SURFACES - AREA 1 Sputter Demental Composition (Atomic %) R dos Analysis Location (mm) (nm) Ni Cr Fe O C S Si Cl Tl Ni!Ni, Cr/Cr, 0 0 9.9 20.0 62.0 0.7 5.7 1.3 0.1 0.0 1 30 21.0 8.1 2.8 21.0 41.0 3.2 2.1 0.3 1.2 0.3 0.5 Near OD 2 60 37.0 18.0 5.3 23.0 13.0 3.4 0.4 0.4 0.5 1.1 Surface 5 150 50.0 20.0 6.9 13.0 7.9 1.5 0.1 0.9 0.7 1.2 to 300 51.0 18.0 6.7 11.0 11.0 1.0 0.1 1.7 0.7 1.1 0 0 13.0 19.0 62.0 0.6 3.8 0.5 1.5 0.2 0.0 Mid-Crack 1 30 17.?> 4.2 0.9 19.0 54.0 1.5 2.3 0.3 0.9 0.2 0.2 2 60 30.0 10.0 3.3 18.0 34.0 3.6 0.3 0.9 0.4 0.6 5 150 36.0 13.0 3.7 16.0 27.0 3.6 0.3 0.9 0.5 0.8 10 300 41.0 15.0 4.6 12.0 24.0 2.3 0.3 1.6' O.6 0.9 0 0 14.0 4.8 1.2 18.0 58.0 0.5 3.6 0.6 0.2 0.3 1 30 22.0 7.1 2.0 19.0 47.0 2.1 1.0 0.4 0.7 0.3 0.4 Crack Tip 2 60 35.0 16.0 4.4 16.0 24.0 3.5 0.3 0.6 0.5 0.9 i 5 150 45.0 16.0 5.1 13.0 18.0 1.7 0.3 0.7 0.6 0.9 j 10 300 52.0 16.0 6.5 7.7 16.0 1.2 0.2 0.7 0.7 0.9 Sputter Demental Composition (Weight %) Res
** *E Analysis Location (min) (nm) Ni Cr Fe O C S Si Cl Ti Ni/Ni, Cr/Cr, 0 0 30.1 16.6 38.6 1.2 10.3 3.2 0.4 0.0 ,
1 30 42.8 14.6 5.4 11.7 17.1 3.6 2.6 0.3 2.0 0.6 0.9 Near OD 2 60 53.4 23.0 7.3 9.0 3.8 2.7 0.3 0.5 0.7 1.5 , Surface 5 150 61.7 21.9 8.1 4.4 2.0 1.0 0.1 0.9 0.8 1.4 10 300 83.3 19.8 7.9 3.7 2.8 0.7 0.1 1.7 0.8 1.3 0 0 37.2 14.8 36.3 0.9 6.5 0.7 3.5 0.5 0.0 Mid-Crack 1 30 41.6 9.1 2.1 12.7 27.0 2.0 3.4 0.4 1.8 0.6 0.6 , 2 60 52.9 15.6 5.5 8.7 12.3 3.5 0.3 1.3 0.7 1.0 5 150 56.4 18.0 5.5 6.8 8.7 3.1 0.2 1.2 0.8 1.2 , 10 300 59.0 19.1 - 6.3 4.7 7.1 1.8 0.2 1.9 0.8 1.2 0 0 36.0 10.9 2.9 12.6 30.5 0.7 5.5 0.7 0.5 0.7 5 1 30 46.3 13.2 4.0 10.9 20.2 2.4 1.3 0.4 1.2 0.6 0.9 Crack Tip 2 60 53.6 21.7 6.4 6.7 7.5 2.9 0.2 0.7 0.7 1.4 5 150 61.7 19.4 6.7 4.9 5.1 1.3 0.2 0.8 0.8 1.3 l 10 300 65.8 17.9 7.8 2.7 4.1 0.8 0.1 0.7 0.9 1.2 2-49 ,
1 1 ((T $ Pc
) - I k)A N h Table 2-10D i SAM RESULTS ON TUBE SPECIMEN 90-28-2N1 DEFECT SURFACES - AREA 2 Sputter Elementel Composition (Atornic %) p, ,,
** f Analysis Location (min) (nm) Ni Cr Fe O C S Si Cl Ti Ni/N( Cr/Cr.
0 0 10.0 4.4 19.0 61.0 1.2 4.0 0.3 0.1 0.3 i 1 30 25.0 9.0 2.8 23.0 35.0 3.2 0.5 0.3 1.3 0.3 0.5 Near CD 2 60 31.0 13.0 4.2 27.0 19.0 2.2 0.6 0.3 0.6 0.4 0.8 Surface 5 150 37.0 15.0 4.2 24.0 16.0 2.7 0.5 0.7 0.5 0.9 10 300 41.0 16.0 4.4 19.0 15.0 2.2 0.6 1.3 0.6 0.9 , 0 0 14.0 3.1 19.0 57.0 0.6 4.1 0.9 1.2 0.2 0.2 f4d-Crack 1 30 19.0 4.9 18.0 53.0 1.6 2.3 0.9 0.7 0.3 0.3 2 60 26.0 10.0 2.6 17.0 38.0 3.9 0.9 0.8 0.8 0.4 0.6 5 150 30.0 13.0 3.1 17.0 29.0 4.8 0.6 0.7 1.2 0.4 0.8 10 300 37.0 16.0 4.2 14.0 24.0 4.1 0.6 0.9 0.5 0.9 0 0 16.0 6.0 1.6 21.0 47.0 2.3 4.2 0.1 0.9 0.2 0.4 , 1 30 23.0 9.9 3.0 17.0 4.0 4.3 1.8 0.3 1.0 0.3 0.6 I Crack Tip 2 60 33.0 16.0 3.9 20.0 22.0 3.6 0.5 0.1 1.0 0.5 0.9 5 150 38.0 16.0 4.7 17.0 21.0 3.3 0.2 0.5 0.5 0.9 k ( 10 300 42.0 17.0 5.3 13.0 18.0 2.7 0.1 1.0 0.6 1.0 - I 5 putter Elemental Composition (Weight %) Rh
** 'E I Analysis Location (rnin) (nm) Ni Cr Fe o C S Si CI Ti Ni/Ni, Cr/Cr.
0 0 29.2 11.4 15.1 36.4 1.9 5.6 0.5 0.4 0.7 ! 1 30 47.8 15.2 5.1 12.0 13.7 3.3 0.5 0.3 2.0 0.6 1.0 Near CD 2 60 51.3 19.0 6.6 12.2 6.4 2.9 0.5 0.3 0.8 0.7 1.2 Surface 5 150 55.7 20.0 6.0 9.8 4.9 2.2 0.5 0.9 0.7 1.3 10 300 58.4 20.2 6.0 7.4 4.4 1.7 0.5 1.5 0.8 1.3 0 0 37.4 7.3 13.8 31.2 0.9 5.2 1.5 2.6 0.5 0.5 , fad-Crack 1 30 45.0 10.3 11.6 25.7 2.1 2.6 1.3 1.4 0.6 0.7 , 2 60 48.7 16.6 4.6 8.7 14.5 4.0 0.8 0.9 1.2 0.7 1.1 5 150 50.6 19.4 5.0 7.8 10 0 4.4 0.5 0.7 1.6 0.7 1.3 . 10 300 55.0 21.1 5.9 5.7 7.3 3.3 0.5 1.1 0.7 1.4 , 1 0 0 37.9 12.6 3.6 13.6 22.8 3.0 4.8 0.1 1.7 0.5 0.8 i i 1 30 51.9 19.8 6.4 10.5 1.8 5.3 1.9 0.4 1.8 0.7 1.3 ; Crack Tip 2 60 51.6 22.2 5.8 8.5 7.0 3.1 0.4 0.1 1.3 0.7 1.4 i 5 150 56.0 20.9 6.6 6.8 6.3 2.7 0.2 0.6 0.7 1.3 . 10 300 58.6 21.0 7.0 4.9 5.1 2.1 0.1 1.1 0.8 1.4 I 1 i i j 2-50
DRAFT Areas on the OD tube surface, which were essentially free of deposit, were composed primarily of nickel, ! oxygen, chromium, iron, and carbon as was the grain boundary corrosion film (see Table 2-11). Low levels of sulfur (below I at%), were consistently observed throughout the OD corrosion film. Significant , levels of silicon and titanium, and low levels of chlorine, calcium, phosphorous and copper were occasionally detected. The nickel and chromium levels were similar to those observed in the grain i boundary corrosion film (i.e., exhibited nickel depletion, see Fig. 2-60). I Table 2-11 SM1 RESULTS ON TUBE OD SURFACES Tube Section Sputter Elemental Composition Elemental
& Analysis Time Depth (Upper Table: stom % - Lower Table: weight %) Ratios Location (min) (nm) Ni Cr Fe O C S Si Cl Ti Cu Ce P Ni/Ni Cr/Cr 52-51 2F1 0 0 16.0 3.0 2.5 29.0 41.0 0.7 7.9 1.0 0.2 0.2
- Tube Outer 0.5 15 30.0 7.2 6.4 37.0 8.0 0.7 8.3 0.2 1.8 0.5 0.4 0.4 Surface 2 60 30.0 16.0 6.9 37.0 5.8 0.8 2.9 0.8 0.6 0.4 0.9 ;
Deposit-free 5 150 35.0 17.0 6.9 35.0 5.7 0.8 0.4 0.5 0.5 1.0 Area 10 300 38.0 20.0 6.0 31.0 5.5 0.4 0.4 0.5 1.2 0 0 37.6 6.2 5.6 18.6 19.7 0.9 8.9 0.0 2.5 0.5 0.4 j 4 0.5 15 49.6 10.5 10.1 16.7 2.7 0.6 6.6 0.2 2.4 0.6 0.7 0.7 2 60 46.3 21.9 10.1 15.6 1.8 0.7 2.1 1.0 0.5 0.6 1.4 5 150 51.2 22.0 9.6 14.0 1.7 0.6 0.5 0.4 0.7 1.4 , 10 300 53.1 24.8 8.0 11.8 1.6 0.3 0.5 0.0 0.7 1.6 j I 90-28 2N1 0 0 2.8 1.6 18.0 75.0 0.4 2.4 0.0 0.0 Tube Outer 0.5 15 23.0 7.6 6.5 26.0 35.0 0.7 1.0 0.3 0.4
)
Surface 2 60 30.0 10.0 11.0 34.0 12.0 0.1 1.5 0.9 0.4 0.6 > Deposit-free 5 150 39.0 13.0 10.0 30.0 6.5 0.4 0.4 0.5 0.8 ( Area 10 300 47.0 15.0 9.1 23.0 5.1 0.4 0.2 0.6 0.9 l 0 0 10.8 5.9 18.9 59.2 0.8 4.4 0.1 0.0 i f 0.5 15 45.1 13.2 12.1 13.9 14.0 0.7 0.9 0.6 0.9 t 2 60 47.7 14.1 16.6 14.7 3.9 0.1 1.9 1.0 0.6 0.9 j 5 150 55.7 16.5 13.6 11.7 1.9 0.3 0.3 0.7 1.1 10 300 61.4 17.3 11.3 8.2 1.4 0.3 0.2 0.8 1.1 f
-i 2-51 I
s
i
-n
- y}a{h,~lky l c
OD Denosit Flake Specimens 52-51-2. 52-51-4. 133-33-3 & 133-33-9 s After a light sputter, the outer flake surfaces were found to be predomiantly composed of iron, oxygen and carbon (see Table 2-12). Lower levels of nickel, copper, silicon, titanium and sulfur were also : detected routinely on the outer surfaces. Energy shifts determined by XPS indicated the copper may have , been present as CuO. The sulfur levels were generally quite low (i.e., < 1.0 at%). Low levels of zinc l and trace levels of chlorine and calcium were occasionally detected. However, chromium was virtually absent at the outer surface with the exception of one analysis point on a flake from above the 1st TSP on 52-51 (52-51-4). l The inner flakes surfaces were Of similar composition, with the following exceptions: (1) nickel levels were generally higher, (2) significant levels of chromium were detected in most cases, and (3) besides sulfur and titanium, other elements (e.g., copper, silicon, zine and chlorine) were not found in ! appreciable quantities. Significant point-to-point variations in composition were noted on both surfaces by both SAM and XPS. j Table 2-12 SAM RESULTS ON OD DEPOSIT FLAKE SURFACES i Tube Section Sputter Elemental Composition
& Analysie Time Depth (Upper Table: etom % - Lower Teble: weight %)
Location (min) (nm) Ni l Cr l Fe l0 lC lS l Si lCl l Ti l Cu l Ce l Zn l P 52 51-2 Deposit Fiske: Outer 0 0 2.4 13.0 20.0 57.0 4.7 2.9 Surface 0.5 15 3.5 39.0 36.0 15.0 0.5 2.9 2.3 inner 0 0 14.0 3.1 22.0 61.0 0.3 0.2 surface 0.5 15 13.0 24.0 5.0 42.0 15.0 0.5 2.7 ; i Outer 0 0 6.4 33.2 14.6 31.3 6.0 8.4 Surface 0.5 15 6.1 64.4 17.0 5.3 0.5 2.4 4.3 inner 0 0 39.2 8.3 16.8 34.9 0.5 0.3 5 Surface 0.5 15 23.2 38.0 8.5 20.4 5.5 0.5 3.9 I 133-33-3 Deposit Flake: ; Outer 0 0 3.9 26.0 25.0 43.0 0.7 0.7 0.2 0.2 ; Surface 0.5 15 1.9 52.0 38.0 6.8 0.6 0.2 0.8 - Inner 0 0 16.0 2.6 22.0 57.0 0.9 0.2 0.2 1.1 l Surface 0.5 15 12.0 32.0 7.9 38.0 7.2 0.2 0.2 2.0 l Outer 0 0 8.6 54.7 15.1 19.5 0.8 0.7 0.3 0.3 Surface 0.5 15 3.0 77.0 16.1 2.2 0.5 0.2 1.0 inner 0 0 42.4 6.6 15.9 30.9 1.3 0.3 0.3 2.4 Surface 0.5 15 19.5 46.0 12.2 16.8 2.4 0.2 0.2 2.7 2-52 l I
l
-. j g
Tube Section Sputter Elemental Composition
& Analysis Time Depth (Upper Table: atom % - Lower Table: weight %)
Location (mini (nm) Ni Cr Fe O C S Si Cl TI Cu Ca Zn P 133-33-9 Deposit Flake: Outer 0 0 2.2 13.0 20.0 62.0 0.7 3.0 Surface 0.5 15 2.5 39.0 36.0 22.0 1.3 inner 0 0 13.0 12.0 19.0 55.0 0.6 ' Surface 0.5 15 21.0 15.0 9.0 36.0 18.0 0.3 1.0 Outer 0 0 6.0 33.9 14.9 34.7 1.6 8.9 ' Sudece 0.5 15 4.5 67.5 17.8 8.2 1.9 inner 0 0 31.6 27.7 12.6 27.3 0.8 Surface 0.5 15 36.6 23.2 14.9 17.1 6.4 0.3 1.4 52 51-4 Deposit Flake (Outer Surface): . Area 1 0 0 2.1 22.0 29.0 40.0 0.4 0.7 0.2 1.3 1.9 0.41 1.9 0.5 15 0.8 49.0 41.0 8.1 0.2 0.7
'i Area 2 0 0 3.7 7.2 24.0 37.0 22.0 0.4 2.9 0.8 1.3 0.9 1.1 O.5 15 2.9 8.6 42.0 39.0 4.5 0.4 1.9 0.9 0.8 Area 1 0 0 4.6 0.0 46.2 17.4 18.1 0.5 0.7 0.3 2.3 4.5 0.6 4.7 0.5 15 1.3 0.0 76.8 18.4 2.7 0.2 0.6 Area 2 0 0 7.0 12.0 43.1 19.0 8.5 0.4 2.6 1.2 2.7 1.2 2.3 0.5 15 4.5 11.8 62.0 16.5 1.4 0.3 1.4 1.1 0.8 i
52 51-4 Deposit Flake Onnar Surface): Area 1 0 0 21.0 I 22.0 54.0 0.7 2.0 0.5 15 44.0 3.2 34.0 17.0 0.4 0.1 0.0 - Area 2 0 0 11.0 6.8 20.0 60.0 0.3 1.7 , 0.5 15 4.4 34.0 33.0 28.0 0.4 Area 1 0 0 53.3 15.2 28.1 1.0 2.4 0.5 15 72.5 5.0 15.3 5.7 0.4 0.1 1.1 Area 2 0 0 29.6 17.4 14.7 33.0 0.4 4.9 0.5 15 8.5 62.6 17.4 11.1 0.4 2-53
l*. 2.2.12 Bulk Denosit Analyses Several techniques were used to analyze bulk tube deposits collected from both defect and non<fefect tube sections to establisa elemental composition and the chemical compounds present, as well as the density and amount of open porosity. A number of elemental analysis techniques were utilized to establish the concentrations of selected transition elements, alkali and alkali earth metals typically found in nuclear steam generating systems. The techniques used and analyzed elements are summarized below in Table 2-13. These analyses were performed at B&W's Alliance Research Center (ARC). Table 2-13
SUMMARY
OF ELEMENTAL ANALYSIS TECIINIQUES AND PURPOSE ANALYSIS TECHNIQUE PURPOSE Atomic Emission Spectroscopy (AES): Quantitative Elemental Analysis ; by Inductively Coupled Plasma (ICP-AES) Al, Ca, Cr, Cu, Fe, Pb, Mg, Mn, Ni, P, Ti, & Zn by Flame Emission Spectroscopy (ES) Nr & K : i ISE (lon Selective Electrode) Quantitative Elemental Analysis (Cl) [ Gravimetric Analysis Quantitative Elemental Analysis (Si) Combustion / Thermal Conductivity Ouantitative Elemental Analysis (C) Turbidimetric Analysis Quantitative Elemental Analysis (S) X-Ray Fluorescence (XRF) Qualitative Elemental Analysis [ (all elements > atomic number 11) - Compound analysis techniques included X-Ray Diffraction (XRD), Fourier Transform Spectroscopy (FTIR) and Raman Spectroscopy. The purpose of XRD was to identify crystalline compounds, such as metal oxides and/or sulfides present in concentrations of a few weight percent or more; XRD was performed at B&W's ARC. FTIR and Raman analysis were intended to identify crystalline, as well as amorphous compounds. In panicular, FrIR would be expected to identify various molecular species such as sulfate, silicate, phosphate and borate and other oxyanions. It was expected that Raman analysis would help establish chemical composition, stoichiometry, and other crystallographic phases which may have i been present. various functional groups associated with particular compounds. Both, FTIR and Raman l analyses, were performed at AECL's Whiteshell Laboratories. j Density, both bulk and skeletal, as well as open porosity volume and pore size distribution were quantified in selected deposit samples by mercury porosimetry. 'nis analysis was performed at AECL's a Chalk River Laboratories. I Selected deposit samples were also sent to Rockwell International for Mossbauer Spectroscopy to establish the oxidation state of iron in the deposits. This analysis was performed under separate contract 2-54
)
W-
DRMi : established by EPRI directly with Rockwell. However, results of this analysis were not available for this report. Lastly, gamma spectroscopy was performed to identify and quantify the radioisotopes present in the ! primary side deposits. A total of nine (9) deposit sm ples, as identified below, were utilized for analysis by selected analysis techniques as discussed above. Three (3) samples from the first freespan regions above the LTSF. These included: i
- One (1) sample from tube section 52-51-2 exhibiting IGA damage.
- One (1) sample from tube section 90-28-2 exhibiting IGA damage.
- One (1) sample from tube section 133-33 3, which did not exhibit IGA damage.
Bree (3) samples were taken from higher regions in the steam generator for comparison with the first span deposits. These included:
- One (1) sample from the second freespan region above the 1st TSP on tube section 52-51-4;
- One (1) sample from the 3rd and 4th freespan regions around the 4th TSP on tube section 133-33-9; !
e One (1) sample from the 3rd TSP intersection on tube section 133-33-9. Two (2) samples of the light-green colored deposits from the tube sheet crevice retion pst below the LTSF on tube sections 52-51-2 and 90-28-2. One (1) sample of primary side deposit collected off a 2-inch long segment from tube section 133-33-9. De results of the deposit analyses are summarized in Tables 2-14 and 2-15. The elemental analyses indicated the major elements were iron and oxygen (calculated as a balance). This is consistent with the XRD and FFIR analysis results, both of which detected major peaks for magnetite (Fe3OJ.' For all samples except the 90-28-21st freespan deposit, the atom ratio of O/Fe was about where it should be (i.e.,1.33); this sample may have contained some excess moisture. He next most prevalent element was nickel, which was typically present in quantities of a few weight percent. Chromium and copper were also detected consistently, but at levels typically below 1 %. Low levels (< 0.5%) of potassium, silicon and carbon were routinely detected, as were trace levels (s;0.1 %) of all other elements analyzed except phosphorous, which was not detected. Based on this limited analysis, most elements did not exhibit an appreciable tendency to partition to specific areas of the generator. Nickel, chromium, silicon and sulfur all tended to be present in slightly greater quantities at lower elevations, while the opposite behavior was noted for copper. The distribution of elements with respect to steam generator elevation is illustrated graphically in Figure 2-61. r 2No spectra could be obtained by backscatter Laser Raman Spectroscopy due to the intense absorption oflight by the magnetite, which is black. i 2-55
w, mad The mercury porosimetry analysis results indicated skeletal densities on the order of 4 to 4.7 g/cm'; this is just slightly lower than the density of magnetite (5.2 g/cm'). Bulk densities were significantly lower - (about 3 to 3.7 g/cm'), indicating open porosity levels of about 20% to 25%, with a pore diameter range of ~0.1 to 0.7 pm. The slightly lower skeletal densities might be partially explained by the presence of some closed porosity. In general, the densities increased, while porosity levels decreased, with ! increasing steam generator elevation. Table 2-14 DEPOSIT ANALYSIS RESULTS - SAMPLE LOCATION 52512 90-28-2 133 33-3 52-61 4 133 33-9 133 33-9 ! Freespen* *
- Freespan* *
- Freespen Freespan Freespan Freespen Analysis Analyses Above LTSF Above LTSF Above LTSF Above 1st TSP Near 3rd TSP At 3rd TSP Technique .
Elemental Analyses (wt %): Fe 68.10 % 55.68 % 65.53 % 70.55 % 69.39 % 70.53 % ICP 0' 26.98 % 36.23 % 26.94% 25.92 % 26.63 % 25.01 % By Balance Ni 3.01 % 5.52 % 4.75% 1.90 % 2.20 % 2.06% ICP Cr 0.57 % 0.87 % 1.42% 0.50 % 0.32 % 0.25 % ICP Cu 0.25 % 0.45% 0.14 % 0.14 % 0.60 % 1.15% ICP K O.18 % 0.17 % 0.17% 0.17 % 0.16 % 0.18% FAA Si 0.19 % 0.27 % 0.29 % 0.07 % 0.06 % 0.11 % Gravimetric C 0.22 % 0.24 % 0.24% - 0.28 % 0.22 % 0.22 % Combustion Cl 0.05 % 0.11 % 0.06 % 0.08 % 0.08 % 0.08% Electrode Na 0.06% 0.06% 0.06 % 0.07 % 0.05 % 0.06% FAA ; S 0.07 % 0.06 % 0.05% 0.04*A
- 0.01 % Turbidimetric At 0.06% 0.07 % 0.04 % 0.03 % 0.03 % 0.04% ICP Ca 0.05 % 0.06 % 0.06 % 0.05 % 0.05 % 0.04% ICP Pb 0.00 % 0.01 % 0.01 % 0.00 % 0.01 % 0.01 % ICP [
Mg 0.07 % 0.07 % 0.07 % 0.07 % 0.07 % 0.08% ICP Mn 0.06 % 0.06% 0.09 % 0.06 % 0.07 % 0.12% ICP Ti O.04 % 0.04 % 0.06 % 0.05% 0.03 % 0.03% ICP Zn 0.03 % 0.03 % 0.03% 0.01 % 0.02 % 0.02% ICP , p .. .. .. .. .. .. ICP
- Below 40 ppm; detection threshold
*
- Insufficient sample available.
* *
- Green deposits at LTSF were Fe & Ni by XRF; insufficient semple for XRD.
Compound Analysos: Fe30 Major Major Ma}or Major Major Major XRD/ FTIR g 1.38 2.27 1.44 1.28 1.34 1.24 Calculated Density Analysis (gfem'): Bulk 3.11 - . 3.02 3.74 - Hg Poros. Skeletal 4.31 - . 4.04 4.68 . Hg Poros. Open 27.8 % - - 25.3 % 20.1 % - Hg Poros. Porosity 0.12-0.69 pm l - - 0.12-0.59 pm 0.12-0.68 pm . Hg Poros. I 2-56 l l
DRAFT Table 2-15 GAMMA SCAN RESULTS ON ID TUBE DEPOSITS FROM TUBE SECTION 133-33-3 b Activity Isotope Specific Activity ( C /gm) 3 Contribution Co-60 1,587.00 71.8 % Co-58 546.20 24.7 % Sb-125 41.59 1.9% Mn-54 19.97 0.9% Ce-144 9.72 0.4% Co-57 6.22 0.3% TOTAL 2,210.70 100.0 % h i 4 9 2-57 l
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;8TH GRIND,80* IGA PATCH; NOTE HIGH SULFUR PEAK 2-76
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- 03:29 l
I C6??32-1 Disk 043 Fre:et= 04f iert- 1000 counts Diso= 1 E!apsed- 155 se:s CFYSTAL RIVER 3 - j 5;ECIMEN: 109-30-2D .; ath GRIND, 80 Leg. Ee Window, 10 kV. 1 Carbon Coated
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FIGURE 2-4B: lSEM/EDS RESULTS ON SPECIMEN 109-30-2D yg
^
- BTH GRIND. 80* IGA PATCH, NOTE INDICATIONS
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! 066190-1 Disk 043 Preset- Off 150 secs Vert- 5339 counts Disp. 1 Elapsed-CRYSTAL RIVER 3 SPECIMEN: 133-33-3, FLAKE {'
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l __ , 286147 l 27-Apr-1993 11:20: 43 Aute-VS 066207 Disk 043 Preset- Off
. Vert- 9205 counts Disp- 1 Elapsed- 150 secs I
CRYSTAL RIVER 3 l l SPECIMEN: 133-33-9, FLAKE EDS of entire area shown in photo 066 207. , Be Window, 20 kV., Uncoated Fe> Ei Fe Trace m
._ -- _ = _
Cyi - N1 11 I2 13 14 15 16 67 i8 19 (- 0.000 Range- 10.230 kev Integral 1 - 10.110 -> 303273 FIGURE 2-s r 6 : INNER (TOP) & OUTER (BOTTOM) EDS REULTS ON DEPOSIT FLAKE SURFACES FRgg SPECIMEN 133-33-9 1
DRAH TUBE SPECIMEN 52-51-2F1 Elemental Ratio 1.2
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0.0 0 50 100 150 200 250 300 Sputter Depth (nm) TUBE SPECIMEN 90-28-2N1 Elemental Ratio 1.2 Base' Metal Cr Level-~~~ ~
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TUBE SPECIMEN 52-51-2F1 Elemental Ratio : 1.0 ; l; : ; j '
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0.0 i 0 50 100 150 200 250 300 Sputter Depth (nm) i Near OD Mid4..ra.ck .. Crac.k.-T.ip .; FIGURE 2-sy: ELEMENTAL RATIO OF NICKEL IN GRAIN BOUNDARY CORROSION FILM RELATIVE TO BASE METAL , i
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0.0 ' O 50 100 150 200 250 300 Sputter Depth (nm) 52-51-2F1 90.-28..2N1 .. f FIGURE 2-co : ELEMENTAL RATIOS OF CHROMlUM & NICKEL IN OD ' l SURFACE CORROSION FILM RELATIVE TO BASE METAL-2-93 c
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Section 3 DATA ANALYSIS AND EVALUATION 3.1 Summary of Tube Decradation Tube damage was predominantly in the form of isolated, small patches of OD initiated intergranular attack (IGA), although some minor pitting was observed in a few instances. The IGA exhibited, in general, a classical " thumbnail" shape. A total of one-hundred eight (108) defects were observed in four tube sections with maximum and minimum depths of 62% and 1% throughwall, respectively and an overall average depth of 28% (a = 16%). The defect depths approximated a normal distribution (see Fig.3-1). Damage was primarily confined to the first free span region, although a few small defects were found within a few inches below the LTSF. The majority of the defects and those with any significant volume were concentrated in a region extending about 8 to 18 inches above the LTSF (see Fig. 3-2). It was also observed that many of the IGA patches were located along "old-appearing" axially oriented scratches, which were probaL:y created during tube installation. 3.2 Correlation with Eddy Current Testing In order to correlate the destructive examination data with the eddy current results, the defects were first grouped into sixty (60) " eddy current distinguishable" defects (i.e., defects spaced sufficiently far apart so as to be detected as separate indications by eddy current) as shown in Table 3-1.' The scatter plot shown in Figure 3-3 shows a general correlation between defect volume and depth as might be expected. In addition, this graph also illustrates that eddy current (field bobbin data) was more effective at detecting those defects with significant volumes. 'Ihis also would be expected since bobbin coil eddy current is a volume sensitive NDE technique. In general, defects with volumes of -40(104) in' or greater and depths of ~22% or greater were detected reliably (83%) by field bobbin coil. Detectability was somewhat worse for smaller (i.e., less volume) defects with the same depth range; for example, defects with volumes in the range of ~ 10 to 40(10*) in' and depths of ~ 22% or greater were detected at about a 48% frequency. This is further illustrated in the bar graphs of Figure 3-4, which provide a general indication of bobbin coil detectability (combined field and lab data). Detectability increases with increasing defect depth and volume. The combined bobbin coil data, shows defects with depths of 41 % to 50% throughwall were detected at a frequency of about 75%, while all deeper defects were detected. MRPC data showed similar behavior, but in general its detectability was lower than bobbin coil (see Fig. 3-5). It had been observed previously by eddy current analysts that many of the field MRPC indications l fell along a single angular position; this could easily be explained by the tendency for IGA patches to initiate at pre-existing axial scratches as noted in Section 3.1. A complete summary of eddy current detectability is provided in Table 3-2. The criteria used for this compilation of data was an axial spacing of about 0.3 inches. The volume of each defect was estimated by assuming an ellipsoid shape for the IGA. For defects , which were combined to form a composite " eddy current distinguishable" defect, axial extent and l l depths were determined by a weighted average (based on volume) and circumferential extents were summed. 4 3-1 e
m.,- TABLE 3-1
SUMMARY
OF EDDY CURRENT DISTINGUISIIABLE DEFECTS Tube Position Defect Ertent Eddy Current Results Section Defect Axial Cire. Axial Circ. Depth Vol. Bobbin Coil MRPC No. No. (inches) (*) (rnils) (*) (%TW) (10-* in') Field Lab Field Lab 90-28-2 AF 17.2 150' 28.9 2.0 51 % 3.0 S/N AD2/1 16.1 180'/315' 52.4 - 3.5 37 % 6.9 S/N AB 15.5 340' 54.4 8.3 30% 13.8 2 15.1 325* 38.2 1.3 30% 1.5 S/N X2/1 14.6 340*/110' 45.6 2.7 43 % 5.4 S/N S/N V2/1 ' 14.0 270'/350' 53.7 7.5 48 % 19.9 T2/1 13.2 110*/330' 36.3 7.8 50 % 14.5 S2/1 12.9 350'/110' 33.9 3.2 26*6 2.9 S/N O 12.3 340' 59.2 3.1 45% - 8.5 S/N O/N/M 11.5 340*/100*/290' 58.5 14.5 43 % 37.5 S/N S/N K 10.8' 290' 31.S 3.6 18 % 2.1 S/N 1/H/O 10.2 200'/10'/330' 71.5 17.3 49 % 62.3 S/N S/N S/N S/N AFC' 9.2 S/N E 7.8 340' 70.9 7.9 50 % 28.8 46 % 36% S/N S/N C/B 6.1 20'/315' 56.5 6.1 41 % 14.5 S/N S/N S/N S/N AFC' 1.0 S/N 52512 X 16.5 315' 40.3 2.0 - 32% 2.6 S/N U 15.3 315' 32.7 4.8 26 % 4.2 S 14.7 315' 63.7 8.3 33% 17.9 - R 14.1 250' 38.9 3.7 18 % 2.7 S/N S/N P 13.1 200* 43.9 5.3 33 % 7.9 N2/1 12.4 180'/260' 33.6 4.6 30% 4.8 L 11 4 180' 33.5 1.4 13% 0.6 S/N K2/1 11.0 250'/180' 42.7 7.8 45% 15.4 12/1 10.0 3508/270' 49.7 15.2 42% 32.9 S/N S/N S/N GIF 8.9 315'/350' 63.9 5.7 47 % 19.3 S/N S/N S/N AFC' 7.9 S/N S/N S/N S/N D 6.5 265' 60.9 8.4 34% 17.9 S/N S/N S/N S/N B -1.0 20* 38.6 2.0 38 % 3.0 97 91-2 W 14.1 105' 60.6 9.6 54% 32.0 67 % S/N S/N S/N AFC' 12.3 S/N U/T/S 11.5 245'/90'/95* 58.2 26.0 46% 70.9 S/N S/N S/N R1 9.3 350' 11.0 6.1 4% 0.3 S/N S/N AFC* 8.6 S/N S/N S/N S/N P/O 8.3 90*/15' 74.4 18.0 50 % 68.8 67 % S/N 3-2 _. . . . - - -- -. _ _ _ _ _ _ _ _ _ _ _ _ _ ~
h{ W % r% ? 1 Nd d - h I l Tube Position Defect Extent Eddy Current Results Section Defect Axial Circ. Axial Cire. Depth Vol. Bobbin Coil MRPC No. No. (inches) (*) (rrsts) (*) (%TW) (10* in') Field Lab Field Lab 97912 M 7.1 320' 19.7 3.3 16% 1.1 (cont.) K 6.6 225' 49.8 3.8 29 % 5.7 I 5.6 355' 6.7 2.4 4% 0.1 G 3.3 20' 13.1 0.7 5% 0.0 E2/1/D 2.8 20*/285'/350' 13.5 5.7 6% 0.5 B 1.1 285* 16.3 2.5 6 96 0.2 AFC' -1.7 S/N 106-32 2 BG/BF 16.6 90'/30' 55.1 7.6 1596 6.2 BD/BC 15.6 50'/30' 63.5 12.8 31 % 25.5 14.9 90'/35'/45' 35.3 12.9 20 % 9.4 BB/Pf/A AY 14.6 220' 55.3 16.1 36% 32.9 S/N S/N AX 14.3 30' 39.9 9.6 32 % 12.6 ATgU/ 13.2 135'/45'/60' 46.8 42.3 34 % 69.2 S/N S/N S/N AR 12.3 90' 44.9 12.8 19 % 11.2 S/N A02/1 11.7 180*/90' 38.1 16.0 35 % 21.9 S/N AP/AO 11.2 20'/90' 48.0 14.4 27 % 19.2 S/N Agp 10.8 g' ' '3/ gl 26.5 31.9 27 % 23.5 S/N S/N S/N AL2/1 10.5 25'/80*/75' 27.7 10.2 11 % 3.2 S/N AJ/AK 9.9 190'/25' 61.3 22.8 39 % 56.0 S/N S/N S/N AG2/AH 8.8 100'/60* 59.1 13.0 35 % 27.6 S/N S/N S/N AFC' 8.2 S/N A{lg/ 7.7 22g*fq0' 62.5 27.5 24 % 42.4 S/N S/N AC1/AB 7.4 60'/70' 53.5 11.5 18 % 11.4 Z/AA 7.0 180'/200* 46.2 18.6 34 % 30.0 X2p/X 6.4 65'/85'/50' 33.7 20.4 28 % 19.8 S/N SIN S/N S/N ' V2 5.3 125' 40.8 2.1 14 % 1.2 S/N S/N O -0.6 190' 17.1 3.2 7% 0.4 N -1.8 270' 5.4 1.0 1596 0.1 LgJ 2.3 280ff4gf(05' 17.3 31.3 14 % 7.8 F -3.4 1 60' 12.0 9.3 9% 1.0 E -3.9 145' 18.2 3.4 23 % 1.5 C -5.4 350' 6.7 4.9 7% 0.2
- AFC -' Apparent False Call l
a 3-3 i
hkt n
]Y; Mffri=f TABLE 3-2 EDDY CURRENT DETECTABILITY
SUMMARY
Eddy FIELD LAB COMBINED Current Size Total No. No. Percent No. Percent No. Percent , Technique Criterie (%TW) Defects Detected Detected Detected Detected Detected Detected Bobbin Depth 0-10 8 0 0% 0 0% 0 0% l Coif 11-20 12 0 0% 1 8% 1 8% l 21 30 11 4 36 % 5 45% 6 55% 31-40 14 4 29 % 5 36% 5 36% 41-50 13 6 46% 9 69 % 10 77 % , 51-60 L L 50 % 1 100 % L 100 % : Total: 60 15 25 % 22 37 % 24 40 % Volume 0-12 34 0 0% 7 21 % 7- 21 % (108 in") 13-24 13 6 46% 5 38 % 6 46% , 25-36 7 4 57 % 5 71 % 6 86% f 37-48 1 1 100 % 1 100 % 1 100 % 49-60 2 2 100 % 2 100 % 2 100 % 1172 3 L 67 % 1 100 % 3 100 % Total: 60 15 25% 23 38 % 25 42 % MRPC Depth 0-10 % 8 1 13 % 1 13 % 1 13 % 11 20 % 12 3 25% 3 25 % 5 42% 21-30 % 11 2 18 % 1 9% 2 18% 31-40 % 14 5 3E% 4 29 % 7 50 % ; 41 50 % 13 8 62 % 9 69 % 10 77% 51 60 % 1 1 50 % 1 50 % 1 50 % Totah 60 20 33 % 19 32% 26 43% Volurne 0-12 34 3 9% 6 18 % 8 24% (10'* in') 13 24 13 6 46% 3 23 % 6 46% 24-36 7 4 57 % 5 71 % 5 71% 37-48 1 0 0% 0 0% 0 0% 49-60 2 2 100 % -1 50 % 2 100 % ; 01-72 3 3 100 % 1 67 % 1 100 % Total: 60 18 30 % 17 28 % 24 40 % i F F i 3-4 1 w avageo e.,W,9, mmw, --, Se+p.. - ~ . _ ~.
DRAFT 3.3 Review of Prior Eddy Current Data A number of reviews of historical eddy current data for the CR-3 steam generators were done (2,3,4_) in an attempt to answer the following questions: (1) When did the observed defects initiate? i (2) Is the corrosion process active or inactive? Only a limited number of tubes having defect indications had been inspected in the interval between the , baseline inspection (1976) and the May 1992 refueling outage. Only 3 of the 6 tubes removed from the I A steam generator (52-51,1%-32, and 109-30) had eddy current data from the 2 previous outages (3/89 and 4/90). Thirty-seven tubes in the A steam generator had eddy current data from the previous outage ; (4/90). l An earlier review (2), carried out in 1990 for 4 tubes (40-47,46-46,52-51, and 52-81), concluded that the defect indicatiens recorded for these 4 tubes during the April 1990 refueling outage were definitely pr esent as early as March 1980, but were not present at the time of the baseline inspection (1976). From this limited review, one could conclude that the defects in those tubes occurred between 1976 and 1980. Krzywosz (1) performed an independent review of prior eddy current data for the 3 pulled tubes (52-51, 106-32, and 109-30) to determine if the IGA could be attributed to a one-time event. To account for different probe sizes and cable lengths used in the 3 inspections, he normalized the 600 kHz channel data for a 100% calibration hole to 5 volts peak-to-peak at a phase angle of 40'. From his review (Appendix C), he concluded the following: (1) The eddy current indications confirmed as IGA patches by metallurgical test results were present in 1989. (2) The IGA patches have not grown since 1989, but have remained stable and dormant. (3) There were no new detectable IGA indications since 1989. In Reference 4, eddy current signals were compared for indications detected during both the 4/90 and 5/92 refueling outages. Based on the indications that could be compared, the average %TW growth was 6%, with a standard deviation of 17%, while the average signal voltage decreased by 0.21 volts. Based on this information, it was concluded in Reference 4 that the defects are growing very slowly, if at all. The reviews summarized above are consistent in their conclusions, viz., the patches of IGA present on the A steam generator tubes initiated prior to March 1989, possibly earlier than March 1980, and are currently dormant or at least growing very slowly. Based on the information presented in Reference 3, new patches of IGA are not initiating in the first tube span of the A steam generator. 3-5 _ _ _ _ _ _ -_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - ~
l 3.4 2ffect of Defects on Pressure Holdine Capability of Tubing l The two tube sections which were burst tested exhibited relatively high burst pressures (see tabularized data below). TABLE 3-3 BURST TEST DATA i Defect Information Tube Section No. Burst Pressure No. Depth Length 97-91-2 12,400 psi O 54% TW 75.6 mils 106-32-2 11,400 psi AG2 40% TW 62.3 mils Since no defect-free CR-3 tubing was burst tested, nor were any tensile tests of the pulled tube sections performed, a direct correlation to burst pressure degradation could not be made. However, Virgin (i.e., defect-free) OTSG tubing with a nominal wall thickness of 37.5 mils would be expected to have a burst pressure of ~ l1,300 psi based on typical values of yield (50 ksi) and ultimate (100 ksi) strengths for stress relieved Alloy 600 tubing (5). Therefore, it can be concluded that no significant degradation in burst pressure was exhibited by the defected CR-3 tubing. Furthermore, burst pressure is highly dependent (exponential relationship) upon defect length, as well as depth. Since these defects are, in general, very short (< 3 mm) their effect on burst pressure would be expected to be minimal. The expected drop in burst pressure associated with the above defects is small (~ 18% decrease based on an empirical relationship developed by D. Azodi et al), which is consistent with the observed burst pressures (6). 1 I l l j 3-6 l l
3.5 Plant Chemistry Data Review (summary of Sue Hobart's paper....to be received) 3-7
-- - - - - - - - - .- ____-__________________________________3
I 3.6 Susceptibility of CR-3 Steam Generator Tubine to IGA Following fabrication, the CR-3 once-through steam generators were subjected to a full-furnace stress ; relief at 600 to 620'C to reduce residual stresses. This step in the manufacturing process resulted in a l sensitized tubing microstructure that subsequently proved to be resistant to caustic stress corrosion cracking. Following an extensive review of laboratory data and operating plant experience, Koch and Miglin (2) concluded that "in caustic environments in which mill-annealed Alloy 600 undergoes intergranular stress corrosion cracking (IGSCC), sensitized and thermally treated Alloy 600 is far less susceptible to IGSCC (than mill-annealed Alloy 600)." There have not, in fact, been any documented cases of caustic IGSCC in operating OTSGs. The " sensitized" Alloy 600 microstructure is, however, susceptible to intergranular attack (IGA, IGSCC) in acidic solutions containing reduced sulfur oxyanions, even when the sulfur is present in small quantities
@). This form of corrosion has been observed at 3 operating plants (TMI-1, ANO-1, and Oconee 1),
all of which have once-through steam generators with sensitized Alloy 600 tubing. At TMI-1, the attack was intergranular and initiated from the primary side (tube ID). It was postulated that the corrosion occurred with the plant shut down, the reactor coolant level lowered, and the RCS open to the air (2,H). The source of sulfur was identified as sodium thiosulfate, Na2S2 0, 3 from the containment spray system that had accidently leaked into the RCS. At Arkansas Nuclear One-1, intergranular attack occurred from the secondary side of the tubes in the upper regions of the steam generator. Based on examination of pulled tubes, it was postulated that the IGA was caused by sulfur oxyanions at ambient temperatures during a long layup period @,11). The source of sulfur was thought to be the condensate polishing system; i.e., either regenerant chemicals or thermally degraded resin fines. Localized regions, ~0.020" X 0.040" X 20% TW, of intergranular penetrations were identified just within the lower tubesheet crevice on the OD of a tube removed from the Oconee 1-B steam generator in 1981. Surface chemistry analysis suggested that "the localized intergranular attack may be due to a synergistie interaction of chlorine, sulfur, and possibly silicon" (12). Basically, sulfur-induced corrosion mechanisms can be divided into at least two regimes: (1) reduced sulfur IGA of sensitized Alloy 600 in oxygenated enviromnents at low temperatures (< 170'F), and (2) IGSCC and pitting in deaerated acidic sulfate solutions at high temperatures (D,14). Corrosion at high teraperatures by acid sulfates has been implicated at Millstone 2 (M,M), Connecticut Yankee (jl), and ' St. Lucie 1 (JJ), and investigated extensively in the laboratory (H). However, the high temperature mechanisms typically result in severe general corrosion or wastage (H,20), which is not consistent with the CR-3 defect morphology. Corrosion of Alloy 600 by reduced sulfur species requires the presence of one or more aggressive species such as sulfite, thiosulfate, sulfide, or polythionate. The most common source of sulfur species, however, are sulfates (SO/). Sulfates are unintentionally introduced into the steam generators via several sources, including makeup water, condenser leaks, improper regeneration of makeup demineralizers and condensate polishers, and leakage of cation resins or cation resin fragments from the demineralizers and condensate polishers (@ In high temperature deaerated environments, in the presence of reducing chemicals such as hydr ,pn or hydrazine, sulfates are not thermodynamically stable and can be reduced to a more reactive state; e.g., sulfides. In these environments, silica may act as a catalyst in accelerating the reduction of sulfates to the more reactive sulfides (22). 3-8
5 k , As noted earlier, the most common mode of attack by reduced sulfur species is intergranular ctfr o. in an oxygenated et ironment at temperatures less than 170*F. However, more recent studies by Sala, Combrade, et.al. Q 3), suggest that sulfides inhibit the formation of protective oxides in deaerated caustic and neutral environments as well, leaving the alloy more susceptible to intergranular attack by other species, e.g., caustic, at normal operating temperatures. Thus, for the CR-3 steam generators, corrosion by species other than reduced sulfur oxyanions cannot be entirely ruled out. 3-9 .a ._,..-4-.,, w ,, , . - - - - e
- sh. th 4
g PERCENTAGE OF TOTAL IGA PATCHES j 30% 1 - 25% ---.E"'~~', ' 1 ./ ., ( . . i .
- j. / , i i 20% - - - - - - - - -
-./- -- - - - - - - - - -
- - - - ' '. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ -
a g 15% ---
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0% 20 % 40% 60 % 80 % 10E N i DEPTH (%TW) > m FIGURE 3-1: W DISTRIBUTION OF IGA PATCH DEPTHS (108 DEFECTS)
i DEFECT FREQUENCY VS AXIAL POSITION i 20% 1
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l MRPC DETECTABILITY VS DEPTH i so
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.. .- - 1
Section 4 DISCUSSION OF RESULTS As noted in Section 2, the majority of the " spots" ofintergranular attack were contained within a region extending about 8 to 18 inches above the lower tubesheet secondary face (LTSF) of the "B" steam generator. Coincidentally, the affected tubes appear to be just outside the sludge pile as it would have existed in the late 1970's through the early 1980's (Figure 4-1). This would suggest a relationship, either direct or indirect, between the occurrence of IGA and the sludge pile. The IGA was confined to spots on the OD tube surface where the deposits were thinner than the bulk deposit, giving a scalloped appearance to the deposit. Underneath these deposits, the surface of the tube appeared to be " stained." These stained areas were enriched in chromium and surrounded by rings of deposit rich in silica and alumina. After descaling, the tube metal in the " stained" regions appeared to have been chemically etched. Significant levels of sulfur were found to be incorporated in the tube OD surface and grain boundary corrosion films. Levels of 2 to 5 wt% sulfur were typically observed on the IGA fracture surfaces, while levels in the OD corrosion film were substantially lower (less than I wt%, predominantly as sulfate although some sulfide was also detected). It was also observed that the corrosion films were, in general, depleted in nickel and enriched with chromium (Figure 4-2). 'lhis behavior was slightly more pronounced for the OD corrosion film. This provides an indication that the corrosion films were not formed under strongly caustic conditions (2_4,25), but could have formed in mildly alkaline to acidic solutions. As discussed in Section 3.6, the presence of sulfur in the grain boundary corrosion films is significant in that stress-relieved (sensitized) Alloy 600 is quite susceptible to intergranular attack by sulfur oxyanions. In general, acidic-oxidizing conditions (26) and temperatures less than ~ 170*F (77'C) are required for reduced sulfur IGA (26). As noted in the previous paragraph, acidic conditions would be consistent with the corrosion film chemistry observed on tM CR-3 tubes. In addition, deposits in one IGA location revealed the presence of copper oxide, which may also be indicative oflocalized oxidizing conditions. As noted in Section 3.3, historical eddy current data, although limited, suggests that corrosion damage in the B steam generator occurred prior to March 1980. Assuming this is correct, the observed IGA would have occurred under conditions that would have been present during and shortly after intial startup. A review of plant operating information (i.e., operating procedures, layup practices, maintenance records, etc.) during the period from startup through 1983 (22) determined that several incidences occurred during which one of the steam generators might have boiled dry following a loss of feedwater event'. Such an event could explain the relationship of the defects to the sludge pile mentioned earlier. Following a loss of feedwater transient and subsequent loss of inventory in the affected steam generator, boiling in the sludge pile could have " splattered" the sludge onto adjacent tube surfaces where they would have " baked on", forming sites for underdeposit corrosion. A similar event occurred at Indian Point No. 3 in 1981 (21) where it was concluded that "in the inner core region of the steam generators some sludge had spattered and then caked on the tubes, because of some local thermohydraulic condition, such as local boiling, during a previous operation. The sludge deposits on the tubes acted as crevices and promoted An Emergency Feedwater Initiation and Control (EFIC) system was installed at CR-3 in 1985 to provide for automatic initiation of emergency feedwater. 4-1
DRAFT m-wastage corrosion beneath them, when the oxygen concentration was high at the time of cool down." Since the observed corrosion most likely occurred during plant shutdown (possibly during or following an event such as that described above), air ingress during shutdown operations or during the subsequent lay-up period could have created conditions favorable to attack by sulfur oxyanions, assuming that reduced sulfur species were present. It is known that wet lay-up practices in the period following initial startup resulted in poor oxygen control (22). In addition, it has been observed recently that oxygen excursions to 1000 ppb in the condensate occur at ~250*F during cooldown (22). The same study of plant operations found that there were numerous incidents of resin leakage from the condensate polishers and frequent repair / maintenance of resin traps in the 1981-1982 time frame. Thus, condensate polishing operations would be a likely source of resin ingress.5 Hydrogen form cation resins provide an interesting candidate source for the sulfur contamination in that they can release significant amounts of sulfur (they contain better than 10 wt% sulfur) upon thermal decomposition over a temperature range of ~ 170*F to 536*F (3D,3.1). Also, breakdown of the resins proceeds through a melted form that could partially coat the tube surface (3D). This could explain the stains observed on the CR-3 tubes, which may have resulted in localized under-bead attack of the tubes during the initial stages of the melting process and interference with subsequent deposition processes. The enriched-chromium scale observed within these stains is also consistent with this form of attack (3Q). Fresh attack of Alloy 600 by sulfur oxyanions would generally produce a film containing very high levels of sulfur as sulfide (i.e., > 10 wt%) (3). Since this was not observed in the CR-3 tubes, it seems probable that the IGA had not occurred recently, and some of the sulfur had been washed away. This would be consistent with the prior eddy current data and could also explain the lower levels of sulfur on the OD tube surface compared to the grain boundary films. l 8 Several modifications to the condensate polishing operations were made in 1982, including the change to a gel type resin that is not regenerated, but replaced when exhausted. 4-2 k-
i i g M'- DRAFT i Figure 4-1 e i r i h t I; 6 E
'h 6
h L i T h B i I I I i f f t I' 4-3
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..q.. ..g.. . .E. .
ELEMENTAL COMPOSITION OF TUBE OD FILM
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,-3 Analysis Depth (nm) i Nickel 52-51-2 Nickel 90-28-2 Nickel Tuba OD Ductile Tube.
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FIGURE 4-2: NICKEL AND CHROMlUM COMPOSITION OF GRAIN BOUNDARY AND TUBE OD SURFACE CORROSION FILMS 4-4
DRMY
+
Section 5 I CONCLUSIONS /RECOMME!iDATIONS In summary, several observations were made during the tube examination and later that are pertinent to the damage mechanism, including:
- Tube wall degradation in the first span region of the CR-3 B steam generator is in the form of :
small, relatively shallow, isolated patches of OD-initiated IGA. t
- Throughwall penetration ranged from 1% to 62%, with an average depth of 28% and having i axial and circumferential extents of less than 0.1 inch. l t
- The damage was concentrated in an area extending 8 to 18 inches above the secondary face of !
the lower tube sheet and was associated with a non-uniform deposit pattern; specifically, spots i of thinner deposit with an underlying chromium-rich scale surrounded by a ring of silica and alumina deposits. i
- The grain boundary and tube OD surface corrosion films contained significant amounts of sulfur, ;
and were depleted in nickel and enriched in chromium indicating an acidic to mildly alkaline l environment.
- Review of prior eddy current data suggests that the IGA initiated as early as 1980 and is currently ;
dormant or at leat growing very slowly. a Based on these observations, the following conclusions were reached:
- The observed corrosion was likely caused by reduced sulfur species at a temperature ofless than ;
170*F sometime during the period from startup (1977) to early 1980, probably closer to the 1 latter. It is postulated that the steam generator boiled dry during a loss-of-feedwater transient. During ei ther the boildown or during the subsequent feeding, the sludge, which was still light and fluffy (or mud-like) vs the piles of spalled deposit observed later on, splattered (or geysered) up and deposited on the tube walls. This established sites for subsequent underdeposit corrosion.
- The sludge and tube deposits contained significant levels of sulfate from chronic leakage of cation ,
resin from the condensate polishers (or a significant sulfur intusion occurred). The sulfate was subsequently reduced to sulfides by hydrazine (or other, including silica or metal ions). [ Corrosion could then have occurred following concentration of the sylfides under the deposit during a period of poor oxygen control (e.g., during cooldown or heatup operations). Conversely, resin beads or fines could have adhered to the tube wall during the boildown, melted, and provided local acidic conditions and sulfur species that subsequently attacked the affected tubes during or following cooldown operations.
- Propagation ceased when conditions were no longer favorable to corrosion (sulfides were depleted, e.g.).
5-1 .
Additional information obtained during the examination includes the following: DRAFT'
- Bobbin coil detectability was good and improved with increasing defect depth and volume; all defects wi:h depths greater than 50% throughwall were detected by bobbin coil.
- In general, detectability with the MRPC was not as good as with the bobbin coil probe, although defects with the largest affected volumes were reliably detc ad with both probes.
- The influence on tube burst pressure for these defects is relatively small (i.e., less than a 20%
decrease). e i 5 i 5-2 I l
- ~., .
-f i
Section 6 ! REFERENCES l t
- 1. BWNS Document No. 1222047A-00, "UT-360 Final Report: Crystal River 3 Tube Pull "B" SG, ;
September,1992," October 1,1992. [
- 2. H. L. Smith, " Crystal River 3 Eddy Current Review on Selected Tubes," BWNS Report l 1208687, January,1991. ;
- 3. K. Krzywosz, " Review of Successive Eddy Current Data on Pulled Steam Generator Tubes from l Crystal River Unit 3,* EPRI NDE Center Letter Report, March 24,1993, i
- 4. J, C. Brown, Crystal River-3 Evaluation of First Span Defect Indications," BWNS Document 51-1218868-00, (DATE?)
- 5. B. Cochet and B. Flesch, " Crack Stability Criteria in Steam Generator Tubes", Structural . j Mechanics in Reactor Technolocv, Volume D: Experience with Structures and Components in !
Operating Reactors,9th International Conference,Lausanne Switzerland, August 1987, pp. 413 - 419. ;
- 6. D. Azodi, H. Schulz and R. Arenz, " Crack Stability Criteria in Steam Generator Tubes", ,
l Structural Mechanics in Reactor Technology, Volume D: Experience with Structures and Components in Operating Reactors,9th International Conference,Lausanne, Switzerland, August . .j 1987, pp. 413 - 419. 4
- 7. D.W. Koch and B.P. Miglin, " Literature Review - OTSG Secondary-Side Tube IGA / SCC Evaluation," BWNS Document No. 51-1177882-00, January 1990. ,
- 8. A.K. Agrawal, et. al., " Evaluation of Alloy 600 Tube A77-34 from Steam Generator A of i Arkansas Nuclear One, Unit 1, EPRI Report No. NP-4504-LD, Project S304-11, March 1986.
- 9. R.L. Jones, et.al., "The Origin of the Extensive Cracking of the Steam Generator Tubing at TMI !
Unit 1," Corrosion /83, Paper No.141, April 1983.
- 10. A.K. Agrawal, et.al., " Failure Analysis of Inconel 600 Tubes from OTSG A and B of Three ;
Mile Island Unit-1", Battelle Columbus Laboratories, June 1982.
- 11. Inman, S.C., " Examination of OTSG Tubes B73 and Bil2-19 from ANO Final Report," l' RDD:84:530344:02, June 10,1983.
- 12. E.B.S. Pardue, et.al., " Evaluation of the Lower Tubesheet Region of an Oconee 1 Steam I Generator Tube," EPRI NP-3026-LD, July 1983. i
- 13. S.L. Harper, et.al., "The Role of Sulfur in the Corrosion of NSG," Proceedines of the Third International Symoosium on the Environmental Decradation of Materials in Nuclear Power -
Systems - Water Reactors," August 1987. ! 6-1 : 1
DRMT 14 P.L. Daniel, " Sulfur Induced Corrosion in Nuclear Steam Generators", B&W Report No. , RDD:83:2341, September 1983.
- 15. J.F. Hall, " Destructive Examination of Steam Generator Tubes Removed from Millstone Point Unit 2," EPRI NP-4737-LD, July 1986.
- 16. S.C. Inman, et.al., " Examination of Steam Generator Tube Sections from the Millstone Point Unit 2 Nuclear Power Plant," EPRI NP-4829-LD, October 1986.
l
- 17. D.E. Powell and L.J. Laskowsk.i, " Destructive Examination Results of Steam Generator Tubing Removed from Connecticut Yankee during 1984 Refueling Outage," Proceedines of the Third International Symnosium on the Environmental Decradation of Materials ir. Nuclear Power Systems - Water Reactors," Traverse City, MI, August 1987.
- 18. G.O. Hayner et al., " Examination of Tubes Removed from St. Lucie Unit I and Investigation of the Causes of Corrosion", Proceedines of the Third International Symoosiuin on the E_nvironmental Deeradation of Materials in Nuclear Power Systems - Water Reactors, Traverse City, MI, August 1987, pp. 449 - 459.
- 19. J.F. Newman, " Stress Corrosion of Alloy 600 and 690 in Acidic Sulfate Solutions at Elevated Temperatures", EPRI Report No. NP-3043, Project S191-1, October 1983.
- 20. W.H. Cullen, et.al., " IGA /lGSCC of Alloy 600 in Acidic Sulfate and Chloride Solutions,"
Proceedines of the Fifth International Symoosium on the Environmental Decradation of Materials in Nuclear Power Systems - Water Reactors, Monterey, CA, August 1991, pp. 780-788.
- 21. W.E. Allmon and S.J. Potterton, " Conditions for the Chemical Reduction of Sulfates in an Aqueous Environment," 1985 Nuclear Chemistry Technology Update, Lynchburg, VA, November 20-22, 1985.
- 22. B. Sala, et.al., " Chemistry of Sulfur in High Temperature Water - Reduction of Sulfates,"
Proceedines of the Fifth International Symposium on the Environmental Decradation of Materials in Nuclear Power Systems - Water Reactors. Monterey, CA. August 1991, pp. 502-510.
- 23. P. Combrade, et.al., "Effect of Sulfur on theProtective Layers on Alloys 600 and 690 in Low and High Temperature Environments," Proceednes of the Fourth International Symnosium on the Environmental Decradation of Materials in Nuclear Power Systems - Water Reactors, Jekyll Island, GA, August 1989, pp. 5 5-95.
- 24. J.B. Lumsden and P.J. Stocker, "The Relationship Between Surface Oxide Compositions and the}}