ML113530076
| ML113530076 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 02/15/2009 |
| From: | Entergy Corp |
| To: | Atomic Safety and Licensing Board Panel |
| SECY RAS | |
| Shared Package | |
| ML113530062 | List: |
| References | |
| RAS 21566, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 CR-IP2-2009-00666 | |
| Download: ML113530076 (89) | |
Text
{{#Wiki_filter:NYS000170 Submitted: December 16, 2011 Entergy CONDITION REPORT ICR-IP2-2009-00666 Originator: Rohla III, Otto R Originator Phone: 5295 Originator Group: Operations Watch StaffiP2 Operability Required: Y Reportability Required: N Supervisor Name: Gates,Clifton Discovered Date: 02/15/2009 15:29 Initiated Date: 02/15/2009 15:35 Condition
Description:
Water filling floor guard collar on CST return line and spilling onto floor on 18' AFB. Chemist has been contacted for sampling. Chemist reports 54ppB ofHydrazine in water. Immediate Action
Description:
Secured recirculation of CST -Hotwell. Chemist dispatched for sampling Suggested Action
Description:
Determine source of leakage EQUIPMENT: Tag Name Tag Suffix Name Component Code Process System Code CST HCLM/SRIMR ACCUMU AFW REFERENCE ITEMS: Type Code Description CR IP2-2009-02874 CR IP3-2009-00556 CR IP3-2009-02788 CR IP3-2009-02150 LOCR LO-IP3L0-2009-00118 (Effectiveness Review) LTCR Approved by CARBon 5/14/09 w-Eng Director Present TEAM2C WON 00183296 WRN 00171129 WRN 00171130 WRN 00171137 WRN WR#00156027 WRN 00171140 WRN 00171141 WR~ 00171143 TRENDING (For Reference Purposes Only): Trend Tvpe Trend Code REPORT WEIGHT 1 HEPFACTOR E INPO BINNING ER3 EL ESPC KEYWORDS KW-LEAKS-WATER KEYWORDS KW-CONDENSATE STORAGE TANK KEYWORDS KW-PIPE BREAK KEYWORDS KW-ENVIRONMENTAL DISCHARGE IPEC00202297 IPEC00202297
Entergy CONDITION REPORT ICR-IP2-2009-00666 Trend Type Trend Code UPGRADED CR CATEGORY CAT B to CAT A RCA 20.4 CAUSAL FACTOR OP4A CAUSAL FACTOR OP2J CAUSAL FACTOR OP5E LT -MOD/DESIGN CA#14 Per NSA Director CARB chairperson
# PERIODIC REVIEW INITIAL IPEC00202298 IPEC00202298
Entergy ADMIN I CR-IP2-2009-00666 Initiated Date: 2115/2009 15:35 Owner Group :P&C Eng Codes Mgmt IP2 Current
Contact:
Current Significance: A Closed by: Summary
Description:
Water filling floor guard collar on CST return line and spilling onto floor on 18' AFB. Chemist has been contacted for sampling. Chemist reports 54ppB ofHydrazine in water. Remarks
Description:
CR #4 to perform a Root Cause evaluation was initially performed by the owner department on 3/19/09 ( <30 days). The Site VP has requested the RCA be extended until failure analysis and evaluation of the failed section of pipe is complete. CA re-opened to owner department to extend. ML T 3/20/09. Closure
Description:
IPEC00202299 IPEC00202299
Entergy OPERABILITY ICR-IP2-2009-00666 Operability Version: Operability Code: EQUIPMENT INOPERABLE Immediate Report Code: NOT REPORT ABLE Performed By: Spagnuolo,Frank M 02/16/2009 01:05 Approved By: Dewey Jr,Donald J 02/16/2009 01:34 Operability
Description:
CST is inoperable due to external pipe leakage and the potential of draining the CST upon a pipe break. Approval Comments: Agree and Approve IPEC00202300 IPEC00202300
Entergy OPERABILITY I CR-IP2-2009-00666 OperabilityVersion: 2 Operability Code: EQUIPMENT INOPERABLE Immediate Report Code: NOT REPORT ABLE Performed By: Huron,Robert W 02/20/2009 17:34 Approved By: Baker,John R 02/20/2009 18:05 Operability
Description:
CST was declared inoperable on Monday, Feb 16, 2009 Approval Comments: Approved IPEC00202301 IPEC00202301
Entergy OPERABILITY ICR-IP2-2009-00666 OperabilityVersion: 3 Operability Code: EQ1J1PMENT OPERABLE Immediate Report Code: NOT REPORTABLE Performed By: Spagnuolo,Frank M 02/24/2009 20:12 Approved By: Dewey Jr,Donald J 02/24/2009 20:42 Operability
Description:
The CST was returned to OPERABLE on 2/21/09 at 0656 after replacement of the defective length of pipe. All Post Work testing has been completed satisfactorily. Approval Comments: Agree and Approve. IPEC00202302 IPEC00202302
Entergy ASSIGNMENTS CR-IP2-2009-00666 Version: 2 Significance Code: A Classification Code: RCA Owner Group: P&C Eng Codes Mgmt IP2 Performed By: Harrison,Christine B 02/20/2009 12:11 Assignment
Description:
2/20/09: At the direction of senior management, Category of this CR upgraded from a "B" to an "A". CA-00002 has been closed to new CA-00004 which reflects this new assignment. CARB Review CA has been edited to reflect this new assignment. IPEC00202303 IPEC00202303
Entergy I ASSIGNMENTS ICR-IP2-2009-00666 Version: Significance Code: 8 Classification Code: HT -ACE CARS Owner Group: P&C Eng Codes Mgmt IP2 Performed By: Harrison,Christine 8 02119/2009 10:53 Assignment
Description:
IPEC00202304 IPEC00202304
Entergy REPORT ABILITY ICR-IP2-2009-00666 Reportability Version: 2 Report Number: Report Code: NOT REPORTABLE Boilerplate Code: Performed By: Rokes,Charles B 03/17/2009 I I :28 Reportability
Description:
The recorded condition does not meet reporting criteria ofSMM-LI-108 based on engineering response to CA-8 concluding the as-found condition and past condition did not result in inoperability of the AFWS. The condition of the leak in the Condensate Return Line did not affect past operability ofTS components, specifically the AFW System (TS 3.7.5) and the Condensate Storage Tank (TS 3.7.6) as demonstrated by the attached safety significance review. The AFW System was not affected as the Return Line was determined by calculation to remain operable. By conservative estimates the leak would have required an additional21,600 gals above the 360,000 gal required for the 24hr decay heat removal ofTS 3.7.6. This means that an additional 1.13 ft in CST level or a minimum of I 7 ft indicated would have to be maintained to account for the additional loss from this past leakage. Except for outages, the plot of past CST level shows level was maintained far above that required by TS 3.7.6. IPEC00202305 IPEC00202305
Entergy I REPORT ABILITY ICR-IP2-2009-00666 Reportability Version: Report Number: Report Code: INDETERMINATE - EVAL Boilerplate Code: Performed By : Rokes,Charles B 03/03/2009 08:27 Reportability
Description:
The impact of the condition on CST or AFW operability is not known therefore CA-8 was issued for SE to determine if the condition during past operation could have resulted in a TS violation or a safety system functional failure. A TS Prohibited condition would be a 60-day LER under 10CFR50.73(a)(2)(i)(B), and a SSFF would be a 60-day LER under 10CFR50. 73(a)(2)(v). IPEC00202306 IPEC00202306
~~-~-n_t_e_~_Y~~~~~~-~~~-~~E-~_T~I~_E~~-~-T_I_~_~~~~~~P2-2009-00666 CANumber:
Group I Name i Assigned By: Operations Watch StafflP2 Dewey Jr,Donald J Assigned To: Engineering Director IP2 Burroni,Richard J Subassigned To : Originated By: Dewey Jr,Donald J 2116/2009 01:51:36 Performed By: McCaffrey, Thomas S 2/20/2009 10:49:09 Subperformed By: Approved By: Closed By: Baker,John R 2/20/2009 13:28:38 Current Due Date: 02/20/2009 Initial Due Date: 02/20/2009 CA Type: OPERABILITY INPUT Plant Constraint: #NONE CA
Description:
Develop an operability evaluation for the operability of the CST supply to the AFW pumps and the CST return line because of the suspected leakage below ground from either of these lines.
Response
Based on investigateion of the pipe crack, it was recommeneded that the line be repaired. Based on this repair, no operability evaluation has been performed for the as found condition. Subresponse : Closure Comments: Response accepted. Return line repairs in progress. IPEC00202307 IPEC00202307
Entergy I CORRECTIVE ACTION ICR-IP2-2009-00666 CANumber: 2 Group I Name I Assigned By: CRG-CARB-SARB IP2 Harrison,Christine B Assigned To: P&C Eng Codes Mgmt IP2 Azevedo,Nelson F Subassigned To: Originated By: Harrison,Christine B 2119/2009 10: 17: 18 Performed By: Subperformed By: Approved By: Closed By: Harrison,Christine B 2/20/2009 12:07:45 Current Due Date: 03/1112009 Initial Due Date: 03/12/2009 CA Type: DISP - ACE/HT Plant Constraint: #NONE CA
Description:
Please perform higher-tier apparent cause evaluation and assign further corrective actions as required. Note that your evaluation is to be presented to CARB and a corrective action is being assigned to CA&A to document this presentation.
Response
Subresponse : Closure Comments: 2/20/09: At the direction of senior management, Category of this CR upgraded from a "B" to an "A". This CA is being closed to new CA-00004 which reflects this new assignment. IPEC00202308 IPEC00202308
Entergy I CORRECTIVE ACTION I CR-IP2-2009-00666 CA Number: 3 Group Name Assigned By: CAA Staff IP2 Harrison,Christine B Assigned To: CAA Staff IP2 Harrison,Christine B Subassigned To: Originated By: Harrison,Christine B 2/19/2009 10:18:06 Performed By: Tumicki,Michael L 5/15/2009 11:51:27 Subperformed By: Approved By: Closed By: Tumicki,Michael L 511512009 11:51:27 Current Due Date: 05/29/2009 Initial Due Date: 05/29/2009 CA Type: CARB REVIEW Plant Constraint: #NONE CA
Description:
Document the results of the root cause analysis presentation to CARB. IPEC00202309 IPEC00202309
Entergy I CORRECTIVE ACTION ICR-IP2-2009-00666
Response
5/14/09: The Root Cause Analysis was presented to, and accepted with edit by, the CARB with the NSA Director serving as chairman. The report received an average grade of20.4. The CARB provided the following insight to be included in the report: P 9 - remove words about estimated 10-12 gpm leak P 10- remove section about DC-343 P 16- remove last sentence referencing att 9.4 P 19 Delete the first paragraph under the title "Conditions That Lead To The Corrision and Leak" and remove the section titles P 20 - add words about failure analysis performed by vendor and remove the section titles P 22 add backfill spec # in root cause paragraph P 23 delete CC2 P 25 section D - clarifY "resources" is referring to specification for backfill and add construction worker practices/supervisory oversight during original construction to discussion P 26 - second paragraph delete word "preliminary"
- Delete last two sentences on page P 27 - extent of cause- last sentence delete words "when developed" P 31 - #2 change words so it is clear that 650,000 gallons is the lowest CST can drain to i#4 and delete reference to CST trends
- Add bullet # 7 that city water backup is available if CST is unavailable P 34 - delete CC2, CC3 from first line of causes
- Delete everything from second line of causes except CC2
- cc 1 change words to "need/feasibility" and replace words "any or all" with "selected" JChange CC3 to CC2 and delete words "and accessability"
- iChange CC3 to CC2 and change due date from from 9115 to 11115
!EOC- change words "once add'l inspection and analysis complete, assign actions needed and present to CARB i Other - change teak to tank P 35- change all CC3's to EOC i Delete entire EOC corrective action line -second from bottom of page P 36 - under CAPR's delete all # 2 CAPR's from page P 39 - label all attachments 1
Add #3 - vendor pipe failure analysis P 40 why staircase - add another box between bottom two boxes to say - use of blast rock from unit 3 was allowed as backfill 3120109: Per special CARB meeting and based on request by Site Vice President, approval was given by CARB to extend the due date tor the completion of this root cause analysis to May 21, 2009. Subresponse : Closure Comments: IPEC0020231 0 IPEC0020231 0
Entergy I CA DUE DATE EXTENSION ICR-IP2-2009-00666 Corrective Action : CR-IP2-2009-00666 CA-00003 Version: Approved: [~J Requested Duedate: 05/29/2009 Previous Duedate: 03/2112009 Requested By: Tumicki,Michael L 03/20/2009 Approved By: Tumicki,Michael L 03/20/2009 Request
Description:
The due date to perform the RCA evaluation CA #4 has been extended to 512li2009 to complete, evaluation and incorporation of a failure analysis into the RCA report. The extension of CA #4 was approved by the Site VP, CARB and P&C Manager IAW EN-LI -102 to exceed the 30 day disposition requirement. This administrative CARB tracking CA has been extended to accommodate the new RCA evaluation due date. There is no impact to Nuclear, Radiological, Environmental or Personnel safety by extending this CA. The CA&A Manager concurs with this extension. Approved
Description:
Approved per above discussion. IPEC00202311 IPEC00202311
Entergy I CORRECTIVE ACTION ICR-IP2-2009-00666 CANumber: 4 Group I Name I Assigned By: CRG-CARB-SARB IP2 Harrison,Christine B Assigned To: P&C Eng Codes Mgmt IP2 Azevedo,Nelson F Subassigned To : P&C Eng Component Mgmt IP2 Manzione,Stephen J Originated By: Harrison,Christine B 2/20/2009 12:05:50 Performed By: Azevedo,Nelson F 5/15/2009 15:12:27 Subperformed By: Azevedo,Ne1son F 5/15/2009 15:12:01 Approved By: Closed By: Tumicki,Michael L 5115/2009 16:08: 19 Current Due Date: 05/20/2009 Initial Due Date: 05/2112009 CA Type: DISP- RCA Plant Constraint: #NONE CA
Description:
Please perform root cause analysis and assign further corrective actions as required. Note that your evaluation is to be presented to CARB within 30 days and a corrective action is being assigned to CA&A to document this presentation. CA REFERENCE ITEMS: Type Code Description CARE-ACCEPT W-EDIT Minor
Response
See sub response below. Subresponse : See attachment files for RCA and other supporting documentation. All CARB comments have been incorporate and all CAs have been assigned. No additional actions required under this CA. Closure Comments: The RCA report was presented to and accepted with edit by the CARBon 5114/09. CA 3 captures the CARB comments. The CARB comments have been satisfactorly incorporated into the report and the revised report is attached to this CAs sub-response. This CA therefore closed. CA re-opened to responsible department to extend per VP request. MLT 3/20/09 The Root Cause Report contains the required sections and discussion popints and has been approved by an independant reviewer and the Responsible Manager as indicated on the cover sheet. It is noted the CAs in the report CA plan are not presently in PCRS and owner has elected to issue the CAs associated with the RCA after CARB review. RCA Report accepted pending CARB review and approval. MLT 3/19/09 Attachments: Subresponse Description Part 2- SIA Failure Analysis Report Subresponse Description Part 1 - SIA Failure Analysis Report Subresponse Description Root Cause Analysis Report Subresponse Description Internal OE Review Subresponse Description External Operating Experience Review IPEC00202312 IPEC00202312
Entergy I CORRECTIVE ACTION lCR-IP2-2009-00666 Attachments: Subresponse Description Why Staircase Analysis Subresponse Description Equipment Failure Evaluation Subresponse Description K-T Analysis IPEC00202313 IPEC00202313
Attachment Header Document Name: Document location Attach
Title:
IPEC00202314 IPEC00202314
( ; 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 {r Structural Integrity Associates, Inc. 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. lJ Structural Integrity Associates, Inc. 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 {! Structural Integrity Associates, Inc. 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). {J Structural Integrity Associates, Inc. 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. {J Structural Integrity Associates, Inc. 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. {J Structural Integrity Associates, Inc. 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. {J Structural Integrity Associates, Inc. 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 {1 Structural Integrity Associates, Inc. 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.
l) Structural Integrity Associates, Inc. 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
Attachment Header Document Name: Document Location Description Attach
Title:
IPEC00202248 IPEC00202248
Attachment Header Document Name: Document Location Attach
Title:
Report IPEC00202249 IPEC00202249
Entergy Operations, Indian Point Energy Center Root Cause Analysis Report CST Underground Recirc Line Leak CR-IP2-2009-00666 REPORT DATE: 05-14-2009, Rev. 0 Root Cause Evaluator: Anthony DeDonato 5/14/09 Team Leader (optional) Steve Manzione 5/14/09 Reviewer: Bob Sergi 5/14/09 Responsible Manager: Mike Tesoriero 5/14/09 (APPROVALS ABOVE REQUIRED BEFORE CARB REVIEW) CARB Chairman: Pat Conroy 5/14/09 Authenticated by Electronic Signatures in PCRS (LI-118, [3.0](8) b.3) Indian Point Energy Center CA&A IPEC00202250 IPEC00202250
Problem Statement "On February 16, 2009, Unit 2 entered a 7 day shutdown AOT due to an underground leak in the condensate storage tank return line." Team Members Team Lead Steve Manzione Root Cause Qualified Evaluator Anthony DeDonato P & C Engineering Nelson Azevedo Robert Lee K-T Member Lizabeth Lee EFin Greg Bouderau Civil Engineering KaiLo Mechanical Engineering John Bencivenga Operations Jan Mayer CA&A Mike Tumicki Fleet Joe Abisamra Root Cause Analysis Report
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Event Narrative On February 15, 2009, a CR was entered at 1629 EST. An Operator observed water filling the floor guard collar on the CST return line and spilling onto the floor on the 18' AFB pump area. Operations secured recirculation of CST -Hotwell. The Chemistry Department was contacted for sampling the spilling fluid. The Chemist reported 54ppb of Hydrazine in the water, which identified the water as condensate. CST was declared inoperable on Monday, February 16, 2009 at 0205 EST. Unit 2 was operating at 100% Rx power throughout the event. The source of the leak was determined to be just outside of the Auxiliary Feed Pump Room (AFPR) based on observations of the leakage at the pipe collar in the AFPR, the leakage observed from Manhole #5 just outside the AFPR door, and Engineering experience and judgment of the leak to be near a pipe bend. Work forces were mobilized and boring through the concrete slab and excavation of the pipes was commenced. The area was full of water, just below the concrete slab. A vacuum truck was used to remove the water and fme debris from the area. Larger objects were removed by hand. Workers reported the material was mostly clay under the floor. There was no evidence of any sand around the pipes. Some construction debris was also unearthed. Based on the condition of portions of the coating, the through wall leak and other defects on the pipe, a decision was made to replace the section of the pipe. Timeline of Major Events Sunday, 2/15/09@ approximately 1500 Water was identified leaking into the IP2 Auxiliary Feedwater Pump Building through a vertical pipe sleeve for the 8 CST return line. Sunday, 2/15/09@ approximately 1600 Chemistry results show 54ppb Hydrazine, which indicates it is condensate. The FSS contacts the Engineering Duty Manager (EDM). A conference call is held between Engineering management and supervisors. Sunday, 2/15/09@ approximately 1900 The EDM arrives on site, inspects the pipe sleeve, confirms water is rising up and requests another chemistry sample for confirmation of condensate. Sunday, 2/15/09 @ approximately 2100 Further Engineering inspection reveals water is leaking into Manhole #5 at two locations through the masonry joints. (Manhole #5 is located in the FRV Room approximately 5' west of the underground location of the 8" line.) The Watch Chemist is instructed to take samples of incoming flows into Manhole #5. Root Cause Analysis Report
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Event Narrative Timeline of Major Events (continued) Monday, 2116/09 approximately 0205 The CST was declared inoperable and entered the 7-day AOT. Chemistry samples confirm the water is condensate in both the pipe sleeve and the effluents entering Manhole #5. The group decided to meet at 10:00 AM the following morning. Monday, 2/16/09@ approximately 1200 Civil Engineering maps out the line location underground and determines the area to be excavated based on the configuration of the pipe. Construction is mobilized. Monday, 2/16/09@ approximately 1900 Core drilling operations commenced in preparation of slab removal for excavation of the area. First indications that water saturation is present under the slab. Demolition by jackhammer is not allowed due to possible undermining. Monday, 2/17/09@ approximately 0500 Core drilling operations in progress; the first 2' x 2' section of the slab is removed. Standing water is present under the slab. Three small sump pumps are needed to keep up with the water. Monday, 2/17/09 @ approximately 1700 Removal of the concrete slab was completed. Tuesday, 2/17/09@ approximately 2200 Shoring is installed in the excavation; a containment area for removed soil is set up. Tuesday, 2/17/09@ approximately 2400 The vacuum truck arrives on site. Wednesday, 2/18/09@ approximately 0230 Excavation of the site begins. Wednesday, 2/18/09@ approximately 1800 Chemistry increases the amount of Hydrazine in the Condensate System and monitors the level of HydraziDe in the area. Wednesday, 2118/09 approximately 2100 Operations calculates the make up to the CST is approximately l7gpm. Chemistry confirms the leak in the 8" line to the CST based on rising Hydrazine levels in Manhole #5. Root Cause Analysis Report
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Event Narrative Timeline of Major Events (continued} Thursday, 2/19/09 approximately 0100 12" pipe is exposed and no leakage is seen. Thursday, 2/19/09@ approximately 0330 8" pipe is exposed and the leak is seen at the horizontal section of the pipe. Thursday, 2/19/09@ approximately 0400 Engineering assesses the leak is located at the 5:00 position of the pipe and determines the pipe is structurally sound to accept a housekeeping patch. Thursday, 2/19/09@ approximately 0600 A full circle clamp with longer bolts is installed over the leak; it slows it down enough for the sump pumps to keep up with dewatering, allowing further inspections. Thursday, 2119/09 @ approximately 1200 Abatement of the coal-tar coating begins. Thursday, 2119/09 @ approximately 2100 Abatement is completed; visual inspection and UT of the line is started. Thursday, 2/19/09 @ approximately 2230 Visual inspection and UT of the line is completed. Several areas of minor degradation were found on the lower elbow and horizontal section of the pipe. A decision was made to replace the elbow and damaged section of the pipe. Friday, 2/20@ approximately 0100 Shop work on the replacement pipe is started. Friday, 2/20 @ approximately 0500 Shop weld is completed. NDE was performed on the weld, MT SAT. Friday, 2/20 approximately 0500 Entered a 72-hour AOT for 22ABFP in order to accommodate the pipe and elbow replacement and isolated line #1509. Root Cause Analysis Report
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Event Narrative Timeline of Major Events (continued) Friday 2/20/09 approximately 1200 Pipe and elbow section removed. Friday 2/20/09 @approximately 1700 Pipe fitted into place. Weld out of two field welds begins. Saturday 2/21/09 @ approximately 0400 Work completed, NDE performed, MT reading SAT, Operations commence clearance of PTO and filling line. Saturday 2/21109 @approximately 0530 Line verified fill, in service VT -1 leak inspection performed by Operations; no leaks observed. Saturday 2/21109@ approximately 0600ABFP 22 declared operable, exited the 72-hour AOT. Saturday 2/21109 @ approximately 0630 CST Line declared operable, exited the 7-day AOT. All work secured. Root Cause Analysis Report
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Event Narrative Background Information
- Lines 1505 and 1509 are carbon steel, schedule 40. Line 1505 is the 12" supply from the CST to the AFPs.
Line 1509 is the 8" CST return line. These lines were deemed not to require cathodic protection during original plant design due to favorable soil resistivity and drainage characteristics. As a defense against localized corrosion attack, however, lines 1505 and 1509 were externally coated with coal tar enamel and have a coal tar enamel saturated felt overwrap. These pipes are sloped from the CST elevation to the AFPB, and are each approximately 320-330 feet in length.
- Several months prior, a similar event occurred when water was observed at the same pipe sleeve.
Excavation of the CST lines at 2 locations was in-progress at this time of inspection. The leak was attributed to groundwater due to the open excavations. No hydrazine was detected. This was based on Chemistry testing for activity, pH and hydrazine.
- The backfill that was used in this area during original installation contained various size rocks and other foreign material such as cans and wire. The backfill used was for a light load area.
- Groundwater is suspected to also infiltrate the area.
- Line 1509 does not experience "movement". The buried pipe is installed below the freeze line. Other than seismic activity, there is no ground movement accounted for in the design nor anticipated to occur. Thermal expansion is very small due to the small delta T that may be experienced if the water from the CST was at its high temperature of approximately 100 degrees °F. However, thermal growth would not cause pipe movement since the pipe is restrained by the ground in the vertical rise at both ends.
- The area is used as a walkway. If there is significant heavy load on top of the slab and the fill has 3" to 8" large rocks (confirmed by observers), the heavy load can force the pipe to deflect downward and pinch on the rock, causing damage to the coating.
- Underneath the 6'x 6' cut hole on the floor slab, the fill was washed out locally.
- AFW building is supported by the foundation and containment building walL The foundation is into the bedrock and loss of fill will not affect the load transfer capability from the slab, to the wall, to the foundation and onto the bedrock. The containment mat foundation is into the bedrock and will not be affected by the leak.
Root Cause Analysis Report
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Event Narrative Background Information (continued)
- Sections of the bituminous type wrap were discovered damage-d some voids around the area of the leak and 90~ elbows.
- The specific 1989 ASME Code requirement to be met for the buried pipe # 1509 is IWA-5244( c) which requires verification of non-impairment of flow in the non-isolated and non-redundant line to the heat sink. This specific requirement is met by performance of a pump test which verifies the ability to obtain and control recirculation flow. This inspection is required to be performed three times within the 10 year interval. Successful performance of PT -Q34 in conjunction with the PI-3Y4A Inservice Inspection services as verification of non-impairment of flow.
- Seismic concerns: based on outside study, historical seismic activities around IPEC from 1974 until 2007 fell into a range of modified Mercalli scale of 2.4 to 3.0. The range of seismic activity at the plant is less than 3.0 (0.007g) and IPEC is designed toM= 6.5, well below the plant's design ground response spectrum. The leak location has exterior surface/coating damages that appeared to be caused by impact from large, angular external object. It is highly unlikely that uniform seismic ground movement with a buried pipe could cause such a surface impact.
- An Entergy Engineering Fleet Call was conducted on March 4, 2009, which discussed the failure of the CST return line #1509.
CST Operation and Secondary leak detection The condensate Storage Tank (CST) supplies makeup water to the Condensate System and to the Auxiliary Feed Water Pumps (AFP) during hot shutdown decay removal via a common 12" underground pipe. The CST is sized to supply a minimum inventory of 360,000 gals for 24 hrs of decay removal in hot standby following a plant trip as well as additional inventory for Condensate operation. This 12" supply line first feeds an 8" common AFW supply header in the ABFP, and then is routed to the Turbine Bldg via LCV-1158 which will automatically isolate make up to the Condensate System to protect this minimum inventory for AFW in this 600,000 gal design capacity tank. An 8" return header off condensate pump discharge is routed underground back to the CST for inventory control. AFPs recirc back to the CST via individual3" lines that tap into this 8" Condensate Return header to maintain minimum design pump flow whenever running AFPs are not feeding Stearn Generators. Normal operational lineup in the Turbine building is as follows, the CST supply valves (LCV-1127 & ll28A) to the condenser hotwells are throttled open in manual control. Condensate System return is controlled in manual via LCV-1129 which is normally kept shut in warm weather. In the winter, LCV-1129 is throttled open to maintain CST temperature between 50 and 65°F. Summer CST temperatures can range in the 80's. Root Cause Analysis Report
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Event Narrative CST Operation and Secondarv Leak Detection (continued) A mobile unit supplies primary water to U2 via portable demineralizers to the three Ul Condensate Storage Tanks. From here, water factory Deaerator Booster Pumps supplyU2 condensate makeup to the Drains Collecting Tank (normal path) or to the U2 CST. Flow to the Drains Collecting Tank (OCT) is adjusted using Booster Pump (BP) flow (FI-531) or Primary Water Flow to the OCT (FIT-10001) meters for rough monitoring of manual changes. Operators control secondary makeup by monitoring average Hotwelllevel in the Control Room. They attempt to match BP flow to the OCT with condensate losses. These losses include 100 gpm S/G Blowdown (or 70 gpm cold), 20 gpm Aux Steam heating (winter), 10-20 gpm condensate leakage and steam loss. Other than S/G blowdown there are no meters to track process losses. Operators allow CST level to track down slowly to makeup for the difference between OCT supply and secondary losses Operations initially estimated the return line loss at 17gpm by shutting LCV-1158 and 1129 and subtracting the difference in CST rates of level change. This assumes no leak by LCV-115 8 and no siphon break in the Return line. A 10 gpm loss equals 14, 000 gallons a day. This equates to a CST level loss of9 in/day or 3/8 in/hr. This would be hard to detect by monitoring CST level changes because the indicator in the CCR has intervals of feet, and such small changes cannot be visibly seen unless tracked over a few days. Since the CST is not the primary means of making up secondary losses, a 10 gpm leak would go unnoticed by watching CST levels. Hotwelllevel is maintained at about 4' or 76,000 gals. At 19,000gaVft., a 10 gpm loss equates to about 3/8 in/hr change in hotwelllevel. Since operators maintain hotwelllevel within a close band, leak rate changes can't be detected by hotwelllevel. Root Cause Analysis Report
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Event Narrative IPEC Buried Piping and Tank Inspection and Monitoring Program The IPEC Buried Piping and Tank Inspection and Monitoring Program, hereafter simply referred to as BPT Program, is under development. The foundational elements of the program have been completed per scheduled milestones identified in Entergy fleet procedure EN-DC-343, which went into effect on Nov. 19, 2007. The fleet procedure required that all systems having buried portions of piping be included in the program, including but not limited to those systems that were identified in the IPEC License Renewal Application (LRA). Once all buried piping systems were identified, the piping was assessed as having High, Medium or Low Impact, based on the consequences of a failure of the piping in the following areas:
- Safety (High = Nuclear Safety Related; Medium= Augmented Quality/Category M; Low = non-safety related)
- Public risk (High = potential radiological consequence; Medium= environment discharge or hazardous fluid; Low= non-contaminated, non-hazardous fluids)
- Economic impact of equipment failure on plant operation (High= >$1M; Medium= $lOOK-
$1M; Low <$lOOK.)
Table 1 presents the details for performing the impact assessment. Using the impact assessment results, the High Impact systems are Corrosion Risk assessed with consideration of the following four (4) factors:
- 1. Soil resistivity
- 2. drainage
- 3. material
- 4. coatings/cathodic protection.
Tables 2 and 3 present the details for performing the corrosion risk assessments. Corrosion risk assessments were performed sequentially for the High, Medium and Low Impact system. Root Cause Analysis Report
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Event Narrative IPEC Buried Piping and Tank Inspection and Monitoring Program (continued) In conjunction with the corrosion risk assessments, the inspection priorities for performing the initial inspections and subsequent inspection intervals were determined for each buried piping system based on the results of the Impact and Corrosion Risk assessments. Table 4 provides the guidance for scheduling these inspections. Buried pipe inspection parameters will include:
- External pipe coating and wrap condition
- Pipe wall thickness
- Cathodic Protection effectiveness (if applicable)
Current plans are for a Central Engineering Programs document for buried pipe and tanks be developed (target issue by end of2009), and for each site to manage its buried pipe activities (surveys, excavations, inspections, etc.) using IDDEAL Scheduleworks, or similar software. IPEC License Renewal Application (LRA) commitments for Buried Piping and Tanks Program: IP2 Commitment NL-07-039 Sept. 28, 2013 IP3 Commitment NL-07 -153 Dec. 12, 2015 The excavations and inspections of the IP2 AFW lines to the CST were performed in response to the ISE Panel recommendation to complete same by the end of2008. Root Cause Analysis Report
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Event Narrative Utility Experience Most utilities are in the process of early Buried Piping and Tank Program development. Some (as IPEC, in 2005) have received INPO AFI's for non-functioning Cathodic Protection systems for their buried piping. At IPEC, however, Cathodic Protection systems are generally not provided for buried piping systems (exceptions being the sewage treatment pipeline, and underground diesel fuel oil lines). Resolution of the IPEC AFI is focused on correcting deficiencies in the installed cathodic protection system. According to the Unit 2 and Unit 3 USF ARs, the basis for not providing cathodic protection systems for buried piping was an engineering study performed during original licensing of the plants. Determinations of the soil resistivities at locations away from the river were concluded to be sufficiently high to preclude the need for cathodic protection for buried piping. The study recommended the application of protective coating to prevent local corrosion attack. Based on recent resistivity testing, the original resistivity determinations remain consistent. An EPRI guidelines document (1016456) for an effective buried pipe program was issued in Dec. 2008. Future revision to the document is planned and will include:
- Buried tanks
- Non-metallic pipe Industry initiatives are being taken to identify underground piping assessment technologies to perform assessments of coating integrity/condition, to identify degraded pipe locations and to quantify associated wall loss.
The EPRI buried piping guidance document has identified several methods that are used in the gas and oil pipe lines industries, but has not endorsed them. Root Cause Analysis Report
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Event Narrative Table 1- Impact Assessment High Medium Low Safety (Class per Augmented QP and Fire Safety-related Non-Safety related EN-DC-167) Protection Radioactive Chemical/Oil-Treated Untreated Water, SW, Public Risk Contamination e.g. System Gases Demineralized Water Tritium Economics (Cost of buried
> $1M or potential equipment failure to the $lOOK- $1M <$lOOK shutdown plant)
Notes: 1. Any buried section with at least one High Impact gets an overall High Impact rating.
- 2. Any buried section with no High Impact rating but at least one Medium Impact rating gets an overall rating of Medium Impact.
- 3. Any buried section with all Low Impact ratings is to be rated as Low Impact.
Root Cause Analysis Report
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Event Narrative Table 2 -Corrosion Risk Assessment Soil Resistivity Corrosivity Rating Soil Resistivity Risk Weight Q-cm (Note 1)
> 20,000 Essential Non-Corrosive 1 10,001 20,000 Mildly Corrosive 2 5,001- 10,000 Moderately Corrosive 4 3,001 5,000 Corrosive 5 1,000- 3,000 Highly Corrosive 8
< 1,000 Extremely Corrosive 10 Drainage Drainage Risk Weight Poor Continually Wet 4.0 Fair Generally Moist 2.0 Good Generally Dry 1.0 Material Material Risk Weight Carbon and Low Alloy Steel 2.0 Cast and Ductile Iron 1.5 Stainless Steel 1.5 Copper Alloys 1.0 Concrete 0.5 Cathodic Protection Coating CP/Coating Risk Weight NoCP Degraded Coating 2.0 NoCP Sound Coating 2.0 NoCP No Coating 1.0 Degraded CP Degraded Coating 1.0 Degraded CP Sound Coating 1.0 Degraded CP No Coating 0.5 Sound CP Degraded Coating 0.5 Sound CP Sound Coating 0.5 Sound CP No Coating 0.5 Note: Soil resistivity measurements must be taken at least once per 10 years unless areas are excavated and backfilled or if soil conditions are known to have changed for any reason.
Root Cause Analysis Report
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Event Narrative Table 3 Corrosion Risk Tabulation Corrosion Condition Risk Weight Points Soil Conditions Resistivity 1- 10 Drainage 1-4 Materials Material 0.5-2 Component Protection Cathodic Protection I Coating 0.5-2 Final Corrosion Risk Tabulation Multiply all weights together in Steps 5.5 [2] (a) thru (d) 0.25 160 Corrosion Risk: High 61- 160 points Medium 30 60 points Low 0 29 points Root Cause Analysis Report
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Event Narrative Table 4 - Inspection Intervals vs Inspection Priority Impact - Corrosion Risk Inspection Priority Initial Inspection Inspection Interval (Years) (Years) High-High High 5 8 High-Medium High 5 8 Medium-High High 5 8 High-Low Medium 8 10 Medium-Medium Medium 8 10 Low-High Medium 8 10 Medium-Low Low 10 15 Low-Medium Low 10 15 Low-Low Low 10 15 Notes: 1. High priority initial inspections shall be scheduled within 5 years. Subsequent high priority inspections shall be scheduled within 8 years thereafter.
- 2. Medium priority initial inspections shall be scheduled within 8 years.
Subsequent medium priority inspections shall be scheduled within 10 years thereafter.
- 3. Low priority initial inspections shall be scheduled within 10 years. Subsequent low priority inspections shall be scheduled within 15 years thereafter.
- 4. Regardless of the above inspection schedule (reference EN-DC-343),
compliance with IPEC LRA commitments prevail.
- 5. Once initial inspections are performed and conditions before known, a re-prioritization may maintain, decrease or increase a component future inspection priority.
The CST line (#1509) was assessed per EN-DC-343 to be a "High" inspection priority. Root Cause Analysis Report
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Event Narrative Previous Inspections of CST 8" Line As a result of the Indian Point Independent Safety Evaluation (ISE) Report dated July 31, 2008, the following recommendation (R-7) was issued via LOCR IP3L0-2008-00151, CA-19: "to explore options for reducing the vulnerability of buried piping to the occurrence of any future unanticipated leak. Such options include excavating a few selected locations to confirm the presence of protective coating on the piping, as well as to measure and confirm the existence of sufficient wall thickness of the thus exposed piping using existing inspection techniques." Two areas of the Unit 2 CST lines were selected for inspection. The following information was retrieved from CR IP2-2008-04754. The three CST pipes (Aux Feed Pump supply, CST return and CST overflow) were exposed at two locations for approximately 10' piping runs each. The three inspected lines were: 12" Line 1505, AFP Suction line, 8" Line 1509, Condensate supply to the CST 10" Overflow Line (no line number assigned, corrugated metal pipe to Manhole #5 Upper and lower holes were excavated. An inspection in the upper hole identified five areas which required coating repair. UT thickness measurements were also performed on those areas where the base metal was exposed and these inspections confirmed that the pipe thickness remains at nominal thickness (i.e. within the manufacturer's tolerance). All of these activities were performed under WO 164495. The visual inspection of these pipes at the lower excavation revealed that they were in generally good condition, with the coating intact and in acceptable condition. A minor coating repair was required at one location on 8" Line 1509 and the 10" overflow line required repair at the top portion of the pipe at the crests of the corrugations, possibly indicative of coating damage during the digging. Based on the results of these pipe visual inspections (at the upper and lower holes), and the coating repairs performed, there was no evidence of any significant pipe degradation that would warrant there-inspection of these pipes at the same locations. Future inspection of these lines will be performed at different location(s) along their length. The scheduling of the future inspections will be controlled under the IPEC Buried Pipe Program. Specifically for the CST lines, CA-5 ofCR IP2-2008-04754 reads, "Given the results of the leak in the AFP Building, determine if the scope and/or frequency of future buried condensate lines should be modified. This should cover both IP2 and IP3." See elevation drawing on the next page. Completed assessments of these lines determined these lines to be of HIGH impact (two lines are safety related), MEDIUM corrosion risk and HIGH inspection priority. The HIGH inspection priority results from the safety function performed by Lines 1505 and 1509. The pipe material, soil resistivity and site condition factors result in these lines being of medium corrosion risk. Accordingly, with the initial inspection of these lines performed in October/November 2008, re-inspection of these lines is required within eight years, or by September 2016. Root Cause Analysis Report
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Event Narrative
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l Root Cause Analysis Report
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Event Narrative The configuration ofthe underground structures in the area is laid out as follows: The ABFP Building column wall #22 is a solid concrete wall anchored directly to the bedrock that spans from the east wall to the west wall. The ABFP Building wall begins at approximately the 12' elevation (6' below grade) and is connected to the containment shield wall on the east end and the ABFP shield wall on the west end. The column wall #21 is a solid wall anchored directly to the bedrock. The east wall running north to south does not penetrate below grade. The west wall running north to south does not penetrate below grade but the structure for Manhole #5 is located in this area. There are two concrete slabs under the pipes in this area. One is the pad for the stairs and the other is believed to be related to Manhole #5. They are between 4-8" below the pipe. Based on this, the area can be described as being similar to a "bath tub" that drains slowly. The slab construction in this area is approximately 6-8" thick and was poured as a monolithic slab on grade with sporadic reinforcement installed. There was one area that had what appeared to be 6 x 6 welded wire mesh. But it was not consistent throughout the slab and was not heavily supported when the slab was originally poured. This arrangement would not be unusual for a walkway design. Once excavation began, it was apparent that there was significant amount of standing water beneath the slab and the backfill was saturated. The backfill also had significantly reduced in volume and was not supporting the slab in this area. The gap between the slab and top of the backfill was approximately 6" to 10", covering an area approximately 8' x 8'. There also was an area that appeared to be washed out measuring 2' x 2' and greater than 6' deep. The backfill in the area contained rocks measuring up to 8" and other debris such as several aluminum cans and other debris. The large rocks were found throughout the excavation area and a concentration was found closer to the pipe, especially in the area of the 2' x 2' sinkhole. The debris and rocks would hamper the achievement of proper compaction of the area due to the creation of voids and an increase in the amount ofun-compactable material. The configuration of the underground structures that encompass the area allows some ground water to collect due to run off from the north hill and surrounding area. The elevation of the 8" pipe is estimated to be at or just above the groundwater table area; this is based on the surveys of the installed test wells in the area. Some groundwater infiltration has been seen leaching into the bottom of the excavation site, creating a wet environment around these lines. The 12" line (#1505) and the 8" line (#1509) are carbon steel, schedule 40. These lines were deemed not to require cathodic protection during original plant design due to favorable soil resistivity and drainage characteristics. As a defense against localized corrosion attack, however, lines 1505 and 1509 are externally coated with coal tar enamel and utilize a coal tar enamel saturated felt overwrap for further protection of the coating. It is a general coating practice to pull a glass matt into the hot enamel as reinforcement, and the outer side of the coating is saturated asbestos felt. The same corresponding lines at Unit 3 are above ground, insulated and heat traced, except outside the ABFB as described on page 35. The bituminous coatings, as a class, are the most widely used protective media. These classes include asphalt enamels, the greases or waxes, and other mastics which consist of an asphalt or coal-tar base plus an inert binder. Of the large group of coatings tested under the joint effort ofthe National Bureau ofStandards and the American Petroleum Institute, concluded that asphalts and coal-tar enamels were the best. Root Cause Analysis Report
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Event Narrative Coal-tar coatings have been used for over 100 years to protect ferrous metals against underground corrosion. In 1913, an early form of coal-tar enamel was used in protecting gates, locks and penstocks of the Panama Canal. Examination after 35 years of service showed them to be in perfect condition. Coal-tar pitch is almost completely inert to moisture and soil chemicals. Coal-tar coatings and coal-tar pitch used as pipe coatings and for waterproofmg have been dug up after 20 to 50 years of service underground. Coal-tar pitch does not absorb any appreciable water and is not affected to any appreciable extent by soil bacteria. These properties make it eminently more suitable for waterproofing and coating ofburied steel pipe lines to protect them from the corrosion action of wet soil. If properly applied, the coating should be able to protect the lines in there currently installed environment and is within the life span of the protective coating. Flow accelerated corrosion (F AC) was not part of the failure mechanism as described below. Flow accelerated corrosion of carbon steel in water occurs due to the dissolution of the normally protective magnetic film that forms on the surface. (Mechanical removal, i.e. cavitation-erosion, does not normally occur under F AC conditions.) This corrosion was outside to inside on the pipe, and temperature attributes for F AC are generally between 212 "F and 5 72 "F. The leak in the 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 likely occurred at localized areas of coating damage that occurred during installation of the pipe. In comparison, other corrosion found on the removed elbow which affected a larger area but it was not as deep is more typical of corrosion related to difficulties in applying a good quality coating on more complex surfaces such as elbows and other fittings. For additional details on the failure analysis, see Structural Integrity Associates (SIA) Report No. 0900235.402. Root Cause Analysis Report
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Event Narrative Conclusions From the infonnation gathered, the event was caused by the failure of the protective coal-tar epoxy coating that was applied at the time of original construction. Based on historical date, the coating, if properly applied, remains undamaged is sufficient to provide corrosion protection of the pipe. This is based on outside studies and the results of the previous inspection and analysis performed in 2008. The coating failure was a direct result from the installation and type of backfill. The eventual location of the "through wall leak" on the straight horizontal pipe at this location was due to a localized coating failure in this area that made it the most susceptible area to degrade once the mechanism for corrosion started. There were other localized areas on the straight pipe section and 90 o elbow that were in a very advanced state of corrosion, also would have, given more time, would have eventually produced additional leak locations. The ground water infiltration, soil composition, and the location of the leak at the lowest point of the system were all contributing factors to the leak developing in this area. Root Cause Analysis Report
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Root Cause Evaluation The Direct Cause (DC) was a through-wall defect in the CST return line located below grade in the ABF Building. There is evidence that the pipe coating had degraded allowing corrosion to eventually penetrate its way through the pipe wall. A. ROOT CAUSE(S)
- 1. RC 1 - The Root Cause (RC-1) is the installation specification 9321-01-8-4 in effect at the time of plant construction. There is evidence that sections of the pipe coating were damaged by rocks that were present in the backfill for the CST lines. The pipe coating material is fiber-based saturated with coal-tar. The material is then applied to the pipe. Since it is a fiber, the coating is susceptible to damage from the various size rocks found in close proximity to and in some cases, up against the pipes themselves.
The rocks present in the backfill caused coating degradation in some areas of the pipes, making the pipes susceptible to external corrosion. It is evident that soil conditions influence the corrosion rate on those sections of pipe where there is coating degradation. For example, in the sample inspection holes, some coating degradation was found accompanied by minor surface rust. Ultrasonic Testing (UTs) of these areas found virtually no pipe wall loss. The soil conditions in the sample inspection holes were mostly dry, with minimal ground water present. By contrast, the soil in the failure location was found to be moist, which is consistent with the water table in the area estimated to be at the eight to ten foot elevation. The absence of gravel and sand surrounding the pipe promotes wicking of the ground water through the soil which also contributes to the moist conditions in the area. Therefore, the combination of degraded pipe coating and high water table served to accelerate corrosion of the failed pipe. Root Cause Analysis Report
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Root Cause Evaluation B. CONTRIBUTING CAUSE(S) CC 1 The water table in the area of the leak is between eight to ten feet with the pipe elevation at approximately ten feet. The backfill specification did not specify the use of clean sand and gravel under the pipe that would have limited the wicking of the ground water to the soil surrounding the pipes. This kept the soil in the area moist, and at times wet. These soil conditions would find its way into defects in the coating causing corrosion external to the pipe. CC 2 - The inspection techniques used to preemptively detect underground pipe through wall leaks was ineffective. Buried Piping and Tank Inspection and Monitoring Program does not identifY the low point of a pipe line as a suggested sample test point. The procedure inspection locations are based on risk and impact assessments, ease of access, limitations of inspections and ability to isolate lines. Root Cause Analysis Report
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Root Cause Evaluation C. 0RGANIZA TIONAL AND PROGRAMMATIC WEAKNESS EVALUATION: The team performed an Organization and Programmatic Issues Review in accordance with Attachment 9.5 of EN-LI-118.
- 1. Organization and Programmatic Issues for Installation Concerns OP2J Is there evidence that personnel exhibited insufficient awareness if the impact of actions on safety and reliability?
Yes. The drawings and specifications allowed the use of material (already available on site) from blasted areas as fill for this buried pipe. OP4A- Is there evidence that there are insufficient details in a procedure to perform the task? Yes, at the time of installation, UE&C Specification No. 9321-01-8-4, Placing and Compaction of Backfill, was used as backfill guidance. This spec only stated the following, "Place fill in 12" layers and compact with tamper in small areas or by dozer or trucks in open areas. Top 12" shall be clean and compacted as noted on drawings." Drawing 9321-F-1002 states to "top off with gravel." Drawing 9321-F-1024, Containment Building Backfilling and Grading North and East Side, has a note which reads, "Surface of fill to be random size blasted rock from Unit 3 excavation." Presently for Unit 2, Con Edison Specification 02200 governs excavation and backfilling. For Unit 3, today's specification is UE&C Specification 9321-05-8-4, Placing and Compaction of Backfill, which is very similar to the original Unit 2 specification. OP5E Is there evidence of inadequate job skills, work practices or decision making? Yes, there could have been the potential for poor job skills and work practices when applying the pipe coating, because the fill used was a contributor to the coating damage that was observed. All of the above identified issues occurred over 30 years ago, and there are corrective actions to address them. Present equipment and construction specifications and quality control/assurance review, the Engineering modification process would minimize these occurrences from repeating themselves. Interim corrective actions will be issued with this report to address these concerns.
- 2. Organization and Programmatic Issues for an Inadequate Buried Pipe Program (EN-DC-343)
OP4A Is there evidence that there are insufficient details in a procedure to perform the task? Yes, EN-DC-343, Buried Piping and Tank Inspection and Monitoring Program does not identify the low point of a pipe line as a suggested sample test point. The procedure inspection locations are based on risk and impact assessments, ease of access, limitations of inspections and ability to isolate lines. A corrective action to address this issue would be for the Entergy Fleet team to assess the addition of this point in the procedure, EN-DC-343. Root Cause Analysis Report
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Root Cause Evaluation D. Safety Culture Evaluation The root cause and contributing causes were reviewed against EN-LI -118, Attachment 9 .6, Safety Culture Evaluation. It was determined that 12 of the 13 impact areas were not applicable to the causes identified within this root cause analysis. However the Human Performance portion of the Safety Culture was impacted because complete, accurate and up-to-date Design Specifications were not in place during original backfill and supervisory and management oversight of work activities and contractors were not effectively implemented to prevent inappropriate backfill practices. E. Equipment Failure Evaluation- see Attachment. Root Cause Analysis Report
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Generic Implications Extent of Condition Review As previously stated in this evaluation, the condition of the CST return line through-wall degradation and eventual leakage, was corrosion of the carbon steel piping material caused by coating imperfections and soiVground water conditions. Based on the cause of the corrosion and a review of the IPEC Buried Piping Program. it has been determined that all buried coated carbon steel piping could be susceptible to the same corrosion mechanism since the same materials and construction practices used to install the CST return pipe could have been used in other systems. Although all buried piping could be susceptible to external corrosion, recent inspections and operating experience indicate that piping buried at the lower site elevations could have a higher susceptibility because of the closer proximity to the ground water. This was confirmed by the Fall of 2008 excavations which indicated that piping with areas of degraded coating experienced essentially no degradation other than minor surface corrosion. On the other hand, the auxiliary steam pipe between IPl and IP3, and the IP2 condensate return lines, experienced significant degradation in areas where the protective coating or insulation was either missing or degraded. In the case of the auxiliary steam piping, the incorrect type of insulation was installed (water retentive vs. water shedding). Both the IP2 CST return line and the auxiliary steam piping were buried under the 15' ground level while the two excavated locations were at the 60' + elevation. Unlike IP2, the piping at IP3 from the CST down to the transformer yard is supported above grade, heat traced and insulated. The impact and risk assessments performed for the Buried Piping Program identified the following systems having buried piping that are deemed high priority for inspection: City Water City Water EDG Fuel Oil EDG Fuel Oil Service Water Service Water CST Piping CST Piping Aux Steam Steam Generator Blowdown Root Cause Analysis Report
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