ML113530085
| ML113530085 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 12/16/2011 |
| From: | Amend W Structural Integrity Associates |
| To: | Altadonna R Entergy Nuclear Operations, NRC/EDO |
| SECY RAS | |
| Shared Package | |
| ML113530062 | List: |
| References | |
| RAS 21566, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 | |
| Download: ML113530085 (43) | |
Text
NYS000175 Submitted: December 16, 2011
( ; Structural Integrity Associates, Inc.
Cerritos, CA 90703 Phone: 562-402-3076 Fax: 562-924-928i www.structint.com bamend @structint.com May 15, 2009 Mr. Robert Altadonna Indian Point Energy Center 295 Broadway PO Box 308 Buchanan, NY 10511-0308 Project:. 0900235.00 Report: 0900235.402 RO
Subject:
Analysis of 8" Condensate Water Storage Tank Return Line CD-183 Final report
Dear Robert:
The report of our failure analysis of the leaking condensate piping is attached for your review. This final version contains no changes to Draft B, (other than the date of distribution and an updated report number) which you have reviewed and approved. Please contact me if you have any technical questions about this report, or Ken Rach for questions regarding any administrative issues about this project.
Best Regards,
~dJ Associate Annapolis, MD Austin, TX Centennial, CO Cerritos, CA Charlotte, NC Chattanooga, TN Oakville, Ontario, Canada South Jordon, UT Stonington, CT Uniontown, OH 411}571-0861 512-533-9191 303-792-0077 562-402*3076 704-597-5554 423-553-1180 905-829-9817 801-676-0216 861}536-3982 330-899-9753 IPEC00202315 IPEC00202315
{J Structural Integrity Associates, Inc.
Cerritos, CA 90703 Phone: 562-402-3076 Fax: 562-924-9281 www.structint.com Project 0900235.00 Report No. 0900235.402 May 15,2009 ANALYSIS OF 8" CONDENSATE RETURN LINE FAlLURE Prepared For:
Entergy, Indian Point Nuclear Station Prepared By:
Structural Integrity Associates, Inc.
Cerritos, California Prepared By: Date: May 8, 2009 Bill Amend, P .E.
Associate Reviewed By: : Date: May 11, 2009 George Licina Chief Materials Consultant Approved By: _ _,___ _ _ _ _ __ Date: _May 15,2009 Ken Rach Associate Annapolis, MD Austin, TX Centennial, CO Cerritos, CA Charlotte, NC Chattanooga, TN Oakville, Ontario, Canada South Jordon, UT Stonington, CT Uniontown, OH 410-571-0861 512-533-9191 303-792-0077 562-402-3076 704-597-5554 423-553-1180 905*829-9817 801-676-0216 86(}536-3982 330-899-9753 IPEC00202316 IPEC00202316
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 2 REVISION CONTROL SHEET Document 090023 5.402 Number:
Title:
Analysis Of 8"Condensate Return Line Failure Client: Entergy- Indian Point Nuclear Station SI Project 0900235.00 Number:
Section Pages Revision Date Comments All All Draft A 4/9/09 Initial Draft for Review All All Draft B 5/8/09 Second draft for Review All All Final 5/15/09 No changes to draft B tJ Structural Integrity Associates, Inc.
IPEC00202317 IPEC00202317
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 3 CONTENTS Executive Summary ...................................................................................................................... 5 Introduction ................................................................................................................................... 5 Background Information ............................................................................................................... 6 Analysis and Results ................................................................................................................... 13 Summary ..................................................................................................................................... 59 Conclusions ................................................................................................................................. 60 Recommendations ....................................................................................................................... 61 Appendix A Observations by Entergy Engineering Staff Regarding the Excavation Conditions
..................................................................................................................................................... 62 FIGURES Figure 1- View of pipe coating as observed in the excavation by Entergy Staff.. ........................ 10 Figure 2 - Photograph of pipe in the excavation before removal of the pipe sample ................... 11 Figure 3- Detail of previous figure showing angular rocks in the backfill .................................. 12 Figure 4- Shipping container for pipe sample, as-received on March 23, 2009 .......................... 16 Figure 5- Pipe sample as-received in the shipping container. I ................................................... 16 Figure 6 - Pipe sample as received, view 1................................................................................... 17 Figure 7 - Pipe sample, as-received view 2 .................................................................................. 17 Figure 8 - Pipe sample, as-received, view 3 ................................................................................. 17 Figure 9 - Pipe sample, as-received , view 4. Arrow points to location ofleak .......................... 18 Figure 10- Pipe sample marked with red boxes to show locations of samples removed for further analysis ...................................................................................................................... 18 Figure 11 - "YS" stamp mark on pipe ........................................................................................... 19 Figure 12- API monogram stamp mark on pipe .......................................................................... 19 Figure 13- Manufacturer's stamp marks on the neutral axis of the elbow ................................... 20 Figure 14 - Manufacturer's stamp mark after light abrasion with sandpaper............................... 20 Figure 15 - Map of external corrosion ......................................................................................... 21 Figure 16- External corrosion on elbow (as-received condition) designated Area 0 .................. 23 Figure 17- External corrosion on the extrados of the elbow, as-received; designated Area 1 .... 24 Figure 18-- Extrados of ell after cleaning, Area 1. ....................................................................... 25 Figure 19 Detail of corrosion in Area 4.1 .................................................................................. 26 Figure 20- Area of Area 4.2 after cleaning by glass bead blasting .............................................. 27 Figure 21 -Detail of corrosion on girth weld in the location designated Area 5 ......................... 28 Figure 22 Second view showing detail ofthe corrosion undercutting the toe of the weld ........ 29 Figure 23- External corrosion on the pipe (as-received condition), designated Area 6. Note absence of corrosion around this pit. ......................................................................... 30 Figure 24- Outside surface of pipe (as received) showing leak and three areas of corrosion in addition to identifying "YS" and "API" stamp marks. Areas designated 7, 8, and 9
................................................................................................................................... 31 Figure 25 Detail of Area 9 (as received) showing multitudes of small overlapping pits of various sizes, resulting in an almost spongy appearance .......................................... 32 tJ Structural Integrity Associates, Inc.
IPEC00202318 IPEC00202318
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 4 Figure 26- Another view of the area of the leak and adjacent corrosion in the pipe (as-received),
Designated Areas 7 and 10, respectively ................................................................... 33 Figure 27- External corrosion pit in the pipe (as-received condition) designated Area 11. ....... 34 Figure 28- Detail of Area 11 in previous figure. This sample was cross sectioned for metallographic examination ...................................................................................... 35 Figure 29- Detail of Area 13 after cleaning ................................................................................ 36 Figure 30- Detail of previous figure (Area 13). Note steep, undercut edges and relatively smooth bottom........................................................................................................... 37 Figure 31 -Detail of cleaned exterior pit in Area 13 Note pit-within-pit morphology in this area of less severe metal loss ............................................................................................ 38 Figure 32- Detail of cleaned pit (Area 13). Note tunneling and striations trending from upper left toward lower right. .................................................................................................... 39 Figure 33- Inside view of pipe sample looking from straight pipe toward the elbow (as received condition) ................................................................................................................... 40 Figure 34 View into pipe from the end of the elbow................................................................. 41 Figure 35- Inside surface near girth weld, after cleaning by glass bead blasting ....................... 42 Figure 36- Inside surface of the pipe after cleaning showing superficial general corrosion...... 43 Figure 37- Detail ofthe inside surface of the elbow after cleaning............................................ 44 Figure 38 Polished and etched cross section through area of external corrosion on the girth weld ........................................................................................................................... 45 Figure 39 - Detail of previous figure showing areas of corrosion at the outside surface of the pipe ............................................................................................................................ 46 Figure 40 - Detail of previous figure, Area GW-A....................................................................... 4 7 Figure 41 -Detail of cross section through corrosion on the outside surface of the pipe, immediately adjacent to the girth weld (Area GW-B) .............................................. 48 Figure 42- Microstructure of elbow at ID surface with corrosion product intact (at upper left). 49 Figure 43 - Microstructure of elbow at outside surface ................................................................ 50 Figure 44 - Microstructure of pipe at inside surface showing blistered corrosion product over a corrosion pit. .............................................................................................................. 51 Figure 45 - Detail of pipe microstructure at inside surface .......................................................... 52 Figure 46 - Microstructure of pipe at outside surface ................................................................... 53 Figure 47- Cross section through the pipe immediately adjacent to an external corrosion pit showing intact mill scale (between arrows) .............................................................. 54 Figure 48- Detail of corrosion product in a pit on the outside of the pipe .................................... 55 TABLES Table 1 -Background Information .................................................................................................. 6 Table 2 - Other Background Reference Materials Provided by Entergy Staff for Review ............ 9 Table 3 Dimensions of Major Areas of Corrosion ..................................................................... 22 Table 4 Ultrasonic Thickness Measurements (inches) .............................................................. 56 Table 5- Chemical Composition of Pipe and Elbow ................................................................... 57 Table 6 -Mechanical Properties of Pipe and Elbow .................................................................... 57 Table 7 - Results of XRD Analysis of Corrosion Products .......................................................... 58 Table 8- Results ofEDS Analysis of Outside Surface Corrosion Products ................................ 58 Table 9- Typical Results of EDS Analysis oflnside Surface Corrosion Products ..................... 58 tJ Structural Integrity Associates, Inc.
IPEC00202319 IPEC00202319
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 5 ANALYSIS OF 8" CONDENSATE RETURt~ LINE FAILURE Executive Summary The leak in the steel condensate piping was caused by external corrosion. Patterns of corrosion on the piping and observations of the backfill indicate that the corrosion on the pipe occurred at localized areas of coating damage that most likely occurred during installation of the pipe or during installation of the fill. The corrosion on the elbow is more widespread than on the straight section of pipe and is typical of corrosion related to difficulties in applying a good quality wrap coating on a more difficult or irregular shape. It is likely that similar corrosion exists on adjacent piping if exposed to comparable soil conditions. The piping was not cathodically protected.
Corrosion on the inside surfaces was superficial.
No evidence of cracking was observed.
The metallurgical characteristics of the pipe and elbow were normal and the workmanship of the girth weld was good. Where corrosion pitting was present on the weld, the weld metal appeared to be more resistant to corrosion than the adjacent heat affected zone or base metal.
The analysis results did not definitively determine the mechanism of the external corrosion.
Features of the corrosion (morphology and corrosion products) support a determination that the corrosion is either the result of exposure to a specific range of ground water characteristics, and/or to microbiologically influenced corrosion (MIC). The corrosion was not consistent with the characteristics of stray current corrosion, even though stray current was previously identified on other buried pipe at the plant.
XRD (x-ray diffraction analysis) showed that the ID corrosion products were generally iron oxides and hydroxides. The OD corrosion product was primarily siderite, an iron carbonate.
The difference in corrosion products on the ID and OD indicate that the corrosion on the two surfaces is unrelated.
Recommendations related to selection of locations for further inspection, corrosion monitoring, and soil sampling are included.
Introduction Indian Point Generating Station Unit 2 (Indian Point) experienced a leak on 8 inch buried piping identified as Condensate Storage Tank Return Line CD-183. The circumstances regarding the discovery of the leak are described in the narrative by Engineering staff in Appendix A. SI performed a long range guided wave (G-Scan') inspection on February 1ih, 2009. to screen several pre-selected sections of pipe for wallloss 1* The inspection was performed while the 1
Bass, A.," G-Scan' Assessment of8" Condensate Water Storage Tank Return Line CD-183, Inspection Date: February 1ih, 2009",SI report no. 0900235.401.RO, March 13, 2009.
f) Structural Integrity Associates, Inc.
IPEC00202320 IPEC00202320
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 6 plant was in operation and water was flowing through the pipes. After identifying the leak location and adjacent areas of significant wall loss, Indian Point excavated the area and in accordance with their Technical Specifications replaced the leaking section of the piping ..
As described in SI proposal 0900308.00 Rev. 1 ofMarch 20, 2009, the objective of this analysis was to determine the probable failure mechanism and describe the overall condition of the pipe sample. Background information pertaining to the condensate piping is described in the next section. The piping sample was received by SI on March 23, 2009 after removal of the potentially hazardous external coating and related decontamination by Entergy.
Background Information The following information was provided to SI by the staff of Entergy in response to our request for pertinent background information.
1 Applicable design standard(s) for this Construction code is B31.1 1955. Design piping (list applicable industry standard piping specification- 9321-01-248-18 and company standards, particularly if Class C-1. Lacquer coating by spool company standards impose additional fabricator (dwg 17D523) All restrictions related to materials, underground piping to be field coated and construction, testing, or inspection) wrapped in accordance with A WWA spec Copies of company or A-E specs C-203. Specification imposes no additional restrictions.
2 3 Expected life or design life of this piping Design life of pipe is not specified or known. life of is 40 4 Expected life limited by what? (external Pipe life limitation appears to be based corrosion following coating degradation, upon life of external coating. Based upon internal corrosion, fatigue, no longer visual results, Entergy staff noted that the needed, etc.) areas of pipe where coating was intact appears like new and has no external corrosion. Internal corrosion appears mmor.
5 Specified wall thickness Specified wall thickness- 0.322" (nominal wall thickness for 8"SCH40 6 Minimum design thickness Min design thickness- 0.064" per calculation IP-CALC-09-00035 Static head- approximately 45 PSIG at leak location S) Structural Integrity Associates, Inc.
IPEC00202321 IPEC00202321
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 7 11 Original test pressure Original test pressure unknown. Spool fabrication drawing does not specify a test pressure. After installation, one end is open to atmospheric tank. Not known if B31.1 hydrostatic test was performed.
12 Periodic test pressure (if any) and date of Static head- Last test date unknown-last test Pressure drop test once every 3 years. Ref 2PT-3Y7 13 Description of the fluid on ID Clean condensate 14 Operating temperature 90 to l15°F 15 Operating conditions consistent? Continuous flow 16 Original construction inspection Visual inspection of welds (radiography?, visual? UT?, other?)
17 Any other periodic inspection, Pressure drop test once every 3 years. Ref monitoring, or testing 2PT-3Y7 18 Approximate depth ofburial Seven feet at leak location from top of building concrete floor slab 19 Specified backfill (description of what the Per specification 9321-01-8-4. This pipe was supposed to be buried in) specification does not describe requirements for backfill materials below two feet below grade 20 Observed condition of backfill (as See interview reports in Appendix A.
expected per item #19, wet, dry, contaminated by construction debris, rocky, gravelly, sandy, clay, other?)
21 Measured soil resistivity No soil resistivity measurements available for the location of the leak. Soil resistivity measurements for soil around this pipe approximately 100 feet and 200 feet from the leak location are described in Background Reference #7 and range from 8000 ohm-em to 63,000 ohm-em depending upon location and depth.
22 Any other soil analysis results available? I See 21 above and Background References
- 8 and #9.
23 Specified external coating (thickness, External coatings per specification type, manufacturer, inspection or QA A WWA C-203 "Coal-Tar Protective methods used during construction and Coatings And Linings For Steel Water installation) (refer also to item #1) Pipelines Enamel And Tape- Hot Applied" 24 Coating on welds same as coating on The same coating was used on pipe and on pipe? welds.
25 Observed condition of coating upon See interview reports in Appendix A excavation ( mechanically damaged, disbanded, water under coating, obvious degradation, etc.)
lJ Structural Integrity Associates, Inc.
IPEC00202322 IPEC00202322
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 8 26 Electrically continuous with different No other buried alloys as part of this alloys? If so, what alloys and how far condensate piping. The copper grounding away. grid is believed to be electrically continuous with this piping 27 Cathodic protection installed? If so, No cathodic protection installed on this describe system type (impressed current, system. CP is installed on some other galvanic) and history of potentials, CP underground systems as described in maintenance, or operational history Background Reference #7 30 Any potential source of electrical No known electrical interference, interference or history of lightning strikes lightening strikes, etc. on this piping.
or ground faults or source of electrical Background Reference #7 does describe current pick-up and discharge from this interference on another piping system pipe? related to a crossing foreign line that is cathodically protected 29 Free corrosion potential (potential of Potential measurements are listed in unprotected steel in the same backfill vs. Background reference #7. The Cu-CuS04 reference electrode) measurements range from -248 mV to-328 mV (some possible minor effects of active CP elsewhere in the plant, although this pipe was not cathodically protected) 31 History of significant external corrosion No corrosion history on adjacent 12" pipe on adjacent piping, if so, describe pipe, (same fluid & design). The adjacent 12" service conditions, and approx. date of line is coated the same as the failed pipe discovery and carrying the same fluid. A 10" CMP drain line is approximately 12 feet from the failed piping at the leak location. The drain line is coated with the same coating as the failed pipe.
32 Any new pipe installations in this line No new pipe installations or near by 33 Any photographic information from the See Figures 1-3 of this report leak location.
{t Structural Integrity Associates, Inc.
IPEC00202323 IPEC00202323
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 9 T a bl e 2 Oth er Bac k(groun dR~ . Is P rovt'd edb)y E n t ergy Sta fffor R ev1ew e erence M a t ena .
1 UT survey results for the 8" CST pipe, "UT Erosion/Corrosion Examination" report IP2-UT-09-010 2 Relicensing Ground Water Samples. XIs 3 Relicensing Sample Locations.doc (Monitoring Well locations) 4 Attachment 1 IP2 FSAR CP Discussion: This documents the original plant design information concerning underground piping, cathodic protection and soil resistivity.
5 Attachment 2 CST Lines.pdf: This shows the locations of the excavations performed on this line in 2008. This is an elevation view. The leak was at the very bottom left and the 1st excavation is off the page at the top right.
6 Attachment 3 Condition Report : This is a report on the condition of the coating and pipe in the first excavation.
7 Attachment 4 "Corrosion/Cathodic Protection Field Survey and Assessment of Underground Structures at Indian Point Energy Center Unit Nos. 2 and 3 during October 2008" prepared by PCA Engineering, revised December 2 2008?.
8 Attachment 5 GEL Labs 11-07-08 Soil Sample Package for Engineerng.pdf: This is the report of the soil evaluation performed for the two 2008 excavations. They are labeled U2-CST -1 through 4.
9 Attachment 6 02-20-09 Soil Sample Results Package.pdf(2) : This is the soil analysis from the leak location taken 2-20-2009.
10 "Specification for Placing & Compaction of Backfill", Spec. No. 9321-01-8-4, April10, 1967, by United Engineers & Constructors, Inc. for Westinghouse Electric Corporation for Indian Point Generating Station Unit No.2 11 Page 14 of specification for piping materials, Specification No. 9321-01-248-18 Part A, July 29, 1966, Revision 6A, September 1, 1990.
l) Structural Integrity Associates, Inc.
IPEC00202324 IPEC00202324
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 10 Figure 1- View of pipe coating as observed in the excavation by Entergy Staff This photograph was provided to SI by Entergy staff. It was taken before the pipe sample was removed. Note wrinkling ofthe coating typical of soil stress. (Soil stress refers to distortion of external pipe coatings of this type. The distortion is typically caused by relative movement of the pipe and soil resulting from pipe expansion and contraction, soil settlement, or other events.)
Arrows point to examples of angular rocks in the backfill.
SJ Structural Integrity Associates, Inc.
IPEC00202325 IPEC00202325
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 11 Figure 2 - Photograph of pipe in the excavation before removal of the pipe sample.
This photograph was provided to SI by Entergy staff. A leak clamp has been applied to the area of the leak. The white arrow and lines at upper right indicate the limits of coating that was to be removed during the process of replacing the segment of leaking pipe. See next figure for detail of rocks in the backfill to the upper left of the clamp.
lJ Structural Integrity Associates, Inc.
IPEC00202326 IPEC00202326
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 12 Figure 3 - Detail of previous figure showing angular rocks in the backfill.
tJ Structural Integrity Associates, Inc.
IPEC00202327 IPEC00202327
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 13 Analysis and Results The analysis tasks included the following:
- Detailed receipt inspection of the sample
- Detailed visual inspection of the outside diameter (OD) of the pipe for cracks, mechanical damage, thinning, corrosion product, etc.
- Visual examination of the inside surface of the pipe for evidence of features that might have influenced the failure
- Dimensional characterization from the OD
- Detailed corrosion mapping
- Metallography to determine the general microstructure and correlation between failure location and microstructure, proper microstructure, any anomalies
- EDS (energy dispersive spectroscopy) and XRD (x-ray diffraction) of corrosion products
- Bulk steel composition
- Tensile Properties of pipe and elbow The significant findings are summarized below. Details of the results and relevant comments are included in the figures and tables that follow.
Visual Examination: The external coating had been removed and the external surfaces wire brushed and washed by site personnel prior to shipping. As a result, no soil or external coating was present when we received the sample. Some external corrosion product may have been removed by the washing process. The as-received condition of the pipe is illustrated in Figures 4 through 9. Segments removed for further analysis are illustrated in Figure 10. Photographs of manufacturer's markings are illustrated in Figures 11 through 14.
External corrosion on the straight pipe generally consisted of deep isolated pits surrounded by surfaces that were completely uncorroded. The pattern of corrosion was consistent with isolated breaks in the coating. The observed corrosion is mapped in Figure 15. Photographs illustrating representative areas of the corrosion are included in Figures 16 though 32.
The external corrosion on the elbow was more widespread and included relatively large areas of more generalized corrosion. This corrosion pattern was more characteristic of less effective performance of the external coating, perhaps as a result of the difficulty in producing a good wrap pattern when coating irregular shapes such as elbows and other fittings.
In both the elbow and the pipe the morphology of the metal loss included features often associated with MIC including tunneling, striations, overlapping cup-shaped pits, and steep sided pits that sometimes had metal loss that undercut the surface of the pipe. However, similar corrosion patterns can also be produced by abiotic corrosion mechanisms.
The internal corrosion consisted of very shallow scattered pits in the elbow and more widespread, generalized corrosion in the pipe. The appearance of the corrosion is illustrated in Figures 33 through 37. Nothing observed on the inside surface of the pipe would have contributed to this leak.
{J Structural Integrity Associates, Inc.
IPEC00202328 IPEC00202328
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 14 The girth weld appeared to be of good workmanship with no significant visible flaws from anything other than corrosion.
Ultrasonic Thickness Surveys and Corrosion Mapping: Ultrasonic thickness data provided by Entergy were spot checked and then supplemented with additional measurements. The supplemental measurements were located around the circumference of the sample at four locations, including near the end of the pipe, the end of the elbow, and on each side of the girth weld. No unexpected results were obtained and the SI data were similar to measurements made by Entergy staff at the corresponding locations.
Visible areas of external corrosion were measured to record the maximum axial length and circumferential width and maximum depth of each area. On the straight pipe, the measurements were made using a digital pit depth gage with a resolution of 0.0005 inches. On the elbow where the pit depth gage and bridging bar could not be used, the pit profile was replicated using a contour gage and the contour was traced. The depth of the pit as indicated by the trace was measured using a magnifying glass and a machinist's scale with a resolution ofO.Ol inches.
Prior comparisons of this method with a conventional pit depth gage show that the contour gage measurements are typically accurate to about 0.010 inches.
Corrosion Product Analysis: The corrosion product on the external surface was relatively soft and friable and was generally nonmagnetic or very weakly ferromagnetic. The corrosion products did not extend above the surface of the pipe, but pits were either completely or partially filled with corrosion product in most cases. Analysis by XRD showed that the external corrosion products consisted primarily of iron carbonate (siderite). EDS showed the presence of very little chloride and only small amounts of sulfur.
The corrosion product on the inside was very hard, tightly adherent, and strongly attracted to a magnet. The corrosion products resulted in distinct raised bumps above each small pit. Analysis by XRD showed that the corrosion product was composed of various iron oxides, including about 70% magnetite, which was likely responsible for the hard, adherent, ferromagnetic properties. Only small amounts of chlorine and sulfur were present.
Analysis of the Steel: The tensile properties of the pipe and elbow were normal. The chemical composition of the elbow met the specification. The chemical composition of the pipe deviated from the ASTM AI 06 requirement that the steel contain at least 0.1% silicon. Two samples of the steel pipe both were found to contain 0.02% silicon, which meets the requirements of both API 5L grade B pipe and ASTM A53 grade B seamless pipe. It is unlikely that the deviation influenced the external corrosion. However, we have seen other cases in which the silicon killed steels appeared to be slightly more resistant to some forms of internal corrosion. The small difference in composition may explain the differences in the patterns of internal corrosion observed between the elbow and the pipe (i.e., general corrosion vs. pitting).
Microstructural Analysis: The metallographic cross sections of the pipe, elbow, and girth weld showed no metallurgical anomalies. All microstructures were as expected. The pipe and the elbow both consisted of fine pearlite and proeutectoid ferrite phases, as is typical for hot worked
~ Structural Integrity Associates, Inc.
IPEC00202329 IPEC00202329
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 15 mild steel. The cross sections showed that the mill scale (magnetite) on the outside surface of the pipe was intact except in areas of corrosion pits, indicating that the surface was not prepared by abrasive blasting prior to coating. The microstructures are illustrated in Figures 40-48. See the figures for explanation of the illustrated features.
Determination of Corrosion Mechanism: The determination of the likely mechanism for the external corrosion was based mainly upon the characteristics of the corrosion product and the morphology of the corrosion. As noted above, the external corrosion product is virtually all iron carbonate. Iron carbonate is most commonly associated with corrosion resulting from exposure of steel to wet C0 2
- However, several sources discuss the formation of iron carbonate in fresh and salt waters where C0 2 corrosion is unlikell 3 4 5 . The references cite the finding of siderite among fresh water and salt water corrosion products but do not describe the morphology of the metal loss associated with the siderite or the corrosion rates related to its formation. Reference 2 relates the formation of siderite to near neutral pH conditions (i.e., about pH 7.2 to 9.4) in which some alkalinity is present, and oxygen is either absent or in which the oxidation of ferrous iron Fe(II) to Fe(III) is kinetically inhibited. Examples of oxidation inhibitors that would favor the formation of siderite include natural organic matter and calcium. The same reference, though, describes siderite as a relatively protective corrosion product, relative to the protectiveness of other corrosion products.
Siderite has also been shown to be related to microbiological processes 6 7 8 , although it is less commonly cited than some other corrosion products as a MIC-related corrosion product in the corrosion literature.
2 Wilson, B.M., Johnson, D.L., et.al., "Corrosion Studies on the USS Arizona with Application to a Japanese Midget Submarine" TMS website at http://www.tms.org/pubs/journals/jom/071 0/wilson-071 O.html 3
A WWA Research Foundation "Internal Corrosion of Water Distribution Systems", ISBN 0898677599, published bv American Water Works Association, 1996 4
McNeill, L.S., Edwards, M. "Review oflron Pipe Corrosion in Drinking Water Distribution Systems" 5
Cook, D.C., Peterson, C. "Corrosion of Submerged Artifacts and the Conservation of the USS Monitor, AlP Conference Proceedings, Journal Vol 765, Issue I ,International Symposium on the Industrial Applications of the Mossbauer Effect, Madrid, Spain, May 2006 6
Zhang, C.L., Horita, J, et. al., 'Temperature-Dependant Oxygen and Carbon Isotope Fractionations of Biogenic Siderite" downloaded from http://www .sciencedirect.com Weber, K. A., Picardal, F.W., Roden, E.E. "Microbially Catalyzed Nitrate Dependant Oxidation of Biogenic Solid-Phase Fe(II) Compounds" Environmental Science & Technology, 2001, vol. 35,No. 8, pp 1644-1650.
8 Mattiesen, H., Hilbert, L.R., Gregory, D.J., "Siderite as a Corrosion Porduct on Archaeological Iron From a Waterlogged Environment" Studies in Conservation, vol48., 2003, pp 183-194
{J Structural Integrity Associates, Inc.
IPEC00202330 IPEC00202330
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 16 Figure 4 - Shipping container for pipe sample, as-received on March 23, 2009 Figure 5 Pipe sample as-received in the shipping container.
lJ Structural Integrity Associates, Inc.
IPEC00202331 IPEC00202331
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 17 Figure 8 - Pipe sample, as-received, view 3
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IPEC00202332 IPEC00202332
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 18 Figure 9 - Pipe sample, as-received , view 4. Arrow points to location of leak Figure 10 - Pipe sample marked with red boxes to show locations of samples removed for further analysis
- 1. Elbow sample with ID corrosion for metallographic examination,
- 2. Girth weld sample for metallographic examination,
- 3. External corrosion pit with internal corrosion on pipe for metallographic examination and EDS analysis of the corrosion product
- 4. Second sample of pipe for metallographic examination (investigation of possible ERW seam).
Segments at arrows at ends of the sample were previously removed for tensile testing and analysis of steel composition.
{J Structural Integrity Associates, Inc.
IPEC00202333 IPEC00202333
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 19 Figure 11- "YS" stamp mark on pipe.
The stamp marks indicate that this pipe is pipe manufactured by Youngstown Steel. At this location the stamps have been partially polished away by erosion from the nearby leak (in this pipe).
Figure 12 - API monogram stamp mark on pipe.
Monogram indicates that pipe met requirements of API specification 5L. It may have also been manufactured to meet ASTM specifications. Grids outlined by white lines are approximately 1" X 1".
{J Structural Integrity Associates, Inc.
IPEC00202276 IPEC00202276
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 20 Figure 13 - Manufacturer's stamp marks on the neutral axis of the elbow.
See next figure for detail of the stamp mark after cleaning.
Figure 14- Manufacturer's stamp mark after light abrasion with sandpaper.
The stamp marks on the neutral axis of the elbow identify it as an 8" schedule 40 fitting manufactured by Dresser. The grade of the fitting is obscured by corrosion.
{:t Structural Integrity Associates, Inc.
IPEC00202277 IPEC00202277
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 21 Figure 15- Map of external corrosion Major areas of corrosion are sketched and numbered. The axial grid lines (marked A, B, C, etc.)
are as marked by Entergy. The leak is at location See Table 3 for additional details l) Structural Integrity Associates, Inc.
IPEC00202278 IPEC00202278
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 22 Notes:
- 1) The %CSA represents the portion of the pipe wall area (as measured in a circumferential cross section through the pipe) that is affected by the metal loss. It relatt;s to the detectability of the corrosion using guided wave UT inspection methods. Larger %CSA values typically represent flaws that are more easily detectable. The %CSA (cross sectional area) of each significant flaw is approximated by the following equation:
% CSA 100 x (2/3 x flaw depth x flaw width)/(pi x outside radius 2 - pi x inside radius 2)
For the purpose of detectablility by use of guided wave UT inspection ,the %CSA separate flaw areas located in the same circumferential plane may be combined to estimate the total %CSA, as shown below:
Flaw Areas in a shared Total% CSA circumferential plane 0, 1 32.5 2,4 34.9 2, 3 5.2 5, 6 6.7 7, 8, 10 9.1 9, 11 >0.4 (see note 4)
- 2) The majority of the corrosion was shallow, therefore the equation used to estimate %CSA is overestimating the area of metal loss
- 3) This area is continuous with Area 1
- 4) This pit was metallographically cross sectioned with corrosion product intact. Pit depth could not be measured and cross section may not have revealed deepest point
{J Structural Integrity Associates, Inc.
IPEC00202279
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 23 Figure 16- External corrosion on elbow (as-received condition) designated Area 0 Note the absence of any corrosion surrounding the "L" shaped pit.
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IPEC00202280 IPEC00202280
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 24 Figure 17 - External corrosion on the extrados of the elbow, as-received; designated Area 1
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IPEC00202281 IPEC00202281
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 25 Figure 18-- Extrados of ell after cleaning, Area 1.
Note extensive general corrosion compared to the straight pipe. A circumferential band was masked off to prevent loss of the grid line identifications lJ Structural Integrity Associates, Inc.
IPEC00202282 IPEC00202282
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 26 Figure 19- Detail of corrosion in Area 4, Location 1 Note sharp edges of pits and tunnellike features (arrow points to one example of tunneling).
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IPEC00202283 IPEC00202283
Mr. Robert Altadonna May 15,2009 Report 090023 5.402 RO Page 27 Figure 20 - Area of Area 4, Location 2 after cleaning by glass bead blasting Note scrape marks. These scrape marks appeared to have discoloration and oxidation comparable to the surrounding uncorroded pipe surface suggesting they may have been formed either during the installation process, or prior to the pipe coating process. If they were formed after coating, the coating would have been damaged and exposed the scraped area to the soil. As a result, the scrape would have been eliminated by subsequent corrosion. The striations are elongated features oriented from lower left to upper right in the round pit at upper left.
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IPEC00202284 IPEC00202284
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 28 Figure 21- Detail of corrosion on girth weld in the location designated Area 5.
Note corrosion undercutting the toe of the weld and striations in adjacent corrosion on the elbow.
The striations are short linear features oriented about 25 degrees off the longitudinal axis of the pipe and are most visible to the right of the weld e Structural Integrity Associates, Inc.
IPEC00202285 IPEC00202285
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 29 Figure 22 - Second view showing detail of the corrosion undercutting the toe of the weld SJ Structural Integrity Associates, Inc.
IPEC00202286 IPEC00202286
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 30 Figure 23- External corrosion on the pipe (as-received condition), designated Area 6. Note absence of corrosion around this pit.
{r Structural Integrity Associates, Inc.
IPEC00202287 IPEC00202287
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 31 Figure 24- Outside surface of pipe (as received) showing leak and two other areas of corrosion in addition to identifying "YS" and "API" stamp marks. Areas designated 7, 8, and 9 A very subtle feature that appeared to be an ERW seam runs horizontally through the "YS" stamp mark. Youngstown Steel manufactured both seamless pipe and ERW pipe in this size range. Only the seamless pipe could have met the requirements of ASTM Al06. Subsequent metallographic examination of the location showed no microstructural evidence of a seam and the seam-like feature may be the remnants of the embossing wheel that produced the "YS" stamp during the manufacturing process of seamless pipe. The area surrounding the leak (Area 7) was eroded and polished as a result of turbulent water in the area of the leak. In comparison, areas of metal loss a few inches or more from the leak (i.e., see areas 8 and 9) have irregular topographies typical of corrosion that has not been modified by erosion.
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IPEC00202288 IPEC00202288
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 53 Figure 46 - Microstructure of pipe at outside surface.
There is no external corrosion at this location. The outside surface is at the top of the figure.
tJ Structural Associates, Inc.
IPEC00202237 IPEC00202237
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 54 Figure 47- Cross section through the pipe immediately adjacent to an external corrosion pit showing intact mill scale (between arrows)
The presence of intact mill scale indicates that there was no corrosion on this surface and that there was no surface preparation prior to external coating. A small amount of decarburization of the surface is present, as expected for this type of steel product.
{J Structural Integrity Associates, Inc.
IPEC00202238 IPEC00202238
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 55 Figure 48- Detail of corrosion product in a pit on the outside of the pipe The corrosion has preferentially corroded the proeutectoid ferrite and the ferrite lamellae of the pearlite leaving the iron carbide constituent of the pearlite grains uncorroded. The resulting shiny irregular globular-shaped areas replicate in the corrosion product the size and shape of the original pearlite grains. This appearance is typical of iron carbonate corrosion products.
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IPEC00202239
Mr. Robert Altadonna May 15, 2009 Report 0900235.402 RO Page 56 Table 4- Ultrasonic Thickness Measurements (inches)
'-'~-""a
. ...... nominal wall thickness 0.322 inch llo:eatioB (~-iacli -1 iacll':rotR -1 iucllrom ""I mcllrom -1 iacllrold l':ircumrereatial Eud of :Pile Girtl Weld, on Girtl Weldt on End of Elf>o:w:
lm.1re*entS'l :Pipe Side Elf>ow Side" 1 0.301 0.290 0.359 0.385 2 0.328 0.290 0.353 0.340 3 0.327 0.311 0.341 0.346 4 0.330 0.316 0.328 0.335 5 0.337 0.324 0.331 6 0.315 0.334 0.320 0.314 7 0.308 0.345 0.322 0.323 8 0.311 0.343 0.327 0.329 9 0.294 0.326 0.335 10 0.290 0.327 0.330 11 0.319 0.341 12 0.304 0.357 Note 1: Measurements by SI at grid locations were made approximately at the intersection of the grid lines. Small differences in measurements between SI and Entergy data may reflect small variations in the location of the transducers during measurements.
Sj Structural Integrity Associates, Inc.
IPEC00202240
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 57 Note: Specifications limits are per ASTM Volume 01.01, 1991 and may not be the same as the requirements that were in effect at the time of construction.
65.8 66.9 60.0 min 62.1 60.0-85.0
% Reduction of 52.6 NA 54.6 NA Area
{1 Structural Integrity Associates, Inc.
IPEC00202241 IPEC00202241
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 58 Inside ~70wt% ~5wt% -15 wt% ~5wt% -5wt% ~5wt%
corrosion Outside Major Minor corrosion
- most likely combined with maghemite y-Fez03 (=decomposed magnetite) tJ Structural Integrity Associates, Inc.
IPEC00202242
Mr. Robert Altadonna May 15,2009 Report 090023 5.402 RO Page 59 Summary The leak in the 8" steel condensate piping was caused by external corrosion. Corrosion on the exterior of the pipe consisted of a large number of localized pits, rather than of widespread general corrosion. The surfaces around the pits on the straight pipe had no evidence at all of corrosion and the original mill scale (high temperature iron oxide) was intact, indicating that where the coating remains intact the pipe surfaces are adequately protected against corrosion.
The external surfaces of the elbow had more widespread corrosion, although a few portions (less than half of the surface) still showed no evidence of external corrosion. The patterns of corrosion on the pipe are consistent with localized mechanical damage to the coating. The corrosion on the elbow was consistent with an imperfect coating resulting from the difficulties inherent in coating an irregular surface such as the elbow.
During and after the excavation process, Entergy staff observed that the backfill in the area of the pipe included debris and angular rocks. Those materials could have damaged the coating in multiple locations during the pipe installation or backfilling process, resulting in vulnerability of the small areas of exposed steel to corrosion. Since a relatively large surface area of the sample has no evidence of corrosion, exposure to leaking water or to water-saturated soil apparently did not have a significant effect on the protectiveness of the coating on the pipe. Rather, the large number of observed pits is more likely related to the occurrence of coating damage that occurred during installation; not to gradual or long term coating degradation that could potentially as a result of exposure to leaking water or water-saturated soil.
While the morphology of the external pitting included features that are typical of corrosion associated with MIC, the features are not unique to MIC. Likewise, the corrosion products in the external corrosion pits consisted primarily of siderite (iron carbonate), which can result from either MIC or from corrosion unrelated to microbiological activity (i.e., from abiotic corrosion).
The siderite corrosion product can be formed either by MIC, or can be generated as a result of electrochemical corrosion of steel exposed to well buffered water containing little or no oxygen, a neutral to moderately high pH, and low calcium. The reported pH of the ground water matches this requirement. The available water analysis and soil analysis does not contain the information required to determine if the other attributes are within the range for siderite to be formed abiotically.
We determined that the corrosion rate responsible for causing the leak must have been at least 8 mpy (0.008 inches per year or 8 mils per year) to cause penetration of the pipe wall in about 40 years. Many soils could cause a long term corrosion rate of about 8 mpy or higher in the absence ofMIC, so the high corrosion rates often associated with MIC are not necessary to cause the leakage. It is likely that the corrosion progressed discontinuously as water table levels rose and fell, or as the soil environment underwent other seasonal or temporary changes. As a result, the peak corrosion rate could have been significantly higher than 8 mpy and within the range associated with MIC. However, it is apparent that ifMIC did contribute to the metal loss, it was not active the entire time the pipe was in service because the leak would have occurred much sooner.
Determining the probable rate of future metal loss at other locations of coating damage on this piping would require either directly measuring the rate with corrosion probes or buried coupons, or modeling the likely abiotic corrosion rates using soil analysis data. Insufficient soil data SJ Structural Integrity Associates, Inc.
IPEC00202243
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 60 currently exists to estimate the corrosion rate that could be caused by the backfill in the absence ofMIC.
Some preferential corrosion of the girth weld heat affected zone was apparent on both the ID and OD of the pipe, but the maximum depth of metal loss in the HAZ was no greater than the maximum depth of metal loss remote from the weld.
Corrosion on the inside surface of the sample was superficial and does not represent a significant threat to the integrity of the pipe. ID corrosion on the straight pipe was more widespread than in the elbow, resulting in an appearance more typical of general corrosion, rather than of pitting.
ID pitting on the elbow consisted of individual small pits. The composition of the corrosion products from the inside of the sample was characteristic of corrosion by low oxygen content water and was significantly different from corrosion products on the OD of the pipe.
The metallurgical characteristics of the pipe, elbow, and girth welds were normal. The workmanship of the weld was good. No abnormalities in the steel or weld were present that could have contributed significantly to the corrosion, although the pipe composition deviated from the ASTM A106 specification with regard to silicon content. The composition did meet the requirements for comparable seamless pipe specifications.
Conclusions
- 1. Internal corrosion is present, but it is superficial and does not represent a threat to the operation of the piping. Minor differences in the extent of corrosion observed on the pipe and on the elbow are attributed to minor differences in the steel composition. The weld HAZ of the elbow appeared be to somewhat less resistant to corrosion than the areas of ethe elbow away from the weld, but no less resistant than the pipe.
- 2. We found no evidence of abnormalities in the metallurgical characteristics of the pipe, elbow, or the girth weld that would have contributed to the observed corrosion. The workmanship of the girth weld was very good. A minor variance in the chemical composition of the pipe from the applicable specification is inconsequential to its performance.
- 3. The coating quality could not be determined directly from the pipe samples submitted for analysis since the coating had been previously removed during the pipe repair process.
However, the observed patterns of corrosion indicate that the coating continues to be protective where it is intact, but the existing coating quality may be somewhat lower on surfaces that are more difficult to wrap, such as fittings, as evidenced by larger areas of general corrosion on the surface of the elbow. The primary cause of localized pitting corrosion in areas surrounded by coating that appears to be generally intact is probably localized mechanical damage to the coating. The mechanical damage causes localized penetrations of the coating resulting in exposure of small areas of the steel surface to the soil environment. The coating damage most likely occurred during installation as a result of using backfill that contained angular rocks and debris. The calculated minimum average long term corrosion rate (about 8 mpy) that would have produced the recent leak is within the range of corrosion rates observed for pipe that is not cathodically protected when exposed to some soils, but lower than expected forMIC if the MIC mechanism was continuously active. Some soil analysis data was provided to SI, but not all of the
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IPEC00202244
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 61 attributes required for input into our SoilPro model were included in the available data.
As a result, we are unable to determine if the soil characteristics at this leak site would be expected to cause an 8 mpy corrosion rate in the absence of MIC. The potential influence ofMIC should not be disregarded since both the morphology of the metal loss and the type of external corrosion product present can be related to MIC, (although neither one is a definitive indicator ofMIC). Two scenarios could describe the cause of the relatively low average corrosion rate in the presence of a MIC mechanism. First, it is possible that corrosion rates fluctuated during the time of service as water table depths rose and fell, resulting in periodic variations in soil properties. Those variations in soil properties could alternatively support or fail to support a MIC mechanism. In a second scenario, the initial corrosion rate could have been low and unrelated to MIC. After some time in service some environmental change occurred, such as a long term change in the water table, or a leak in adjacent piping. That transition could have triggered the onset of long term MIC (or of higher abiotic corrosion rates). Either case describes how the significantly higher corrosion rates often associated with MIC could have occurred only during a portion of the total service time.
Recommendations
- 1. Generalizations regarding what constitutes "corrosive soil" can be misleading, particularly when based on assessment of one or only a few soil parameters. Consider installing corrosion probes or corrosion coupons in the backfill with the means to monitor or retrieve the assemblies. Coupons or probes can help quantifY corrosion rates, detect transients in corrosion rates, and assist in the determination of the mechanism of corrosion. Alternatively, if available, an additional soil sample could be analyzed to determine the attributes needed to run the SI SoilPro program and estimate the likely pitting rate that would be expected at the location of the sample. However, the SoilPro data will represent the snapshot in time at which the sample was obtained and will not address seasonal changes or transient conditions in the environment unless additional samples are taken at a later time
- 2. Consider focusing any future piping inspection on areas containing:
- a. Elbows and other harder to wrap fittings since those are preferential locations for coating anomalies.
- b. Backfill suspected of having the same characteristics at those observed at this leak since angular rocks may have caused coating damage at which corrosion can occur
- c. Areas where results of soil analyses indicate that corrosion rates may be the highest. In the absence of data that is sufficient to run the SI SoilPro corrosion rate model , select areas of lowest elevation and low resistivity since low resistivity is often associated with more corrosive soiL Note however that high resistivity soil may still be corrosive.
tJ Structural Integrity Associates, Inc.
IPEC00202245 IPEC00202245
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 62 d.
Appendix A- Observations by Entergv Engineering Staff Regarding the Excavation Conditions Observation 1
- The initiating event was a report by Operations that the water level was rising in the sleeve of the 8" Condensate Return line in the Aux Feed Pump Room where the pipe goes into the floor
- On his own initiative, an Operator looked in the manhole just outside the Aux Feed Pump Room in the Main Feed Reg Valve Room and noticed water flowing in the manhole.
- The Condensate Storage Tank was declared inoperable
- Once the core boring was complete there appeared to be undermining of the area under the concrete slab.
- A lot of water was still coming into the hole during excavation
- During excavation and shoring, there were a lot of large rocks, cans, and other garbage in the fill that was used. The rocks were large enough to get stuck in the hose that was sucking out the mud from the hole Upon inspection of the pipe (the pipe was still leaking) there appeared to be a hole at the 7:00 position approximately 22" from the elbow weld joint.
- The coating was not present in the areas of the hole and/or indications. It appears to have been blown away over time. This could have been caused by initial damage to the coating during the backfill
- The area of the holes/indications probably saw constant groundwater and could have caused the erosion in the areas of the damaged coating. Note that the inside of the pipe was in pristine condition; no internal corrosion noted.
Observation 2
- Observed the area being excavated with sump pump installed, but no shoring yet. The hole was still ~ 12 full of water.
- Inspected pipe after clamp was installed. No areas coating had been stripped for UTs yet however, the coating appeared to be in bad shape and chewed up. Not sure if this was a result of the excavation, from original construction, or degradation over time.
- Additional observations of the coating indicated that it was not in uniform contact with the pipe and not tightly adhered to. Some scaling had occurred at some point as well.
- Did not witness the excavation activities however, did notice a lot of debris, especially stones in the area under the pipe. These were fist size or greater and seemed to be crushed rock not normally seen in areas of backfill.
- An indication was noted to have the appearance of a rock (or other object) that had been forced into the pipe and caused damage to the coating.
- Some of the pitting was very shiny which is unusual. It also appeared to be uniform in depth.
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IPEC00202246 IPEC00202246
Mr. Robert Altadonna May 15,2009 Report 0900235.402 RO Page 63 Observation 3
- Did not observe excavation efforts, but did see ~ 6" in the area around the pipe once it was exposed.
- The coating was already stripped and prepped for UTs.
- Based on a review of the photos it appears that the coating may not have been applied consistently during original construction. The workmanship was not up to current standards. The coating has a "rippled" look to it.
- Pipe thickness looked good Observation 4
- Once the core boring was complete, observed a lot of debris in the hole during excavation.
- Items included large rocks, metal pieces, and Styrofoam packaging material.
- The rocks were large enough to clog the hose that was used to suck out the mud during excavation
- The hose was getting clogged frequently due to the large rocks and debris to the point where the hose needed to be disconnected at the truck end in order to clear it out.
- The sump pumps also appeared to be clogging frequently.
- The pressure from the rocks could have been enough to damage the coating and the surface of the pipe.
lJ Structural Integrity Associates, Inc.
IPEC00202247 IPEC00202247