ML081780742

Filing Discussing Proprietary Documents in the Matter of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc

ML081780742
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	06/19/2008
From:	Tyler K New England Coalition, Shems, Dunkiel, Kassel, & Saunders, PLLC
To:	NRC/SECY/RAS
SECY RAS
References
50-271-LR, ASLBP 06-849-03-LR, RAS M-100
Download: ML081780742 (147)

Text

{{#Wiki_filter:HuL SNSA-AS SHEMS DUNKIEL KASSEL & SAUNDERS P L L C RONALD A. SHEMS* GEOFFREY H. HAND' KAREN L. TYLER BRIAN S. DUNKIEL** REBECCA E. BOUCHER ASSOCIATE ATTORNEYS JOHN B. KASSEL DOCKETED EILEEN 1. ELLIOTT USNRC OF COUNSEL MARK A. SAUNDERS June 20, 2008 (8:00am) ANDREW N. RAUBVOGEL OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF June 19, 2008 Office of the Secretary Attn: Rulemaking and Adjudications Staff Mail Stop O-16C1 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Re: In-the Matter of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. (Vermont Yankee Nuclear Power Station), Docket No. 50-271-LR, ASLBP No. 06-849-03-LR Filing Discussing Proprietary Documents

Dear Sir or Madam:

Please find enclosed for filing in the above-stated matter New England Coalition, Inc.'s Opposition to Entergy's Motion in Limine. This filing attaches an expert witness report, NEC-UW_03, which discusses the following documents that Entergy has designated proprietary, all of which NEC has previously filed in this proceeding:

1. Recommendations for an Effective Flow-Accelerated Corrosion Program (NSAC-202L-R3);

2. EPRI: Recommendations for FAC Tasks;

3. Letter to James Fitzpatrick from EPRI (February 28, 2000); and

4. Letter from Entergy to NRC re. Extended Power Uprate: Response to Request for Additional Information.

The first two documents are EPRI guidance documents for flow-accelerated corrosion programs. The third is a letter to an Entergy staff person at the Vermont Yankee (VY) plant, stating EPRI's evaluation of the VY FAC program, and recommending certain changes to that program. The fourth is Entergy's response to a NRC Staff Request for Additional Information concerning issues related to Entergy's VYNPS EPU application. 9 1 COLLEGE STREET BURLINGTON, VERMONT 0540 1 TEL 802 X860 1003

• FAX 802 / 860 1208 - www.sdkslaw .com lSo-0

                                                                                                           *Also;                        Maine Also admitted in the District of Columbia

Pursuant to the Protective Order governing this proceeding, an unredactedwersion of this filing, including the four proprietary documents, will be served only on the Board, the NRC's Office of the Secretary, Entergy's Counsel, and the following persons who have signed the Protective Agreement: Sarah Hoffman and Anthony Roisman. A redacted version of this filling that does not include the proprietary documents will be served on all other parties. Thank you for your attention to this matter. Sincerely, Karen Tyler SHEMS DUNKIEL KASSEL & SAUNDERS PLLC Cc: attached service list

                       /

2

UNITED STATES NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges: Alex S. Karlin, Chairman Dr. Richard E. Wardwell Dr. William H. Reed In the Matter of )

                                                             )

ENTERGY NUCLEAR VERMONT YANKEE, LLC ) Docket No. 50-271-LR and ENTERGY NUCLEAR OPERATIONS, INC. ) ASLBP No. 06-849-03-LR

                                                             )

(Vermont Yankee Nuclear Power Station) . ) NEW ENGLAND COALITION, INC's OPPOSITION TO ENTERGY'S MOTION IN LIMINE New England Coalition, Inc./ ("NEC") opposes Entergy's motion to exclude from the record portions of its direct and rebuttal testimony and other evidence. The Nuclear Regulatory Commission rules that govern the Board's decision of this motion require only that evidence must be "relevant, material, and reliable," and that a party's rebuttal must be "directed to the initial statements and testimony of other participants." 10 'CFR §§ 2.337(a), 2.1207(a)(2); See also, 10 CFR § 2.319(d)("In proceedings under this part, strict rules of evidence do not apply to written submissions."). "Relevant" evidence is defined by the Federal Rules of Evidence as "evidence having any tendency to make the existence of any fact that is of consequence to the determination of the action more probable or less probable than it would be without the evidence." Federal Rules of Evidence 401. With one exception noted below;-NEC's testimony and other evidence

that Entergy would exclude from the'record meets these standards and is therefore admissible. The scope of admissible evidence in this' ASLB hearing overseen by a panel of judges with te~chnical expertise is very broad in recognition that such a panel is well equipped to evaluate the evidence and give it its proper weight in the' final decision. The Supreme Court relaxed the formal rules about the admissibility of evidence in agency proceedings as early as 1904. Today, it is well accepted in federal courts that relevant evidence not admissible in court, including hearsay, is admissible at an administrative hearing. Not only may an agency admit and rely on evidence not admissible at trial but it cannot ignore relevant and probative evidence merely because the evidence would not be admissible in a trial. This has developed because the rules of evidence are designed to protect unsophisticated members of a jury and hence are not appropriate for hearings in which the trier of fact is sophisticated and usually expert in the area of the factual controversy. 2 Admin. Law & Prac. §5.52; See also, Catholic Medical Center of Brooklyn and Queens, Inc. v. N.L.R.B., 589 F.2d 1166, 1170 (1978)("an agency thus may not provide for the exclusion of relevant evidence"). The majority of Entergy's arguments for exclusion of NEC's evidence go to its weight, not its admissibility. I. The Board Should Deny Entergy's Motion in Limine A. NEC's Contentions 2A and 2B Entergy moves to exclude discussion in NEC's Rebuttal Statement of Position and the Rebuttal Testimony of Joram Hopenfeld of Entergy's positions in proceedings concerning its license renewal Iapplication for the Indian Point plant that 1) it should not be required to provide any information about its CUFen analyses for the NUREG/CR-6260 locations until after the close of the ASLB proceedings, and 2) Staff should accept a commitment to perform these analyses as part of an aging management program under 10 2

CFR § 54.21(c)(1)(iii). 1 Entergy also moves to exclude Exhibit NEC-JH_67, which includes related NRC Staff correspondence filed in the Indian Point docket. This discussion and correspondence are directly relevant to NEC's rebuttal argument concerning the NRC Staff s interpretation of 10 CFR § 54.21 (c)(1). The Staff contends that Entergy can complete the projection of its environmentally-assisted metal fatigue TLAA as part of an aging management plan under § 54.21 (c)(1)(iii), and is not required to include this analysis in its license renewal application under § 54.2 1(c)(1)(ii). NEC is aware of no binding Nuclear Regulatory Commission or federal court precedent on this question of regulatory interpretation. As discussed in NEC's Rebuttal Statement of Position, the Board should therefore consider the plain language and structure of the rule. 'It should also consider the policy implications of the NRC Staff's proposed construction. The discussion and document Entergy would exclude illustrate these policy implications - they make clear that the Staff s interpretation of the rule would permit a license renewal applicant to perform any analysis to project TLAAs to the end-of the period of extended operations under. licensing commitments after the close of any ASLB proceedings. They further illustrate that license renewal applicants are in fact likely to defer TLAA analyses in order to avoid the obligation to release information regarding TLAA methodologies to intervenors. The Board should deny Entergy's motion to exclude this relevant information. B. NEC's Contention 3

1. Hopenfeld Rebuttal Concerning Validity of EPU Stress Load Analysis.

1See, New England Coalition Rebuttal Statement of Position at 6; Rebuttal Testimony of Joram Hopenfeld at A19. 3

Entergy moves to exclude Dr. Joram Hopenfeld's rebuttal testimony at A34 regarding the validity of analytical tools used to estimate stress loads on the steam dryer during the power ascension phase of EPU implementation, on grounds that the validity of

                                                          \1 the analytical tools used during the power ascension phase has been ruled as out of the scope of Contention NEC-3. Dr. Hopenfeld's rebuttal testimony on this subject is directly responsivd-to the following direct testimony of Entergy witness Mr. Hoffman:

The analytical tools that were used during the uprate proceeding to demonstrate that loads on the dryer will be below its endurance limit were performed as part of the design validation process that demonstrated the adequacy of the design and established the current licensing basis.... [T]he loadings on the dryer derive from plant geometries .... Those have not changed since the uprate was implemented, so there has been no change to the loadings on the dryer and the resulting stresses. Therefore, there is no reason to provide continued instrumentation to measure loadings or, further analytical efforts. Joint Declaration of John R. Hoffman and Larry D. Lukens on NEC Contention 3 - Steam Dryer at A63. As discussed in both NEC's Statement of Initial Position and its Rebuttal Statement of Position, NEC acknowledges that the Board has narrowed the scope of NEC's Contention 3 to. exclude the validity of the analytical tools used to estimate stress loads on the steam dryer during EPU implementation. The Board did not, however, make any ruling on the validity of these tools or the adequacy of the EPU stress load analysis as the basis for Entergy's steam dryer aging management program during the period of extended operations. In fact, the Board expressly ruled that this latter issue remains unresolved. In the Matter of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations,Inc. (Vermont Yankee Nuclear Power Station), 64 NRC 131, 189 (September 22, 2006). 4

The Board foreclosed litigation concerning the EPU stress load analysis based on Entergy's representations that its aging management plan would not rely on this analysis or involve use of the same analytical tools used in this analysis. See, Exhibit NEC-, JH_61, Declaration of John R. Hoffman in Support of Entergy's Motion for Summary Disposition of NEC Contention 3 at ¶¶ 23-24. If the Board strikes Dr. Hopenfeld's, rebuttal testimony concerning the validity of the EPU stress load analysis, it should also disregard the multiple statements contained in Entergy and the NRC Staff's Statements of Position and testimony that totally contradict Entergy's representations that were the basis for the Board's decision to foreclose litigation concerning this analysis. See, e.g.' Joint-Declaration of John R. Hoffman and Larry D. Lukens on NEC Contention 3 - Steam Dryer at A63; NRC Staff Initial Statement of Position at 19 (The Staff's position is that stress analysis as a means of estimating and predicting stress loads during operations "is not necessary because the results of the EPU power er ascension program demonstrated that the pressure loads during the EPU operations do not result in stress on the steam dryer that exceed ASME fatigue stress limits.").

2. Hopenfeld Rebuttal Testimony Concerning IGSCC Cracks in the VY Steam Dryer.

Entergy moves to exclude portions of Dr. Hopenfeld's rebuttal testimony concerning the possibility that existing IGSCC cracks in the steam dryer could grow by fatigue and portions of NEC's Rebuttal Statement of Position that discusses this testimony.2 Entergy contends that this testimony is outside the scope of NEC's Contention 3. 2See, NEC Rebuttal Statement of Position at 20; Hopenfeld Rebuttal Testimony at A29 - A3 1. 5

Contention 3 is that Entergy's steam dryer aging management program does not provide reasonable assurance that cyclic loads on the dryer. will not result in hazardous deterioration of the dryer. The deterioration of concern is reasonably interpreted to encompass both new dryer flaws caused by cyclic loads and growth in any existing flaws caused by cyclic loads. Entergy's argument that the Board must ignore the possibility that dryer flaws that are not fatigue-induced could grow by fatigue involves an absurd splitting of hairs. Moreover, Dr. Hopenfeid's testimony is proper rebuttal directly responsive to the following direct testimony of Entergy witness Larry D. Lukens: Q58. Do the results of the most recent dryer inspections shed any light on the long term outlook for the physical integrity of the VY steam dryer? A58. (LDL)' Yes. The most recent steam dryer inspections show that the VY steam dryer has a modest number of IGSCC and stress relief indications typical of its age and service. These inspections show that none of the indications identified to date are active; that is, they exhibit no discernible growth from one inspection to the next. Joint Declaration of John R. Hoffman and Larry D. Lukens on NEC Contentions 3 - Steam Dryer. Entergy also objects to the admission of Exhibit NEC-JH_68 to Dr. Hopenfeld's rebuttal testimony. This document is a copy of Entergy Condition Report CR-VTY-2007-02133 and attached documentation, including an Entergy engineering report stating that "continued growth by fatigue [of IGSCC cracks in the steam dryer] cannot be ruled out.' Again, this document is within the scope of Contention 3 and directly responsive to the above-cited direct testimony of Mr. Lukens. 3A copy of this document was also filed as Exhibit NEC-JH_59 to Dr. Hopenfeld's direct testimony. Due to a clerical error, Exhibit NEC-JH_59 is an incomplete copy of the document. 6

Entergy argues that Exhibit NEC-JH_68 is unreliable evidence because the specific statement Dr. Hopenfeld quotes is contained in a draft version of Entergy's report, and the final version of this report did not include this sentence. The factthat the statement-that "continued growth by fatigue cannot be ruled out" is in a draft version of a report from which it was ultimately omitted does not render the draft report inadmissible evidence. On the contrary, the Board should question Entergy's witnesses about why this statement was included in the draft report, and? the basis for removing it from the final version. C. NEC's Contention 4

1. Testimony of Joram Hopenfeld and Rudolph Hausler

a. Definition of FAC Entergy moves to exclude discussion of whether flow-accelerated corrosion by definition excludes corrosion associated with localized turbulence, in which the rate of corrosion does not vary linearly with velocity. This discussion is contained in the testimony of both Drs. Hopenfeld and Hausler, portions of Dr. Hausler's report, "Flow Assisted Corrosion (FAC) and Flow-Induced Localized Corrosion: Comparison and Discussion," Exhibit NEC-RH_05, and portions of NEC's Rebuttal Statement of Position.4 Entergy's argument that this testimony is outside the scope of Contention 4 or introduces new issues is utterly incorrect. Dr. Hopenfeld's view that the rate of FAC does not always vary linearly with velocity is key to his view that the CHECWORKS model must be recalibrated to EPU operating conditions. Dr. Hopenfeld has raised this 4 NEC Rebuttal Statement of Position at 23-24; Rebuttal Testimony of Dr. Joram Hopenfeld at A45; Hausler Rebuttal Testimony at A6, Exhibit NEC-RH_05 at 1, 6 and 12.

7 K

issue repeatedly throughout these proceedings. He first raised it in his declaration in support of admission of NEC's Contention 4: I questioned the validity of this very contention concerning velocity dependence for the following reason. It is commonly accepted that mass transfer phenomena play an important part in the mechanism of FAC. As such, the mass transfer coefficient would control FAC when the process is not controlled by chemical kinetics. At high turbulence, such as flow around bends and in pipe enlargements, the mass transfer coefficient is proportional to the velocity square and not to the velocity. Second Declaration of Dr. Joram Hopenfeld (June 27, 2006) at ¶ 21. Both Drs. Hopenfeld and Hausler raised this issue in their direct testimony. See, Exhibit NEC-JH_36 at 2-5; Exhibit NEC-RH_03 at 5 ("In the majority of cases a relationship between the corrosion rate, w, and the flow rate, U, can be approximated with an exponential relation"). The continued discussion on rebuttal is in response to the direct testimony of

                                                 /

Entergy witness Dr. Horowitz concerning this subject. See, Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4 - Flow-Accelerated Corrosion at A47-A49.

b. Use of CHECWORKS Code Entergy objects~to discussion included in Dr. Hopenfeld's report, Exhibit NEC-JH_36 at 9-11, concerning industry experience with FAC. The discussion of industry experience is relevant to Dr. Hopenfeld's view that the CHECWORKS model is difficult to use properly because it must be carefully calibrated to plant conditions.

2. Direct Testimony and Exhibits of Ulrich Witte.

Ulrich Witte has reviewed Entergy's records of its flow-accelerated corrosion management program under its current Vermont Yankee operating license and provided direct testimony in support of NEC's Contention 4 that mainly concerns whether this 8

program appropriately implements industry guidance and complies with the Vermont Yankee CLB. Mr. Witte's testimony is within the scope of NEC's Contention 4 both 1) because Entergy has represented that its aging management program addressing flow-accelerated corrosion will be identical to its FAC management program under its current Vermont Yankee operating license; and 2) because Mr. Witte has identified a failure to consistently update the CHECWORKS model with plant inspection data that bears on NEC's claims concerning the time necessary to recalibrate the model to post-EPU operating conditions. Entergy moves to exclude in their entirety 'the Prefiled Direct Testimony of Ulrich Witte Regarding NEC Contention 4, dated April 23, 2008 (Exhibit NEC-UW_01); Mr. Witte's report, "Evaluation of Vermont Yankee Nuclear Power Station License Extension: Proposed Aging Management Program for Flowv Accelerated Corrosion (Exhibit NEC-UW_03); and all other Exhibits cited in Mr. Witte's testimony and report (Exhibits NEC-UW_02 and NEC-UW_04 - NEC-UW_22). Entergy first contends that Mr. Witte does not qualify as an expert on the issues raised by NEC's Contention 4. This argument ignores the majority of Mr. Witte's curriculum vitae. See, Exhibit NEC-UW_02. In fact, Mr. Witte has substantial experience in licensing and regulatory compliance of commercial nuclear facilities, which does qualify him to identify problems in Entergy's implementation of its FAC management program based on a review of program documentation. Mr. Witte has evaluated the compliance of nuclear facilities with regulatory requirements and industry guidance many times before. He characterizes his expertise as "assisting problem plants where therregulator found reason to require the owner to reestablish competence in safely 9

operating the facility in accordance with regulatory requirements." Exhibit NEC-UW_01 at A2. His experience includes six years Ias a Project Manager for Dominion Resources, Inc., Millstone Station, where he developed a successful program to manage implementation of docketed commitments to the NRC, and five years as a manager with the New York Power Authority (NYPA), where he established a program to bring NYPA nuclear facilities into compliance with EPRI guidance and NRC requirements. Id. Entergy and the NRC Staff both challenged Mr. Witte's qualifications when he provided a declaration stating his evaluation of the May 2007 VY steam dryer inspection report. The Board rejected this challenge: [Bloth Entergy and the Staff questioned the qualifications of Mr. Witte, NEC's expert, to interpret and evaluate the May 2007 [steam dryer] inspection report. While Mr. Witte does not appear to have extensive training or experience in analyzing and interpreting inspection results, the Board finds that his background in the areas of configuration management, engineering design control changes, and licensing basis reconstitution provides him with the management-level capability to review results and assess whether there are apparent issues with the data that may raise concerns warranting further investigation and resolution. The Board finds that, based on his training and experience, Mr. Witte can reasonably assist the Board in deciding this case. Memorandum and Order (Ruling on Motion for Summary Disposition of NEC Contention 3)(September 11, 2007) at 13. Entergy next contends that Mr. Witte's entire direct testimony and all associated exhibits should be excluded because some observations of Entergy's FAC management program contained in Mr. Witte's report, "Evaluation of Vermont Yankee Nuclear Power Station License Extension: Proposed Aging Management Program for Flow Accelerated Corrosion" (Exhibit NEC-UW_03), are unsupported. See, Entergy Motion in Limine at 24-25. 10

Mr. Witte's report clearly identifies the basis for his conclusions regarding Entergy's program: it lists all the Entergy documents and NRC and industry guidance for FAC management that he reviewed in preparing it. Exhibit NEC-UW_03 at 10-13. NEC disagrees with Entergy's apparent argument that an expert witness must provide a citation for his every statement. Certainly, the testimony of Entergy's expert witnesses in no, respect satisfies this standard. Mr. Witte has, nonetheless, identified some citation errors in'the copy of his report filed as Exhibit NEC-UW_03. He has also determined that one of his Exhibits, NEC-UW 15, is incomplete; and a second, NEC-UW_20 was printed from a corrupted file. 5 A corrected version of Mr. Witte's report and of his two Exhibits is attached hereto as Attachment A. All corrections to citations are indicated. The following lists Mr. Witte's allegedly unsupported observations, and notes where appropriate references are provided in the corrected version of Mr. Witte's report, Attachment A hereto. a Entergy's most recent FAC inspection was performed under superseded procedures. Mr. Witte cites two documents in support of this observation: Exhibit NEC-UW_ 12, ENN-DC-315, effective March 15, 2006, at 1 ("This procedure supersedes the following site procedures: ... VY-PP7028); and Exhibit NEC-JH_42 at NEC01 7888 (VY Piping FAC Inspection Program PP 7028 - 2007 Refueling Outage (April 3, 2006). See, Attachment A at 20 n. 51, 52. 0 The CHECWORKS model was not updated during a seven-year period. Mr. Witte's references include the following documents: Exhibit NEC-UW_1 0, Condition Report CR-VTY-2005-02239 ("The CHECWORKS predictive models for the Piping 5 Mr. Witte converted this document to a text-searchable format from PDF. The conversion changed the - substance of some of the text. The corrected version of this Exhibit is printed from the PDF file Entergy produced to NEC. 11

FAC Inspection Program were not updated after the 2002 and 2004 refueling outages as required per Appendix D of PP 7028.... Scoping for FAC inspections for RFO 24 and RFO 25 was based on CHECWORKS predicted wear rates from the 2000 and 2001 CHECWORKS model updates."); Exhibit NEC-UW_07 at NEC038424 ("CHECWORKS models and wear data analysis updated with all previous inspections in 3rd quarter 2006"); Exhibit NEC-UW_14 (2/20/2008 e-mail from Beth Sienel to Jonathan Rowley: "I talked to the FAC program owner (Jim Fitzpatrick) and he said the [CHECWORKS] update is in progress.").- Attachment A at 15"n.29, n. 31, n. 32 and 44. 0 From 2000-2006, the VY FAC program used an outdated version of the CHECWORKS software. Mr. Witte cites the following documents: Exhibit NEC-UW_08 at 5-6, Exhibit NEC-UW_20 at NEC037103. See, Attachment A at 17 n. 35. 0 The VYNPS FAC program was deemed unsatisfactory under quality assurance review. Mr. Witte cites the following document in support of this observation: Exhibit NEC-UW_09 at 2, Audit No. QA-8-2004-VY-1 (result summary table states that FAC program is "unsatisfactory."). See, Attachment A at 2 n. 1. 0 "The first page of the CR. includes a statement that this condition had no impact on the RFO 25 inspection scope - i.e., indicating that updating of CHECWORKS was not necessary for establishing scope of RFO 25." Mr. Witte cites the following document: Exhibit NEC-UW-10 at 1, CR-VTY-2005-02239 ("Scoping for FAC inspections for RFO 24 and RFO 25 was based on CHECWORKS predicted wear rates from the 2000 and 2001 CHECWORKS model updates."). See, Attachment A at 19 n. 44. N Ranking of small bore piping was not done. Mr. Witte cites the following document: Exhibit NEC-JH_44 at 18, Focused Self-Assessment Report (10/28*04) ("The 12

susceptibility analysis for small bore piping is complete. However, inspection priorities are not documented.... Without a priority ranking, it is difficult to determine if all the high priority lines have been selected. Ranking for the small bore lines was scheduled for the summer, 2003, but had to be pushed back due to emergent work on the power uprate project."). See, Attachment A at 19 n. 47. Finally, Entergy also takes issue with Mr. Witte's opinion stated at several points in his report that Entergy's failure to consistently update the CHECWORKS model weakened the predictive capability of the software and undermined the effectiveness of the FAC program. Entergy's disagreement is not reason to exclude Mr. Witte's testimony. Mr. Witte has provided the information the Board needs to evaluate his opinions: he has identified both hisqualifications and the information he considered. The Board should consider his testimony. II. Enterwy's Motion in Limine Should be Granted with Respect to One Portion of the Testimony of Ulrich Witte. Entergy has moved to exclude Mr. Witte's testimony that Entergy reduced the number of FAC inspection data points between the 2005 refueling outage and the 2006 refueling outage, Exhibit NEC-UW_03 at 20. Mr. Witte has determined that he relied for this testimony on a corrupted version of the document filed as Exhibit NEC-UW_20. Mr. Witte converted this document to a text-searchable format from a PDF file, and the conversion changed the text of the document. NEC will file a motion to withdraw Mr. Witte's testimony concerning this issue. 13

The Board should deny Entergy's Motion in Limine except with respect to the testimony of Ulrich Witte concerning the reduction of FAC inspection data points between RFO 2005 and RFO 2006, Exhibit NEC-UW_03 at 20. June. 19, 2008 New England Coalition, Inc. by: Andrew Raubvogel6 Karen Tyler SHEMS DUNKIEL KASSEL & SAUNDERS PLLC For the firm Attorneys for NEC 14.

ATTACHMENT A EVALUATION OF VERMONT YANKEE NUCLEAR POWER STATION LICENSE EXTENSION: PROPOSED AGING MANAGEMENT PROGRAM FOR FLOW ACCELERATED CORROSION NEC-UW 03 I. Introduction CORRECTED I submit the following comments in support of the New.England Coalition, Inc.'s REDACTED ("NEC") Contention 4. My comments concern the Applicant's aging management program, specifically addressing the fidelity of the Flow-Accelerated Corrosion ("FAC") Program (NEC Contention 4). NEC asserts that the application for License Renewal submitted by Entergy for Vermont Yankee does not include an adequate plan to monitor and manage aging of plant equipment due to flow-accelerated corrosion ("FAC") during extended plant operation. The Applicant has represented that its FAC'management program during the period of extended operation will be the same as its program under the current operating license,

• and consistent with industry guidance, including EPRI NSAC 202L R.3. The use of the CHECWORKS model is a central element in the Program implementation.

In the Applicant's motion for summary disposition, the Applicant proffered a response that credits the its current program for FAC management at the facility, and simply extends the current program for the renewal period, making the following statement: "furthermore, the FAC program that will be implemented byEntergy is the same program being carried out today, which has not been otherwise challenged by NEC, will meet all regulatory guidance." Ref. Entergy Motion for Summary Disposition on New England Coalition's Contention 4 (Flow Accelerated Corrosion), June 5, 2007, at 3. Italics added. The Applicant has asserted that it is in full compliance with its current licensing basis regarding its FAC program. The Applicant asserts that the plans for monitoring flow

accelerated corrosion, including the FAC Program goal of preclusion includes appropriate procedures or administrative controls to assure that the structural steel integrity of all steel lines containing high-energy fluids is maintained. Id at 6. The applicant is argues, that since the VY FAC program is based on EPRI guidelines and has been in effect since 1990, one could therefore conclude the applicant has established methodology so as to preclude of negative design margin or forestall an actual pipe rupture, and Entergy infers that it is technically adequate and is compliant with its licensing basis requir6ments. I draw a different conclusion. Based on the implemented program presently in place, and the historical inadequacies necessary for effective implementation (including evolution) of the FAC program, the oversights are substantial in program scope, application of modeling software, and finally necessary revisions to the program not implemented as was promised to support the power up-rate. I am not alone in this conclusion. Program weaknesses and failures have been identified by others and form the basis of condition reports, the categorization as unsatisfactory in a Quality Assurance Audit dated November 11, 20041, and noted as "yellow" in a cornerstone roll-up report circa 20062. In addition, the NRC Project Manager made a recent inquiry into indications of an out-of-date program. 3 On Monday, April 21, 2008, I spoke by phone with NRC resident inspector Beth Sienel, and she confirmed that, even now, Entergy has not completed verification of the upgrade of the CHECWORKS model to EPU design conditions. This concern regarding deficiencies in implementation of the program brings Exhibit NEC-UW_9, Audit No.: QA-8-2004-VY-1, "Engineering Programs", page 2, JNEC038514). 2 Exhibit NEC-UW 7, Cornerstone Rollup, Program: Flow Accelerated Corrosion, Quarter: 3rd, dated 10/03/2006, page NEC038424, Open Action Items, (includes All CR-CAs; ER post action items and LO-CAs, is shown as "yellow", however, 6 LO-CAs are shown as open. By definition, "Red" includes 2 or more CR-CAs and /or E/R post action items (excluding LOs action items) greater than one year. 'Exhibit NEC-UW 14. 2

into question the results of FAC inspection during RFO 25 and RFO 26, in which power is as yet not incorporated. up-rate design data apparently These program implementation delays are substantive, and based upon the K information provided to NEC appear to remain unresolved. These deficient conditions raise questions as to the fidelity of the entire license renewal application, Entergy's commitments for license renewal, management oversight, and the efficacy of the I regulatory-required Corrective Action Program. If it is true that power'up-rate parameters such as flow velocity were not incorporated into the FAC program model, these deficiencies appear to be substantive and without question warrant condition reports under the Entergy Corrective Action Program, in particular given that they appear to violate regulatory commitments regarding the Flow Accelerated Corrosion Program. 10 CFR Part 50 Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," provides that a condition that is deficient is requiredto be identified, investigated, andremediated expeditiously. 4 Promises to correct the deficient program at some point in the future are not sufficient, unless all reasonable alternatiye methods for remediation are exhausted and the condition is shown to be safe in the interim. Lack of oversight and a single missed inspectionpoint that remained unnoticed 4 10CFR Part 50, Appendix B, XVI, "Corrective Action," states: "'Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defectiv'e material and equipment, and non-conformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The identification of the significant condition adverse to quality, the cause of the condition, and the corrective action taken shall be documented and reported to appropriate levels of management." 3

for years 5 led the Japanese Mihama Plant FAC pipe rupture in 2004, causing five fatalities.6 As discussed in detail below, Vermont Yankee missed dozens of points. Identification of discrepancies and timely corrective action are the cornerstones of a well-managed plant. In my experience assisting problematic plants, change usually begins with a cultural shift toward proactive corrective action and away from a reactive mentality of delaying needed corrective, actions to programs such as FAC that result in unresolved deficient conditions and unnecessarily narrowed safety margins for longer periods of time than are necessary. A common metric used by the regulator (for example in ROP reviews) and management is the volume of the backlog of open corrective actions and the number of open corrective actions that date further back than one year, two years or even three or more years, to establish the fidelity of the licensee's compliance with the terms of its operating license and associated commitments. The metric is useful in evaluating Flow Accelerated Corrosion management at VermontYankee. II. Summary Assessment Based on a detailed review of the record provided to NEC regarding the Flow-Accelerated Corrosion Program, my conclusion is that the FAC program appears to have been in non-compliance witth its licensing basis from about 1999 through February 2008. The failure to comply is evidenced by the licensee's own 'assessments, audits, and condition reports, roll-up of numerous cornerstone reports, and focused self-assessments. Corrective actions from approximately five Condition Reports ("CR") remained open for Exhibit UW 20, Page 6 of 14 of VY FAC Inspection Program PP7028, 2005 refueling outage at NEC0,37 9.............. - Deleted: 7 I 6 Keyco Orderedto Shut Down 4ihama Reactor. The Japan Times, September 28, 2004, available at htW:,/search.japantimes.co. fv,"member;'mteniber.html?nn20040928a6.htm. 4

                                                                 )

as much as four years. The last condition report regarding FAC, CR,2006-2699, was written on August 30, 2006. Although noted in the cornerstone report dated October of 20067" the condition report apparently was never provided to NEC. The condition report aggregated approximately six corrective actions to the program that had been ignored and the current status was then open and which is presently unknown to NEC.

                                                                                                                              /

In addition, the most recent FAC inspection was performed under superseded procedures and the results therefore are of potentially no programmatic value8 . Procedure ENN-DC-315, was revised and ineffect on March 1, 2006, yet superseded on December 1, 2006 by yet a new program level procedure. Close examination shows that the procedures prepared, approved and implemented by Entergy for implementing the FAC Program were substantially revised, yet were not used in the most recent flow-accelerated corrosion inspections after VY increased operating power by 20 percent in the March, 2006 EPU, nor were they available for RFO 25, the first outage after power up-rate. Required changes, including both a software upgrade and design parameters regarding the substantial plant modification to uprate the plant to 120% power, were not incorporated for either outage, and were in fact still being implemented in February 2008, when Staff inquired on this subject. Exhibit NEC-UW 07 Cornerstone Rollup, Program: Flow Accelerated Corrosion, Program Infrastructure Cornerstone, Quarter: 3rd, dated 10/03/2006, page NEC03419 ("Corrective Action Plan to complete open - --

                                                                                                      -      Deleted: I LO-CA tasks developed 10/02/2006, (CR-2006-02699)"). See also pp. NEC038422, NEC038424.

NEC038426-28-see also footnote 3. 8 Exhibit NEC-IH 42, VYPiping FAC Inspection Program PP 7028- 2007 Refueling Outage, Inspection - - Deleted: UW 20', Location Worksheets/Methods and Reasons for Component Selection," 'April 3, 2006, at 1, NEC017888-

                          - -                      5
                          )

The Feedwater System FAC review was run using 1999 Ultrasonic Test ("UT") data, yet the results were not used in the RFO 24 outage. To be an even marginally predictive modeling tool, the CHECWORKS model Formatted: Highlight should have been kept current for successive outages,

10) that were required to be managed for FAC as far back as Formatted: Highlight 1999. The predictive capability of CHECWORKS was virtually non-existent for the period from 1999 forward. Although Entergy did incorporate the program, which depends heavily on trending of data of multiple outages, they incorporated in one plunge plant design conditions during the 3 rd quarter 2006. The scoping document supporting selection of grid points collected essentially all the sins of the past, including, for example, stale predictive inspection data from the out-of-date version of CHECWORKS, and placed heavy reliance on engineering judgment. As provided under the 2005 scoping document",

i Deleted: I LDeleted:- Exhibit NEC-UW_20, PP7028 Piping FAC Inspection Program, FAC Inspection Records for 2005 "Formatted: Highlight Refueling Outage, undated, NEC037099. Includes on page NEC037104, Inspection Locations and Reasons for component selection, dated 3/1/05. Note on page 2 of 14 of this report, exclusions of inspection scope were based upon cycle predictions from 1999, and did not appear to include Uprate design changes, nor account for the EPRI model not being current. Many recommendations from 1999 were not to reinspect until 2007-or 9 years. This approach appears to be entirely inconsistent with NSAC 202L. Newer examinations 6

the rationale for selection of grid points relied on (1) length of time since the lapsed inspections had ceased to examine a particular inspection point, (2) CHECWORKS User Groups, (CHUG) suspects found at other plants, (3) exclusion of components that were intended to be replaced based upon another regime or degraded condition. Had data from previous FAC inspections routinely been entered into CHECWORKS, the selection of grid points and ranking would have provided a better historical perspective on where to inspect in successive outages, including the most recent outage. With the exception of VY's strength in reactively replacing piping or components with FAC-resistant material during repairs or maintenance, the program itself was not effective as a predictive modeling tool. Simply stated, once something ruptured or was found to be outside its design margin, it was replaced in a reactive management approach. Proactive management of the program to predictfailureshas been inadequate in the FAC Program, as referenced above. Even the most recent inspection completed for RFO 26 appears to have been structured around procedures that were superseded, scoping requirements to establish a new baseline of pipe geometry and as-found wall thickness were based on stale data, and the upper-tiered governing procedure that was used had not been revised since 2001 and 2 was therefore void.' showed an trend of increased frequency of reinspection. See NEC037106. Page 4 of 14 provides for negative margin, or no inspections for Feedwater System. Conclusions called for. "assessing the need" for inspections in 2007 outage. See page NEC037107. The condensation system showed one component with negative time to Trn-in. The Extraction Steam System indicated three components with negative time to code min wall. Page NEC0Q7108. ....... [ Deleted: 7 2 Exhibit NEC-UW- 11, Official Transcript of Proceedings ACRST-3397, Advisory Committee on Reactor Safeguards Subcommittee on Plant License Renewal, June 5, 2007, at page 43. Entergy's Mr. Dreyfuss stated: "... we did increase the number of FAC inspections by 50 percent from what we typically do in outages. We did 63 inspections overall." It is also noted that the average number of points examined by the domestic industry is 82-under a well managed program, without significant changes to the model-such as a power uprate. 7f

The current program-level procedure had been in existence since March 2006. Scoping was performed in May of 2006 under the void procedure, and updating of CHECWORKS was not done until 3rd quarter 2006.13 Grid points, scope selection, and small bore piping susceptibility do not appear to have been ranked under NSAC 202L guidance or in an orderly trending of data by CHECWORKS based upon repeated passes with new grid points and new rankings selected. Data input and passes by CHECWORKS were not accomplished on an outage-by-outage basis."4 With only 63 points examined in RI*O 2615, the baseline forithe power up-rate conditions appears not to have been established. I found it troubling that RFO 26 results were provided to the Advisory Committee on Reactor Safeguards ("ACRS") on June 5, 2007, but apparently were not disclosed to NEC. VY is the first plant modified to achieve Constant Pressure Power Up-rate to 120% power and only one other plant out of the fleet of 104 was licensed to 120% increase in power in one step. Given the uniqueness of the design of VY's power up-rate, CHECWORKS has little industry benchmarking data, and is of marginal use. The history of the one-other up-rated power plant, Clinton Power Station, suggests, the possibility of future problems at Vermont Yankee. The NRC inspected Clinton Power Station, including a review of the FAC program, after its up-rate in January 2003 and found the program to comply with its licensing basis, including NSAC 202L and the use SExhibit NEC-UW 7at EC 824... ............ Deleted: 10 14 Exhibit NECkjQ , VY Piping FAC Inspection Program PP 7028- 200i FAC Inspection Program - .. Deleted: _UW-20 Records for 2005 Refueling Outage atNEC4)37112 -NEC037120. -..- - 'FDeleted: 7 's Exhibit NEC-UW- 11, Official Transcript of Proceedings ACRST-3397, Advisory Committee on Reactor ', Deleted: 9, Safeguards Subcommittee on Plant License Renewal, June 5, 2007, at page 43. Entergy's Mr. Dreyfuss Deleted: 017896 stated: "... we did increase the number of FAC inspections by 50 percent from what we typically do in outages. We did 63 inspections overall." It is also noted that the average number of points examined by the domestic industry is 82-under a well managed program, without significarit changes to the model-such as a power uprate. 8

of CHECWORKS. Program inputs were fully incorporated from previous inspection data and heat balance up-rate data. Wear rates were predicted to increase 8% K because of up-rated power conditions. Although. the increase was a concern to the regulator, the program was found to be adequate. Yet only nine months later, Clinton experienced a FAC rupture' 6 . It is relevant that this failure occurred approximately 16 years after Clinton received its operating license in 1987-while apparently complying with its CLB and the 7 EPRI guidance.' Plant Surry, where a rupture due to FAC killed four people, failed after 15 years of operation, and required 190 component replacements due to FAC. The accident led to unpredicted causal events outside the engineering design basis-including discharge of C0 2, seepage of the heavier than air gas into the control room, requiring reactor operators to don Scott air packs and with some operators exhibiting symptoms such as dizziness because of control room habitability' 8 . Pleasant Prairie, a fossil plant with similar

                                                                                                    '9 conditions, endured a catastrophic FAC failure at 13 years, causing two fatalities' , and a Japanese plant failed without warning, killing five people, simply because of a failure to inspect one component section due to an administrative oversight, repeatedly missed by program owners. 20 The oversight was never noticed during quality control or quality assurance reviews, or spotted by the system engineers responsible for FAC at the plant.

16Exhibit NECJ at 7 (NECO 17894).. Deleted: UW-20 " Exhibit NECUW-04; Exhibit NEC_UW-_,5 at .XI.M --. , - - Deleted: 0 18Exhibit NEC-UW_22 U.S. NRC NUREG 0933; Issue 139: thinning of Carbon Steel Piping in LWRs (Rev. 1)at 1-4. 9 Exhibit NECUW-21, Milwaukee Sentinel, March 9, 1995. 20Exhibit NECUW-20 at NEC037109 - -........................... j Deleted: at 9, NEC017896 9

These plants were not specifically using aging management tools, where as others, such as Clinton, did-but each FAC failure occurred well before the plants reached their engineered end-of-life of 40 years. The event at Mihama occurred due to nothing more than an administrative failure to routinely inspect a known FAC-susceptible component. I fully concur with NEC's consultant Dr. Joram Hopenfeld that comprehensive benchmarking will be required through the number of years when unmanaged FAC failures typically begin to emerge, such as the operational age of the Surry plant at the time of FAC failure, or theClinton Plant failure. III. Licensing basis for management of flow-accelerated corrosion at VY and review of the program implementation I reviewed the FAC program in four parts: Part A, examining the current licensing basis; Part B, the implementation of the licensing basis; Part C, the Licensee's own record of problems with implementation; Part D, my independent observations based on the record provided to NEC, and the requirements for implementing an effective program under NRC-endorsed guidance, with which the Licensee has stated that it has complied. A. The current licensing Basis and the proposed licensing basis for the flow accelerated corrosion program: My review to establish the current licensing basis and the current status of application for license renewal includes the following documents:

1. NUREG 1801 Rev 1, §XI-M 17, Flow Accelerated Corrosion 10

3. CHECWORKS EPRI procedures provided by the Applicant, including fleet procedure EN-DC-315, Rev. 0, "Flow-Accelerated Corrosion Program" effective December 1, 2006.

4. Commitments made by the licensee including the following:22

i. USNR generic letter 89-08, Erosion corrosion -induced pipe wall thinning; ii. Vermont Yankee Letter to USNRC; iii. Vermont Yankee letter to the USNRC, Vermont Yankee Response to NRC Bulletin No. 87-01: Thinning of Pipe Walls in Nuclear Power Plants, dated September 11, 1987; iv. Vermont Yankee letter to the USNRC, Supplement to Vermont Yankee Responseto NRC Bulletin No. 87-01: Thinning of Pipe Walls in Nuclear Power Plants, dated December 24, 1987;

v. USNRC Generic Letter 90-05, Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2 and 3 Piping, dated June 15, 1990; vi. Vermont Yankee letter to the USNRC, request from code relief for use of ASME Code Case N-597, as an alternative to analytical evaluation of wall thinning; vii. USNRC letter to Vermont Yankee, Vermont Yankee Nuclear Power Station-Relief request for use of ASME code case N-597 as an Alternative Analytical Evaluation of wall thinning (TAC No. MB 1530) dated July 27, 2001. NVY 01-74; viii. VY memo: J.F Calchera to OEC (R. McCullough), subject: response to commitment item: ER-990876_01, Reevaluate Feedwater Heater Inspection Program to address Ownership, dated April 25, 2000.

Industry guidance and other records that were used for interpreting VY position regarding license renewal include: ix. Flow accelerated corrosion in power plants TR-106611 RI, published by EPRI in 1999;

x. Official TranscriptAdvisory Committee on Reactor Safeguards subcommittee on Power Uprates November 30, 2005; xi. RAI SPLB-A-1 (LR001576);

xii. Section 12-2 Wear rate analysis (Excerpt from an EPRI report); 22Items i., ii, iii, iv, and viii listed as commitments were not provided to NEC but were only referenced in' Entergy's program level documents, and therefore were not directly reviewed. They do not appear on Entergy's Appendix A, licensee renewal list of commitments, but are listed in program level documents that were valid until March 15, 2006. No evidence of withdrawal, modification, or otherwise changes to these commitments was provided to NEC. 11

xiii. VYNPS License renewal Project Aging Management Program Evaluation j Results. (NEC00113191) B, Implementation of the Flow Accelerated Program in accordance with the CLB. I reviewed the following documents to ensure the implementation of the FAC program in accordance with the CLB: xiv. ENN-DC-315, Rev. 1, "Flow Accelerated Program;" xv. VY-PP7028, Piping Flow Accelerated Corrosion Inspection Program; xvi. VY -PP7028, FAC Inspection program PP 7028- 2007 Refueling outage; xvii. VY -PP7028, piping inspection program, FAC inspection records for 2005 refuelirng outage; xviii. ENN-CS-S-008, rev 0, effective 9/28/2005, pipe wall thinning structural evaluation; xix. DP-0072. K C. Review of Inspection Histories, EPRI Reviews, Quality Assurance Reports, Cornerstone Roll-ups, Focused Self assessments, Condition Reports, and Independent Assessments, and NRC Inspection Reports. In addition, I reviewed inspection histories, condition reports, quality assurance reports, and one cornerstone report rollup on trending in the FAC Program (2003)- through October, 2006), NRC Inspections, and various revisions to VYLRP subsections and revisions. The list included the following: xx. Focused Self Assessment Report, Vermont Yankee Piping Flow

                  'Accelerated Corrosion inspection report, Condition Report LO-VTYLO-2003-0327; xxi. Audit No. QA-8-2004-VY1, Engineering Programs, dated 11/22/2004; xxii. EPRI review of Vermont Yankee Nuclear Power Flow-accelerated corrosion, dated February 28, 2000; xxiii. CR-VTY-2005-02239; xxiv. Cornerstone Rollup update last dated 10/23/2006; 12

)

xxv. VYNPS License Renewal Project Aging management Program Evaluation Results.23 D. Current status of the FAC Program with respect to the licensing basis.

1. The current licensing basis goal is to preclude negative design margin or pipe rupture due to Flow-Accelerated Corrosion and is centered arounduse of EPRI document NSAC 202L. The guidance is specifically endorsed by the NRC under NUREG 1801, which calls for a three prong approach to minimize uncertainties:

(1) Use of a model such as CHECWORKS [with precision in data collection, examination, and frequency]; (2) Use of sound engineering judgment in selecting inspection points that are independent of CHECWORKS; and' (3) Use of industry events that have potential relevance to VY in material condition, design parameters, and operating' history. There are numerous FAC-related failures throughout the industry. Examination of the. OECD Pipe Failure Data Exchange Project (OPDE) database provides that information."4

2. To accomplish the licensing basis goal, the FAC Program needs explicitly to include each of the following ten elements under the specific Generic Aging Lessons Learned (GALL) Report:

I. Scope

2. Preventative actions

3. Parameters monitored or inspected 23These docurments were typically provided to NEC in fragments, with no title page, no document date, no record of whether the documents were current and had superseded others, and no signature or references to the author.

24 Exhibit NEC-Uw_ 15,NucE 597D-Project 1, Data Collection of Pipe Failures occurring in Stainless Steel and Carbon Steel Piping. provides industry wide data on FAC failure. Pag,204.ncludes.a failure rate for BWR.plants. The SDeleted: s probabilistic risk assessment for BWR plant FAC failures is reported as 10E-5 (higher than reactor accident threshold J Deleted: and 30 PRA for Design Basis Accidents). 13

4. Detection of aging effects

5. Trending

6. Acceptance criteria

7. Corrective actions

8. Confirmation processes

9. Administrative processes 25

10. Operating experience

3. Implementation of these ten elements is accomplished under formal program-level procedures. Successful implementation requires actions in sequence that are constructive to yielding the highest predictability of wall thinning and the most certainty in ranking test points for inspection on a routine that collects wear data in a timely fashion, then adjusts the selection scope based upon multiple trending of data, along with incorporation of 26 changes to the plant.

4. _._27 The record indicates that the Vermont Yankee Nuclear Power Station ("VYNPS") FAC program only partially implemented its licensing basis requirements to achieve a successful FAC program and that Entergy was aware of the problematic state of the program for many years. 28 25 Exhibit NEC-UW 06 at 152-157; Exhibit NEC-UW_08 at 2. I' 26 Exhibit NEC-UW 5sat 20, This Exhibit provides inddThtry-wide data on FAC failures. The high rate of ...-[_eleted: 18 failure in BWR plants underscores the need for precision in implementing an FAC program. . T.Deleted: 30 S27 Exhibit NEC- _ 3 .at 3-3.4- .... ... ... .................. Deleted: UW 28 Exhibits NEC-JH-4' at NEC017893-912; Exhibit NEC-UW-09 at NEC038514. NEC038515, Deleted: 16 NEC03 8529, NEC03853 I -8533 Eh NEC-UW t). t8. . .. Deleted: ; Exhibit NEC-UWI6 at 4-1 Deleted: UW-14 14

5. The self-identified deficiencies in Entergy's current VYNPS FAC Program are Formatted: Highlight identified in multiple documents.

29 Entergy apparently ignored the warning. More troubling is that Entergy continued to be in non-compliance with its licensing basis through the years 1999-2006. This deficiency was again noted in late 2004 30 under an internal quality assurance audit, and two Condition Reports were written.

6. Relevant data apparently was not entered into the CHECWORKS model until the third quarter of 2006.31 The October 23, 2006 rollup thus confirms that the model was not kept current during a seven-year period and suggests that susceptible locations may not have been inspected during this time period. This lengthy lapse significantly weakened the trending capability of the software, both during the lapse period and presently. It is also evident that EPU data was still being modeled and validated in 2008 .32 29 Exhibit NEC-UW-08 at 1,4-_(, -[Deleted: 10

• 11; Exhibit NEC-UW-12 3

3o Exhibit NEC-UW-09_at 2_ NEC03853_1-NEC03_8555. *CR- VlY-2004-03062' and *CR-VTY-2004- FDeleted:99 03061." Deleted: letter

                                                      /

3' Exhibit NEC-UW-07 at NEC038424 ("CHECWORKS models and wear data analysis updated with all Formatted: Highlight previous inspections in Formatted: Highlight 3,d quarter 2006."). 32 Exhibit NEC-UW 14, Email from Beth Sienel to Jonathan Rowlev, Feburary 20. 2008, Deleted:; Formatted: Highlight I j

In spite of Entergy's commitment, the required additional susceptibility scoping analysis is not apparent to NEC in information provided.

7. From 1999-2006, the plant was essentially operating in a state in. which component wear was improperly trended and pipe conditions were actually unknown. Reliance on CHECWORKS for this time period for predicting grid points, ranking stisceptible components, and inspecting new points was therefore virtually without technical or empirical value. Without proper trending, the predictability goal of CHECWORKS is lost; it essentially became a data collection repository.

8." During the years 2000-2006, the VYNPS FAC program apparently used an Formatted: Highlight outdated version of the CHECWORKS software. Formatted: Highlight Entergy's failure. to f 34M.~ I ~Exhibit NEC-UW-08,at 5-6: NEC..UXV:20at NEC037 103. - (Deleted: 10 16

update the CHECWORKS model in a timely fashion makes data comparison between operating cycles more difficult.

9. In 2004, at least four VYNPS components, including the condensate system and the extraction steam systems, were determined to have "negative time to Tmin," meaning that wall thi"nning was being predicted as beyond operability limits and should be considered unsafe with potential rupture at anytime. 36 "Negative cycles of operations,"

meaning wall thinning beyond acceptable code limits, were also predicted. The hours negative to the next inspection were substantial-predicting potential code violation or failure could have occurred 3000+ hours previously to October 23, 2006. It is surprising that the Licensee apparently did not write condition reports for this condition. I do not believe that NEC received any notice of Condition Reports relevant to this significant indication by CHECWORKS predicting substantial wall thinning beyond code limits to occur with negative margin of this magnitude. This issue is particularly troubling given that the equipment failure event is unpredictable, and catastrophic when wall thinning is beyond acceptable limits. Despite CHECWORKS' prediction of wall thinning, the plant continued to operate. I have not seen any inspection or audit discussion of this situation. It does, however, appear on the RFO 24 Inspection Plan, 37 oddly with the same number of hours of negative time to Tmin, even with the plan including wear data observed of 30% increase at Quad Cities and Dresden after the up-'rate.38 36 Exhibit NEC-Jt.T.-42.at NECO017893. See also N-EC-UW-20 at NEC037108. . Deleted: UW 7 Exhibit NEC-JH_43- at NEC02018O9. . .Deleted: .- ".[ Deleted: 05 ____ _- 5 31Id. at _ECO)20197. .. Deleted: 41

                                                  -17 N

10. The VYNPS FAC program was deemed unsatisfactory under quality assurance review dated November 22, 2004, and two condition reports were written.39 On page 5,

                                                                                                                    ,(Deleted: "

the report notes the need for program management to ensure ppdate ofgsusceptible piping Deleted: " to be identified and modifications to be incorporated 40 In addition, the report notes that cross-discipline review required by procedure had not been performed .4

11. The 2006 cornerstone report shows a number of indicators as yellow, with lists of open CR corrective actions, and a new CR written in August 30, 2006. 42 The report lists six corrective actions and four CRs that were written as early as 2003 that remain open.43 These include references to a number of progress indicators, but authors of the report continue to express concern over the program and the slow progress to update the CHECWORKS model. I reviewed several of the listed condition reports, some more than four years old, and found no indication that corrective actions recommended in these reports were completed.

12. In addition, in 2005 a sixth CR was written, CR-VTY-2005-02239, stating "CHECWORKS predictive model for Piping FAC inspection program was not updated per appendix D of PP7028.'4 The first page of the CR includes a statement that this*

condition had no impact on the RFO 25 inspection scope - i.e., indicating that updating of CHECWORKS was not necessary for establishing scope of RFO 25. This assertion is 9 Exhibit NEC-UW-42 at 2(NEC0385 14). . .... ........ - Deleted: I I 4' Exhibit NEC-UW-ý9 at 5 (NEC038517).

4. 1 _... .. . . . . . . . . . ... ........ . . ..... . ... . ... .. . . _

Deleted: 9i

                                                                                                                   -  Deleted: Exh~ibit NEC-U W-Jl 4a--------------------------------------

42Exhibit NEC-UW-Q*Z at NEC0.38419, NEC038422....... ............

                                                                                                                  -   Deleted: 9 4' Exhibit NEC-UW-0. at NEC0..38424..

14Exhibit NEC-UW- 1i, atl. Deleted: 3 18

another indicator that the VY FAC program was primafacie in noncompliance with its CLB.

13. A review of a focused self-assessment was performed. This assessment was called for under one corrective action from a condition report LO-VTYLO-2003,00327. The report identifies numerous issues that required or require action to bring the FAG, program into compliance with the CLB. For example, the program susceptibility review report for 2004 was not formal, and did not properly separate scope for ranking. 45 The report was not given an adequate review, nor placed in the document control system.

14. PP7028 n(tes plant modifications and inspection results as not updated since May 15,2000. 46

15. Ranking of small-bore piping was not done. With no ranking, the basis for selection of high susceptibility points for small-bore piping is not evident.47 Procedural conflicts were'identified with missing programmatic requirements.4 8

16. A flow-accelerated corrosion related pipe break associated with a 1" elbow, SSH rd (WO 06-6880), appears to have occurred in 3d quarter 2006. 49

17. Entergy apparently reduced the number of FAC inspection data points between the 2005 refueling outage and the 2006 refueling outage, in violation of its commitment to increase inspection data points by 50%. The 2005 refuelingoutage inspection called for 4' Exhibit NEC-JH 44 at 17.

46 Id. at 18. I 47 Id.at 19.

 '48 Id. at 27-29.

4' Exhibit NEC-UW-0_7 at NEC038428._ ..... .. ...-... -. Deleted: 9 19

137 large-bore inspection points. The 2006 refueling outage inspection, presented to the 50 ACRS 'on June 5, 2007, covered only 63 points.

18. The 2006 refueling outage FAC inspection scope, planning, documentation, and procedural analysis all appear to have been performed under a superseded program document. ENN-DC-315 Rev. 1 was effective March 15, 2006, superseding the PP7028 Piping FAC Inspection Program.51 Yet VY inspection plan for FAC Program PP7028 was approved on May 11, 2006, almost two months after the PP7028 program document was 52 superseded. This error potentially invalidates the baseline requirement of

 ;CHECWORKS, in accordance with NRC-endorsed guidance5 to establish the as-found condition of components and piping.53 The fundamental step of updating inputs is required in the NSAC 202L approach for FAC, and is a required step in the CHECWORKS instructions. Essentially, working to a void procedure makes the results
                                                                                                  - Formatted: Highlight, invalid Given the significant changes to the plant, a baseline pass with accurate inputs was necessary, and subsequent passes were necessary to establish the grid locations and high susceptibility inspection points.

I ExhibitNEC-UW-I I at 4 f Deleted: 4 I s, Exhibit NEC-UW-1g,(ENN-DC-315) at_.; Exhibit NEC-UW_ _9 (PP7028).-----------------------.

                                                                                              ... Deleted: 5.

12 Exhibit NEC-jH.-.42 at NEC017888. ... -.Deleted: 20 Deleted: UW s Exhibit NEC-UW-06 at § XI.M17. Deleted: 05 14 Exhibit NEC-,.IH-at _4-_5 ..

                                                         --------------..                           Deleted: UW-06 20

19. No indication is provided that plant isometrics were updated as required as of 10/22/04."5 IV. Time needed to benchmark CHECWORKS for Post-EPU use at VYNPS I agree with the testimony of Dr. Joram Hopenfeld that CHECWORKS is an empirical model that must be updated with plant-specific data. NUREG 1801 does not specify the number of years' data necessary to benchmark CHECWORKS, but does advise that a baseline must be established as noted above This requirement is reasonable given that'each plant has unique characteristics and operating history. Separate industry guidance supports five to ten years of data trending.5 7 Trending to the high end of the range is appropriate where variables affecting wear rate, such as flow velocity, have significantly changed, as at VYNPS following the 120% power up-rate.

Given the deficiencies in the current VYNPS FAC program discussed in this statement, trending under the program is of marginal value. In addition, substantial "negative margin" conditions were identified in scoping the 2005 FAC inspection-many of which were predicted because of the repeated missed inspections in previous outages (that, significantly, occurred prior to up-rate). 5 Exhibit NEC-JH_44 at 19.

56. Deleted:

                                                                                            .... ... ......... .Deleted:

57 Exhibit NEC-UW-13 at 38 ("In order to establish a baseline for the plant's equipment performance and reliability, the operating history over the past 5 to 10 years is reviewed and trended."). 21 (

I do not agree that a prolonged period of data collection is not necessary to use CHECWORKS effectively at VYNPS after the 120% power up-rate because the predictive algorithms built into CHECWORKS are based on FAC data from many plants. VYNPS is unique in its approach of Constant Pressure Power Up-rate to 120%. Clinton is ,the only other plant to accomplish a one-step up-rate to 120% power and is a very different'plant from VY. To my knowledge, out of 104 operating plants only six have increased operating power by more than 15%.58 Of this group, at least three - Clinton, 59 Dresden, and Quad Cities - appear to have FAC-related issues. The argument that CHECWORKS incorporates relevant industry data is difficult to accept when so few plants are operating under analogous conditions, and 50% of those have experienced FAC related problems. The need to extend the period of data collection is further evidenced by the fact that the CHECWORKS model was not updated with plant-specific changes until after RFO 26. Furthermore, by inference from an inquiry by the Staff project manager to the resident inspectors office only two months ago, it appears the NRC was informed that the EPU up-rate conditions were still being verified and the process was at this late date incomplete after two outages hadpassedsince EPU design was completed, licensed, and implemented. The apparent failure to update the program underscores the lack of benchmarking done to date regarding the CHECWORKS software, and demonstrates troubling failures by Entergy to adhere to their own procedural requirements and failure to honor commitments made to the regulator, for example, made to the ACRS in November Exhibit NEC-UW 18, Union of Concerned Scientists, "Power Uprate History," July 12, 2007. '9 Exhibit NEC-UW 20 at NEC037109 NEC037116: JI 42 at NECO17894 NECO17897. NECO17898: JH 43 at NEC020196 -- Deleted: UW-05 22

2005, regarding use 'ofthe tool and the applicant's intention to conduct benchmarking testing during RFO 25 a6d RFO 26. Based on the foregoing, it is my opinion that seven or more cycles will be necessary to establish a credible benchmarking of CHECWORKS to VYNPS under up-rated operating conditions It is also my opinion that benchmarking can only be accomplished after the current program deficiencies are corrected and a proper baseline is established. 23

NEC-UW_1,5 CORRECTED PENNSTATE Department of Mechanical and Nuclear Engineering (814) 865-2519 College of Engineering Fax: (814) 863-4848 The Pennsylvania State University 137 Rebcr Building University Park. PA 16802-1412 Dr. Brian W. Sheron Associate Director for Project Licensing and Technical Analysis U.S. Nuclear Regulatory Commission MS 05E7 11555 Rockville Pike Rockville, MD 20852-2738

Dear Dr. Sharon:

Enclosed are the results of a project given to my Penn State Graduate Students on finding pipe failure data over a range of pipe sizes and conditions. We specifically looked for stainless steel data as well as carbon steel pipe data. Since the data is from several sources other than nuclear the pipe wall thickness may not always be comparable to reactor pipe wall thicknesses. In some of the reports the students did separate the failure and leakage data by mechanism such that we could then screen the data. J I had the students normalize the data in such a fashion that we could then compare to the break frequency spectrum curves generated by,the NRC experts group. I did talk to Rob Tenoning on the best way of normalizing our data such that we would be consistent with the break frequency plots. The key findings from the students work is that the data, when plotted in the same manner as the break frequency spectrum plots from the NRC experts work, shows a much flatter behavior at the larger pipe sizes indicating a more similar probability level for failure as compared, to a more significant decrease in the failure probability as given by the NRC break frequency spectrum. I am complying all the independent sets of data in a spread sheet and will attempt a further screening. Once complete, I will send you a copy of the data. I wanted you to have these-report now with all the'data so you could make an independent assessment. Please let me know if you need anything else. Very truly yours, L.E. Hochreiter Professor of Nuclear and Mechanical Engineering College of Engineering An Equal Opportunity University

NucE,597D - Project 1 DATA COLLECTION OF PIPE FAILURES OCCURING IN STAINLESS STEEL AND CARBON STEEL PIPING Pennsylvania State University Dr. L.E. Hochreiter April 2005 I - I

N Executive Summary Currently the Nuclear Regulatory Commission (NRC) is contemplating changing the acceptance criteria for Emergency Core Cooling Systems (ECCS) for light-water nuclear power reactors contained in NRC Regulation 10 CFR 50.46. This regulation sets specific numerical acceptance criteria for peak cladding temperature, clad oxidation, total hydrogen generation, and core cooling under loss-of-coolant accident (LOCA) situations. Furthermore, the regulation requires that a spectrum of break sizes and locations be analyzed to determine the most severe case and to ensure the plant design can meet the acceptance criteria under such conditions. Currently the regulation states that breaks of pipes in the reactor coolant pressure boundary up to, and including, a break equivalent in size to the double-ended rupture of the largest pipe in the reactor coolant system must be considered. While this restricts the design, it maintains a large safety margin ensuring the plant-is covered under all LOCA situations. However, an impetus for change has resulted from materials research, analysis, and experience that indicate that the catastrophic rupture of a limiting size pipe at a nuclear power plant is a very low probability event,. If approved, the proposed change would divide the break spectrum into two categories based upon the likelihood of a break. Breaks of higher likelihood, breaks smaller than 10 inches, would need to meet the current requirements set forth in 10 CFR 50.46. Breaks of a lower likelihood, those larger than 10 inches, would only need to meet the requirements of maintaining a coolable geometry and having the capability for long term cooling.. The purpose of this project was to collect data on instances of pipe failures including cracks, leaks, and ruptures. For each instance of failure the plant type, pipe diameter, type of pipe, failure mechanism, and type of failure was recorded. The data was then collapsed based on plant type (PWR or BWR), type of pipe (carbon or stainless steel), pipe size, and failure mechanism. Then, normalized failure frequencies were calculated as a function of both pipe size and failure mechanism per reactor year. Plots of the frequency distributions were generated on a semi-log scale, and the frequency distributions as a function of pipe size were compared to the NRC predicted failure frequencies. For this project our group collected two, independent sets of data. The first set was provided by the OECD Pipe Failure Data Exchange Project (OPDE), with a total of 2891 data points. The second set consists of 67 data points collected by our group from various sources. The two sets of data were not combined due to the lack of information accompanying the data presented in the OPDE database, such as plant name or exact failure size. This made it impossible to identify overlapping coverage and combine the information. Rather, within this report we have analyzed each data set individually in order to make an overall comparison of the trends observed for each data set and the NRC predictions. The results from both the OPDE and the independent sets of data detailed in this report do not support the NRC's assertion that larger sized pipes do not break frequently enough to be used as design criteria. The overall trends of both sets of data show that the frequency of failures does not decrease as sharply with increasing pipe size as the NRC predicts. 2

Table of Contents 1.0 Detailed IntrodUction to the Problem .............................................................................. 6 2.0 Data Collected .............................................................................................................. 8 2.1 OECD Pipe FailureData Exchange Project....................................................... 8 2.2 Independently Collected Data .................................................. ................. 9 3.0 Collapsing and Analyzing the Collected Data .................................................................. 12 4.0 Results and comparisons .................................................................................................. 15 4.1 FailureFrequency as a function ofPipe Size ...................................................... 15 4.2 FailureFrequencyas a function ofFailureMechanism .......................................... 25 5.0 C onclusions .................................................... ........................................................................ 31 6.0 R eferences ............................................................................................................................. 33 Appendix A - OPDE-Light Database Appendix B - Independent Database Appendix C - Collapsed OPDE Data Appendix D - Copies of References

List of Figures Figure 4.1-1. Normalized pipe failure frequencies as a function of pipe group size for both carbon and stainless steel pipe failures in both BWR and PWR plants Figure 4.1-2 Normalized rupture frequencies as a function of pipe group size for both carbon and stainless steel pipe failures in both BWR and PWR plants Figure 4.1-3. Normalized Failure Frequency Distribution for PWRs Figure 4.1-4. Normalized Failure Frequency Distribution for BWRs Figure 4.1-5. Normalized pipe failure frequencies as a function of pipe size for PWRs Figure 4.1-6. Normalized pipe failure frequencies as a function of pipe size for BWRs Figure 4.1-7. Normalized pipe failure frequencies as a function of pipe size for PWRs using the Modified Analysis Method. Figure 4.1-8. Normalized pipe failure frequencies as a function of pipe size for PWRs using the Modified Analysis Method. Figure 4.2-1. Normalized pipe failure frequency as a function of Pipe Group Size for PWVRs Figure 4.2-2. Normalized pipe failure frequency as a function of Pipe Group Size for BWRs Figure 4.3-1. PWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism Figure 4.3-2. BVWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism Figure 4.3-3. PWR and BWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism Figure 4.3-4. Pipe Failure.by Corrosion as a Function of Pipe Size (PWR & BWR) Figure 4.3-5. Pipe Failure by Fatigue as a Function of Pipe Size (PWR & BWR) Figure 4.3-6. Pipe Failure by Mechanical Failures as a Function of Pipe Size (PWR & BWR) Figure 4.3-7. Pipe Failure by Stress Corrosion Cracking as a Function of Pipe Size (PWR & BWR) 4 7.

List of Tables Table 1-1. NRC Total Preliminary BWR a~nd PWR Frequencies Table 2-1. Excerpt from "OPDE-Light" Database Table 2-2. Description of Plant Systems and Type of Piping Table 2-3. Definition of OPDE Pipe Size Groups Table 2-4. OPDE Pipe Failure Definitions Table 3-1. Definition of Pipe Size Groups Table 3-2. Definition of NRC LOCA Groups Table 4.1-1. OPDE Calculated, and NRC Predicted, Normalized Failure Frequencies (l/cal-yrs). Table 4.1-2. Normalized Rupture Frequencies Table 4.1-3. Summary of PWR Pipe Failures from the OPDE Database as of 2-24-05 Tl Table 4.1-4. Summary of BWR Pipe Failures from OPDE Database as of 2-24-05 Table 4.1-6. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method. Table 4.1-7. Summary of BWR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method. Table 4.2-1. OPDE Calculated, NRC Predicted, and Independent Database Calculated, Normalized Failure Frequencies (1/cal-yrs) Table 4.3-1. Failure Frequencies of Pipes for each Failure Mechanism 9 5

1.0 Detailed Introduction of Problem In order to ensure the safety of nuclear plants the cooling performance of the Emergency Core Cooling System (ECCS) must be calculated in accordance with an acceptable evaluation model, and must be calculated for a number of postulated loss-of-coolant accidents (LOCA) resulting from pipe breaks of different sizes, locations, and other properties. This is done to provide sufficient assurance that a plant can handle even the most severe postulated LOCA. LOCA's are hypothetical accidents that would result from the loss of reactor coolant, at a rate in excess of the capability of the rea'ctor coolant makeup system. Currently, the evaluation criteria for these types of accidents state that pipe breaks in the reactor coolant pressure boundary up to and including a break equivalent in size to the double-ended rupture of the largest pipe in the reactor coolant system must be considered. In the case of such an event the NRC has set forth the following criteria that must be met for a design to be considered acceptable [37]:

            ýa. Peak cladding temperature must not exceed 22000 F.

b. Maximum cladding oxidation must not exceed 0.17 times the total cladding thickness before oxidation.

c. Maximum hydrogen generation. The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the

                'metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react.

d. A coolable geometry of ihe core must be maintained.

e. After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core.

While requiring that all plants be analyzed in the case of a double-ended guillotine break of the largest pipe restricts the design, it does maintain a large safety margin ensuring the plant is covered in all pipe break situations. However, an impetus for change has resulted from materials research, analysis, and experience which indicate that the catastrophic rupture of a large pipe at a nuclear power plant is a very low probability event. The hypothesis that is currently being set forth is that small pipes break more frequently than large pipes. The criteria would change so that the NRC would refocus their analysis efforts because they want to make sure that the appropriate amount of time and money are being invested in the areas of most concern. Furthermore, risk analyses indicate that large break LOCA's are not significant contributors to plant risk. According to a presentation given by Dr. Brian Sheron of the NRC at Penn State in the Fall 2004, "using the double ended break of the largest pipe in the reactor coolant system as the design basis for the plant results in ECCS equipment requirements which are inconsistent with risk insights and places an unwarranted emphasis and resource expenditure on low risk 6

contributors. This also places constraints on operations which are unnecessary from a public health and safety perspective." Therefore, the proposed rule change would use the pipe size with the largest break frequency as the design basis for pipe rupture and accident analysis of the plant. A pipe size with a 10 inch diameter is currently being suggested. [37] The proposed change would divide the break spectrum into two categories based upon the likelihood of a break. Breaks of higher likelihood, or those smaller than 10 inches, would need to meet-the current requirements set forth in 10 CFR 50.46. These include criteria (a) through (e) above. On the other hand, breaks of a lower likelihood, or those larger than 10 inches up to and including a double-ended guillotine break of the largest pipe in the reactor coolant system, would only need to meet the requirements of maintaining a coolable geometry and having the capability for long term cooling. Thus, criteria (a), (b), and (c) would be eliminated for these cases. [37] The purpose of this project was to collect data on instances of pipe breaks, leaks, and cracking. These failures included pipe failures from broken pipes either by splits, ruptures, or guillotines, and cracks in pipes, either circumferential or length wise. For each instance found the plant type, pipe diameter, type of pipe, failure mechanism, and type of failure was recorded. Only stainless steel and carbon steel pipes were considered. Then, normalized failure frequency distributions were developed and compared to NRC predictions. The predicted NRC failure frequencies were taken from Table 3 on page 14 of 10 CFR 50.46, LOCA Frequency Development [38). This table is replicated below. Table 1-1. NRC Total Preliminary BWR and PWR Frequencies. Plant Effective Current-Day Estimates (per cal. yr) Typla Break Size 5% Median Mean 95% Type (inches) 5% Median Mean 95% 1/2 3.OE-05 2.2E-04 4.7E-04 1.7E-03 1 7/8 2.2E-06 4.3E-05 1.3E-04 5.0E-04 3 1/4 2.7E-07 5.7E-06 2.4E-05 9.4E-05 7 6.6E-08 1.4E-06 6.OE-06 2.3E-05 18 1.5E-08 I.IE-07 2.2E-06 6.3E-06 41 3.5E-1 I 8.5E-10 2.3E-06 8.6E-09 1/2 7.3E-04 3.7E-03 6.3E-03 2.OE-02 1 7/8 6.9E-06 9.9E-05 2.3E-04 8.5E-04

• 3 1/4 1.6E-07 4.9E-06 1.6E-05 6.2E-05 7 PI.IE-08 6.3E-07 2.3E-06 8.8E-06 18 5.7E-10 7.5E-09 3.9E-08 1.5E-07 41 4.2E-11 1,4E-09 2.3E-08 7.0E-08 7

2.0 Data Collected For this project our group collected two, independent sets of data. The first set was provided by the OECD Pipe Failure Data Exchange Project (OPDE), with a total of 2891 data points. The second set consists of 67 data points collected by our group from various sources listed as references in this report. The two sets of data were not combined due to the lack of-information accompanying the data presented in the OPDE database, such as plant name and exact failure size, which made identifying overlapping coverage impossible. Rather, within this report each data set was individually analyzed in order to make an overall comparison of the trends observed for each data set and the NRC predictions. OECD Pipe FailureData Exchange Project[3] OECD Pipe Failure Data Exchange Project (OPDE) was established in 2002 as an international forum for the exchange of pipe failure information. It is a 3-year project with participants from twelve countries, including Belgium, Canada, Czech Republic, Finland, France, Germany.'Japan, Republic of Korea, Spain, Sweden, Switzerland and the United States. "The objective of OPDE is to establish a well structured, comprehensive database on pipe failure events and to make the database available to project member organizations that provide data." [3] The OPDE database evolved from what existed in the "SLAP database" at the end of 1998,[2]. OPDE covers piping in primary-side and secondary-side process systems, standby safety systems, auxiliary systems, containment systems, support systems and fire protection systems. Furthermore, ASME Code Class 1 through 3 and non-Code piping has been considered. At the end of 2003, the OPDE database included approximately 4,400 records on pipe failure. The database also includes an additional 450 records~on water hammer events where the structural integrity of piping was challenged but did not fail. Access to the actual OPDE database is restricted to organizations providing input data. However, a "OPDE-Light" version of the database will be made available later this year to non-member organizations contracted by a project member to perform work or which pipe failure data is needed. This version will not include proprietary, data, such as the exact pipe diameter, where failure occurred, and preclude any plant identities or dates. Our group was fortunate enough to get a copy of this "light" version of the database for BWR and PWR pipe failures reported as of February 24, 2005. A total of 2891 failures (1536 for PWR plants and 1355 for BWR plants) were provided in this database, and considered for this project. The database listed the plant type, reactor system, apparent cause of failure, pipe size group, number of total failures for each cause and pipe size group, and then a break down of the type of failure within the category. An excerpt from the OPDE-Light database has been provided for clarification in Table 2-1 on the following page. The database, in its entirety, has been included in Appendix A of this report. 8

However, there are a few problems with this database related to the purpose of this project. First, since the database did not-provide the type of pipe (carbon or stainless) for each failure, a reasonable prediction of what type of pipe was involved in the failure based on the'plar't system, which was given, was made. The type of pipe assumed for each system is also given in the following page in Table 2-2. Additionally, as previously mentioned, no explicit pipe diameters were given for each failure due to the proprietary nature of this information. Rather, the failures were collected into group sizes before itwas sent out. A total of six group sizes were utilized by OPDE. The range of pipe diameters that comprise each group is given in Table 2-3. The main problem with these groupings, and the database in general, is that pipes larger than 10 inches in diameter are all grouped together and there is no. way of determining how much larger than 10 inches they actually were. Finally, for the purpose of this analysis any crack, leak, or issue (i.e. wall thinning) with the pipe was considered to be a failure. However, the OPDE database lists the information by type of failure. The definitions of each failure type have been included in Table 2-4. Independently Collected Data[5-36] For the purpose of this project our group collected separate information on instances of piping failures and their causes. The information was collected primarily from Nuclear Regulatory Commission (NRC) bulletins, information notices, event reports, and generic, letters. Our group was able to compile a total of 67 instances of piping failures. This database is provided in Appendix B. While our database is much smaller than the one compiled by the OECD Pipe'Failure Exchange Project, it provides an independent check of the trends observed by that database. A list of references is provided at the end of this report, and some of the actual references, printed from the NRC website, have been included in Appendix D. 9

Table 2-1. Excerpt from "OPDE-Light" Database PLANT PIPE SYSTEM APPARENT CAUSE PIPE SIZE TOTAL NO. Crack- Crack- Deformation Large Leak P/H- Rupture Severance small Wall TYPE TYPE GROUP GROUP OF RECORDS Full Part Leak Leak Leak thinning BWR SS RAS Severe overloading 2 3 1 2 BWR SS RCPB external damage ' 3 1 I BWR SS RCPB Severe Overloading 4 1 I BWR SS SIR Severe overlading 6 1 BWR CS STEAM Water Hammer 6 I I BWR SS RCPB IIF:Wclding Error 3 7 1 - I 1 4 BWR SS RAS TGSCC - Transgranular SCC 2 7 I I 4 BWR SS SIR IGSCC - Intergranular SCC 4 ' 4 1. 2 I BWR SS RAS IGSCC - lntergranular SCC 4 56 I 32 9 1 13 BWR SS SIR 0 1 1 BWR SS RCPB TGSCC - Transgranular SCC I I I BWR SS SIR IGSCC - Intergranular SCC 2 3 1 1 1 BWR SS RCPB Overpressurization 4, 2 1 BWR CS AUXC Vibration-Fatigue 5 1 1 Table 2-2. Description or Plant Systems and Type of Pipi g. Plant Group Representative Plant System Names Type of Piping AUXC Service Water Systems, Raw Water Cooling Systems Carbon CS Containment Spray System Stainless EHC Electro-Hydraulic Control System Carbon EPS Emergency Diesel Generator System Stainless FPS Fire Protection System - Carbon FWC Feedwater & Condensate Systems Stainless IA-SA Instrument Air & Service Air Systems Carbon PCs Power Conversion Systems (incl. Steam Extraction Carbon Lines, Heater Drain Lines, ctc.) RAS Reactor Auxiliary Systems (incl., CVCS, RWCU,. Stainless CCWS, CRD) RCPB Reactor Coolant Pressure Boundary Stainless SG Steam Generator Systems (e.g., S/G Blowdown System) Carbon SIR Safety Injection & Recirculation Systems Stainless STEAM Main Stea m'(from nuclear boiler/steam generator up to Carbon turbine steam admission) C 10

Table 2-3. Definition of OPDE Pipe Size Groups. Corresponding Corresponding Pipe Size Pipe Diameters Pipe Diameters Group (mm) (inches) I DN < 15 DN < 0.6 2 15 < DN < 25 0.6 < DN < 1.0 3 25<DN<50 1.0 < DN < 2.0 4 50 <DN< 100 2.0 <DN <4.0 5 100<DN<250 4.0 < DN < 10.0 6 DN > 250 DN > 10.0 Table 2-4. OPDE Pipe Failure Definitions. Type Description Crack - Part Part through-wall crack (? 10% of wall thickness) Crack - Full Through-wall but no active leakage; leakage may be detected given a plant mode change involving cooldown and depressurization. Wall Thinning Internal pipe wall thinning due to flow accelerated corrosion - FAC Small Leak Leak rate within Technical Specification limits Pinhole Leak Differs and the from "small leak" only in terms of the geometry of the throughwall defect underlying degradation or damage mechanism Large Leak Leak rate in excess of Technical Specification limits but within the makeup capability of safety injection systems Severance IFull circumferential crack - caused by external impact/force, including high-cycle mechanical fatigue - limited to small-diameter piping, typically Large flow rate and major, sudden loss of structural integrity. Invariably caused Rupture by influences of a degradation mechanism (e.g., FAC) in combination with a severe overload condition (e.g., water hammer) ( (

3.0 Collapsing and Analyzing the Collected Data The next important step in this analysis was collapsing the collected information into a usable form by specifying pipe size groups and failure mechanisms. The data was broken into separate bins based on plant type (PWR or BWR), pipe type (carbon or stainless), failure mechanism, and pipe size. Table 3-1 below lists the pipe diameters included in each bin for this analysis. J f- Table 3-1. Definition of Pipe Size Groups. OPDE Pipe Corresponding Pipe Size Groups Diameters (inches) 1+2 0.0-1.0 3 1.0-2.0 4 2.04.0 5 4.0-10.0 6 >10.0 Note: This grouping of piping diameters includes one less bin than used by the OPDE database. Combination of the data from groups 1 and 2 of the OPDE database allowed the bin sizes to correspond more readily with those used by the NRC for listing predicted failure frequencies, taken from page 14 of 10 CFR 50.46, LOCA Frequency Development. The categories used for the NRC predicted failure frequencies are given in Table 3-2. [38] Table 3-2. Definition of NRC LOCA Groups. LOCA Effective Break Category Size (inches) 1 1/2 2 - 17/8 3 3 1/4 4 7 5 18 6 41 It can be seen that for LOCA categories I though 5 the effective break sizes fall within the ranges listed for the pipe size groups, after pipe size groups 1 and 2 from the OPDE database were combined. LOCA category 6 was not considered in this analysis since the OPDE database did not provide specific information for pipes larger than 10 inches. The effect of this on the results will be discussed later in this report. After collapsing the data based on pipe size, the data was then collapsed further by combining some of the failure mechanisms. The following is a list of the failure mechanisms that are used to group the data. Several items have been placed into general categories for simplificaiion purposes. 12

1. Corrosion

2. Flow Accelerated Corrosion (FAC)

3. Microbiological Induced Corrosion (MIC)

4. Erosion

5. Fatigue

a. Thermal Fatigue

b. Vibration Fatigue

6. Human Factors (already combined in the OPDE database)

a. Welding Error

b. Fabrication Error

c. Human Error

7. Mechanical Failures

a. Excessive Vibration ,

b. Overpressurization

c. Overstressed

d. Severe Overloading

8. Stress Corrosion Cracking

9. Water Hammer

10. Miscellaneous

a. Brittle Fracture

b. Cavitation

c. External Damage

d. Fretting

e. Freezing

f. Hot Cracking

g. Hydrogen Embrittlement

h. Unreported After collapsing the data, it needed to be normalized so that failure frequency distributions could be calculated. Failure frequencies were calculated in for carbon steel pipes, stainless steel pipes, and a composite (both carbon and stainless) pipes as a function of both pipe group size and failure mechanism, separately for PWR and BWR plants.

The number of failures in each bin was normalized by dividing by the total number of failures. This gives the fraction of failures for each bin size. For example, when looking at carbon steel pipes in BWRs the number of failures in each pipe group size, regardless of failure mechanism, was divided by the total number of pipe failures (carbon + stainless) in BWRs. Similarly, the number of pipe failures in each failure mechanism bin, regardless of pipe size, was divided by. the total number of pipe failures in BWRs. Then, after normalizing the data, the fractional size in each bin was divided by 3390 calendar years of operation. This gives a failure frequency in 1/calander-years for each bin size. The number 3390 represents the number of reactor years experience in the US (2745 years) as of the end of 2003; divided by an assumed availability factor of 0.81 to get calendar years. 13

The normalization by pipe size (regardless of failure mechanism) and failure mechanism (regardless of pipe size) was repeated for BWR stainless steel failures, BWR composite failures, PWR carbon failures, PWR stainless steel failures, PWR composite failures, total carbon steel failures, total stainless steel failures, and total composite failures for a total of nine situations analyzed and a total of eighteen frequency distributions developed (nine as a function of pipe size and nine as a function of failure mechanism). Finally, the frequency distributions developed were based both on pipe size and failure mechanisms for the different types of pipes had to be plotted against the NRC's predicted frequencies. Semi-log plots of failure frequency as a function of pipe group size were used. OPDEDatabase In order to use this database it had to be collapsed into a more useful form. First, after determining the type of pipe associated with each system, the plant system was no longer taken into consideration. Nextfor the purpose of this project any type of failure (i.e. crack, rupture, wall thinning) was considered to be a pipe failure. Furthermore, as shown above severhal causes of failure were combined together into one failure mechanism, category. The collapsed form of this database is provided in Appendix C. IndependentDatabase There were 67 incidents recorded, which in the end did 'not provide enough data points in each bin to come up with a good normalized frequency distribution. When the data was sorted on plant type, then pipe material and finally on pipe size, various bins of pipe sizes had zero incidents. Appendix B is a listing of all of the incidents which were found.- This listing is sorted on plant type, pipe material, and finally on pipe size. The highlighted incidents throughout the appendix represent incidents for which not enough information was given in the source to include this data in our analysis. Failure m.chanism plots were not made due to the lack of variety in failure mechanisms. The majority of the failure mechanisms were erosion/corrosion and stress corrosion cracking. 14

4.0 Results and Comparisons 4.1 Pipe Failuresas afunction of Pipe Size from OPDEData This section of the report examines the results of pipe failures as a function of pipe size. Normalized failure frequencies for carbon steel, stainless steel, and composite (carbon and stainless) pipes are presented individually for PWRs and BWRs. The NRC has developed their own failure frequencies for PWR and BWR plants as function of pipe size, but does not have ,separate frequencies for carbon and stainless steel pipes. Table 4.1-1 lists the normalized failure frequencies for both PWR and BWR plants, regardless of pipe type, calculated from the OPDE database data and the NRC mean predictions [38]. Table 4.1-1. OPDE Calculated, and NRC Predicted, Normalized Failure Frequencies (l/cal- rs). Plant Pipe Size Groups OPDE Results NRC Predictions Type (inches) 0.0-1.0 1.3E-04 6.3E-03 1.0-2.0 4.4E-05 2.3E-04 PWR 2.0-4.0 2.9E-05 1.6E-05 4.0-10.0 4.6E-05 2.3E-06

                                        > 10.0             4.2E-05                 3.91-08
                              ~~~~~~~~~~~~~~.
                                           ... - ::=**-*"'.*.?.'.:":"...:;"..':"..

V.... ." 0.0-1.0 8.2E-05 4.7E-04 1.0-2.0 2.3E-05 1.32-04 BWR 2.0-4.0 5.6E-05 2AE-05 4.0-10.0 6.2E-05 6.OE-06

                                        > 10.0             7.2E-05                 2.2E-06 Figure 4.1-1 displays this information graphically on a semi-log plot with normalized failure frequencies on the y-axis and the pipe size groups on the x-axis. The figure shows that the results of the OPDE database underestimate the failure frequency for the smaller pipe size groups and overestimate the failure frequency for the larger pipe size groups compared to the NRC predictions for both PWRs and BWVRs. However, there is less disparity in the two BWR predictions than the two PWR predictions.

The NRC predicts that PWR plants are much more likely to have pipe failures in smaller pipes than larger pipes. This trend remains the same in NRC prediction for BWR plants, but is not nearly as drastic. The OPDE results for both PWR and BWR plants show a much more consistent failure frequency both over the range of pipe sizes and between PWR and BWR plants. is

1.OOE.02 ) F An 4 - NRCBWR Prediction 1.00E.04 1.OOE-o5 0 1.00E-06 1.OOE-07 1.00E-08 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (inches) Figure 4.1-1. Normalized pipe failure frequencies as a function of pipe group size for both carbon and stainless steel pipe failures in both BWR and PWR plants. There were three issues in the data analysis that were initially thought to factor into the difference in results between the analyzed OPDE database and the NRC predictions. The first assumption was that all types of cracks, leaks, ruptures, or other issues were considered to be a complete failure in the pipe. In actuality this is not true since inspections or other indicators may catch a crack or leak before a complete failure occurs. As a result, a separate analysis considering only the pipe ruptures listed in, the OPDE database was conducted. However, the calculated frequency distribution considering only ruptures did not change significantly, in either trend or magnitude, from the results obtained when considering all issues to be a failure. The results of this rupture only analysis are shown below in Figure 4.1-2. 16

1.OE-04 CL 1.OE-05 ID. S1.OE-06 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (inches) " Figure 4.1-2 Normalized rupture frequencies as a function of pipe group size for both carbon and stainless steel pipe failures in both BWR and PWR plants. The data for this plot is shown in Table 4.1-2. Table 4.1-2. Normalized Rupture Frequencies. Normalized Plant Pipe Size Instances Failure Type (inches) of Rupture Frequency (I/cal-yrs) 0.0-1.0 - 37 9.8E-05 1.0-2.0 14 3.7E-05 2.0-4.0 10 2.7E-05 4.0-10.0 29 7.7E-05

                                            > 10.0           21          5.6E-05 Total          111 il 0.0-1.0          31          8.2E-05 1.0-2.0          5           1.3E-05 2.0-4.0          6           1.6E-05 4.0-10.0          11          2.9E-05
                                            > 10.0           7           1.9E-05 Total            60-17

The second assumption of concern is the nature of the information contained in the OPDE database. Since the "light" version of the database did not specify the exact pipe size due to the proprietary nature of this information, all pipe failures greater than 10 inches were included in one bin for this analysis. However, for the NRC predictions there are two categories for pipes greater than 10 inches, LOCA categories 5 and 6. As a result, the OPDE calculated failure frequencies for the largest pipe group size would be expected to be larger in magnitude than the NRC's predictions since it covers a wider range of pipe sizes, and thereby a greater fraction of the total when normalized. The final concern is the OPDE database excludes instances of steam generator tube rupture (SGTR) from consideration. By doing this the total number of failures in the smaller pipe size groups is reduced, and the calculated frequencies are lower for the smaller pipe size groups than if SGTR had been considered. The next two plots, Figure 4.1-3 and Figure 4.1-4, present the same data as is included in Figure 4.1-1, but these figures include the ranges for the NRC prediction. It can be seen that even when the range of validity is taken into consideration, a large portion of the distribution still falls outside the boundaries for both PWRs and BWRs. 1.00E+00

                                                                    *'      --- Ar--OPDE Resufts 1.00E-01                                                                     - -NRC Mean i.0E02       X                                                        X NRC 95th Percentle 1.E-02                                                                           NRCMedian
                         *. " ",...~NRC                                                  5th Percentile W* 1.00E     , 1.00E    LL 1.OOE   u. 1.00E-06                                                            .     .-.

x X 1.00E-07 Z 1.OOE-10 0.0-1.0 1.0-20 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (Inches) Figure 4.1-3. Normalized Failure Frequency Distribution for PWRs. 18

1.OOE+00 NRC 5th Percentile 1.00E-03 1.00E.04 - . 0x

                                                       *.--                                        x LL. 1.",E-05                                                                                             -         -     -

u. 1.OOE-06 1.00E-07 1.00E 1.00E-09 1.00E-10 0.01-1.0 .1.01-2.0 2.0-4.0 4.0-10.0 >10.0 Pipe Size (inches)

Figure 4.1-4. Normalized Failure Frequency Distribution for BWRs. Table 4.1-3 and Table 4.1-4 serve as summaries of the information on pipe failure as a function of pipe size and pipe type from the OPDE database for PWRs and BWRs respectively. All the data contained in these tables wvas normalized based on the total number of failures for the given plant type (1355 for BWR and 1536 for PWR). Table 4.1-3. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05 Both Carbon Steel P andd Stainless B oSteel SCarbon Steel Pipes Only Stainless Steel Pipes Only PipeSizeSteel Pipes Pipe Size Normalized Failure Normalized Failure Normalized Failure (inches) Number Number Frequency Number Frequency of Failures Frequency (l/cal-yrs) of Failures Feucy (l/cal-yrs) of Failures Frequeny (l/cal-yrs) 0.0-1.0 698 1.3E-04 154 3.0E-05 544 L.OE-04 1.0-2.0 228 4.4E-05 74 1.4E-05 154 3.OE-05 2.0-4.0 153 2.9E-05 78 1.5E-05 75 1.4E-05 4.0-10.0 238 4.6E-05 126 2.4E-05 112 2.2E-05

  > 10.0              219                   4.2E-05                  93                  1.8E-05                 126                  2.4E-05 Total              1536                      --                   525                    --                  1011 19

Table 4.1-4. Summary of BWR Pipe Failures from the OPDE Database as of 2-24-05 Both Carbon Steel and Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only Pipe Size -_ Steel Pipes (inches) Number Normalized Frqec, Failure Number of rqecFailure Normalized F FrequenrFailure Normalized

• of Failures Frequency Failures Frequency of Failures Frequency of Failures (1/cal-yrs) (1/cal-yrs) (1/cal-yrs) 0.0-1.0 375 8.2E-05 118 2.6E-05 257 5.6E-05 1.0.-2.0 107 I.IE-05 32 7.OE-06 75 1.6E-05 2.0-4.0 259 2.6E-05 32 7.OE-06 227 4.9E-05 4.0-10.0 284 2.9E-05 50 1.IE-05 234 5.1E-05

    > 10.0        330             3.4E-05            39             8.5E-06        291             6.3E-05 Total       1355                  -             271               --          1084                --

There are a few important things to note from these tables. The first is that there have been a similar number of failures reported in BWRs as PWRs (1355 vs. 1536). Second, there were 4 times as many failures of stainless steel pipes as carbon steel pipes in BWRs (1084 vs. 271), and almost two times as many stainless steel failures than carbon steel failures in PWRs (1011 vs. 525). It was not expected to find more stainless steel failures than carbon steel failures. It should also be noted that while the number of stainless steel pipe failures is about the same for both BWRs and PWRs, but nearly twice as many carbon steel failures were observed in PWR plants than BWR plants (525 vs. 271). Figure 4.1-5 and Figure 4.1-6 shows a more detailed representation of failure frequencies as a function of pipe size for PWR plants only, and BWR plants only, respectively. These figures present the separate failure frequency distributions for carbon steel and stainless steel pipes, where the data is normalized based on the total number of failures for each plant type, Figure 4.1-5 shows that failures of stainless steel pipes are more frequent than carbon steel pipes only for smaller pipe sizes in PWRs. Figure 4.1-6 shows that stainless steel pipe failures are much more frequent than carbon steel pipe failures at all pipe sizes in BWRs. As previously mentioned, the data for these two figures (4.1-5 and 4.1-6) was normalized using the methodology explained in the Data Analysis Section, using the total number of failures (carbon + stainless) for each plant type. Conducting the analysis in this manner allows for relative comparisons of failure frequencies to be made between the two types of pipes, however, it does not allow for the failure frequencies to be compared to the NRC predictions. As a result, a second analysis was done where the data was normalized based on the number of failures for a given pipe type in each plant type. In other words, the BWR carbon steel failures would be normalized by the total number of carbon failures in BWRs. The results of this modified analysis are given in-Figure 4.1-7 and 4.1-8 for PWRs and BWRs, respectively. The summary tables, with the recalculated frequencies, have also been included as Table 4.1-5 and Table 4.1-6. It can be seen from these two figures that conducting the analysis in this modified manner collapses the data, meaning that the failure frequencies, based strictly on pipe size, are very similar for carbon and stainless steel pipes in both types of plants. However, the fact remains that stainless pipes are still more likely to fail than carbon pipes in both plant types, based in the relative number of failures for each. More importantly, however, conducting this modified analysis did not show any substantial improvement in matching the data to the NRC predictions. 20

                  //

1.00E-02" * -- C nSte 1.ooE.o3 *I--sa~s te 1.00E-04 Se 1:-, 1.OOE-05 U-. 1.OOE-06 L<7 1.00E 1.00E-08 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0. > 10.0 Pipe Size (inches) Figure 4.1-5. Normalized pipe failure frequencies as a function of pipe size for PWRs. 1.O0E-02 1.00E-03 Carbn Steel

                                                          ,o          "- --Stanle" Stee

- 1.00E-04 , U. 1.O0E-05 1.OOE-07 1.00E-08 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0. > 10.0 Pipe Size (Inches) Figure 4.1-6. Normalized pipe failure frequencies as a function of pipesize for BWRs. 21

1.OE-02 0 Carbon Steel 1.OE-03 Stainless Steel F -)-NR(C PWR Pr~edictjonjý C 1.OE.04

u. 1,OE-05 IL 1,0E-06 1.OE-07 1.OE-08 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0

• 10.0 Pipe SIze (inches)

Figure 4.1-7. Normalized pipe failure frequencies as a function of pipe size for PWRs using the Modified Analysis Method. 1.0E-02 1.OE-03 -4,---Carbn Steel

                                                                    *-+-I-Stainless Steel
                                                                     "')*-*-NRC SWR Predictio I .0E       1.OE-05 0

1.OE-07 1.OE-07 1.0E-08 ... 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (Inches) Figure 4.1-8. Normalized pipe failure frequencies as a function of pipe size for BVRs using the Modified Analysis Method.

7 Table 4.1-5. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method. Both Carbon Steel and Stainless Steel Pipes Carbon Steel Pipes Only Stainless Steel Pipes Only Pipe Size Normalized Failure Normalized Failure Normalized Failure (inches) Number Frequency Nuc Frequency of Failures Feucy (I/cal-yrs) of Failures Frequency (1/lca l-yrs) of Failures (F/cal-yrs) (l/eal-yrs__ 0.0-1.0 698 1.3E-04 154 8.7E-05 544 1.6E-04 1.0-2.0 228 4.4E-05 74 4.2E-05 154 4.5E-05 2.0-4.0 153 2.9E-05 78 4.4E-05 75 2.2E-05 4.0-10.0 238 4.6E-05 126 7.1E-05 112 3.3E-05

  > 10.0      219              4.2E-05            93              5.2E-05           126               3.7E-05 Total      1536                  --            525                 ---           1011 Table 4.1-6. Summary of PVWR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method.

Both Carbon Steel and Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only, Steel Pipes PipeSibe Normalized Failure Normalized Failure Number Normalized Failure (inches) Number Nuqenymber NumberunNormaiedq aiuren of Failures Frequency of Failures Frequency of Failures Frequency (I/cal-yrs) (l/cal-yrs) (I/cal-yrs) 0.0-1.0 698 1.3E-04 154 3.4E-05 544 7.OE-05 1.0-2.0 228 4.4E-05 74 9.3E-06 154 2.0E-05 2.0-4.0 153 2.9E-05 78 9.3E-06 75 6.2E-05 4.0-10.0 238 4.6E-05 126 1.5E-05 112 6.4E-05

 > 10.0      219              4.2E-05             93              1.1E-05           126              7.9E-05 Total      1536                 --             525                 --       1    loll                  --

J

4.2 Pipe Failuresas afunction ofPipe Size from Independent Data The independent database was used primarily to confirm the OPDE database predictions, along with comparing this set of data to the NRC data. Due to the small number of incidents found in this database, some of the pipe group size data groups had values of zero. When plotted on a semi-log scale, similar to the NRC and the OPDE plots, the points do not appear on the plot for that particular pipe size group. This occurs only once for the total normalized frequency plot for BWR data. Table 4.2-1 shows the comparison of the OPDE, NRC and the independent database frequencies. Table 4.2-1. OPDE Calculated, NRC Predicted, and Independent Database Calculated, Normalized Failure Fre uencies (1/cal-yrs). Plant Pipe Size Dat NRC Independent Type (inches) OPDE Prediction Database 0.0-1.0 1.3E-04 6.3E-03 3.6E-05 1.0-2.0 4.4E-05 2.3E-04 3.6E-05 PWR 2.0-4.0 2.9E-05 1.6E-05 9.4E-05 4.0-10.0 4.6E-05 2.3E-06, 2.2E-05

                                > 10.0     4.2E-05      3.9E-08       I.IE-04 0.0-1.0    8.2E-05      4.7E-04       2.3E-05 1.0-2.0    2.3E-05      1.3E-04       0.OE+00 BWR       2.0-4.0    5.6E-05      2.4E-05       3.4E-05 4.0-10.0    6.2E-05      6.0E-06       2.3E-05
                                > 10.0     7.2E-05     2.2E-06        2.2E-04 The Figure 4.2-1 presents the overall normalized frequencies of PWR plants in the United States, and roughly 10 foreign plants for the independent database, the entire OPDE-light, and the NRC mean data given in reports. As seen, the NRC mean values of frequency decrease as the pipe size increases. Although in the two other independent sets of data obtained, the frequencies remain relatively the same throughout the pipe size groups. Pipe sizes which were less than roughly two inches had a lower frequency for the two independent data sets compared to the NRC data, and the pipe sizes above the two to four inches group size show a higher frequency compared to what the NRC's expert elicitation has predicted. This figure shows that the two independent data sources follow similar trends compared to what the NRC's prediction. The PWR frequency shows a vast difference at the higher pipe size groups which in turn contradicts the thinking that larger the pipe size have a smaller break frequency.

22

1.E-02 I.E 0 OPDE result C. U 1.-E.04 -

       " I.E-05         LZ.

o 1.E-06 . 1.E-07 1.E-08 0.0-1,0 tc.0-. 2 "-.0 4.0-10.0 > 10.0 Pipe Size (Inches) Figure 4.2-1. Normalized pipe failure frequency as a function of Pipe Group Size for PWRs. Figure 4.2-2 presents the overall BWR data for the independent data, the OPDE-light, and the NRC data. A similar trend for each data set can be seen in BWR's as in PWR's, except that the frequency range is much smaller for BWR's than PWR's. The independent data provided no pipe failures in the pipe size group of one to two inches, and thus on a log-scale, no data point appears on the figure. Once again the independent data and the OPDE-light data coincide tliroughout the pipe size groups, and contradict the NRC prediction of pipe failure frequencies; except for the range of two to four inches again they are similar. Pipes which are larger than ten inches prove to have a higher frequency in the two independent data sets when compared to that of the NRC data set provided by expert elicitation. 23

i'1.E-03

       .I.E-O L. 1.E-OS
 -       1.E.,07 S.E-08 11E-09, 1.E-10 ..

0.0-1.0 1.0-2.0 2.0.4.0 4.0.10.0 > 10.0 Pipe Size (Inches) Figure 4.2-2. Normalized pipe failure frequency as a function of Pipe Group Size for BWRs. Overall, the two independent data sets, show contradicting trends when compared to the NRC normalized frequencies. IJstfead of the double-ehnded guillotine break being analyzed for every plant for the largest pipe in that plant, the NRC is trying to make the maximum break size which needs to be analyzed ten inches. The reasoning for this is due to low frequency of breaks in pipes of larger diameter than ten inches. This data above shows that the frequency from raw-data does not agree with the current NRC predictions by expert elicitation. There is a high frequency of occurrence in pipe sizes greater than ten inches according to the independent data found. 24

                                     -I

I 4.3 Pipe Failuresas afunction ofFailureMechanism This section of the report summarizes the frequency of failure mechanisms for carbon and stainless steel pipes. The information presented in figures 4.3-1 through 4.3-3 represents the normalized failure frequencies for each failure mechanism. This data is also presented in tabular form in table 4.3-1. The data was collapsed by pipe sizes and broken apart by steel type and plant type. The data was normalized for each type of steel based on the number of reactor years and the total amount of failures (carbon +stainless) for each plant. Table 4.3-1. Failure Fre uencies of Pipes for each Failure Mechanism. Plant Carbon Steel Stainless Steel . Total Failure Type Failure Frequency Failure Frequency Frequency PWR Corrosion 2.04E-05 "5.38E-06 2.57E-05 PWR FAC 2.29E-05 2.32E-05 4.61 E-05 PWR MIC 8.26E-06 1.92E-07 8.45E-06 PWR Erosion 1.84E-05 2.30E-06 2.07E-05 PWR Fatigue 1.77E-05 9.62E-05 1.14E-04 PWR Human Factors 6.91E-06 2.42E-05 3.11E-05 PWR Mechanical Failures 4.23E-06 7.11 E-06 1.13E-05 PWR SCC 9.60E-07 3.25E-05 3.34E-05 PWR Water Hammer O.OOE+00 3.84E-07 3.84E-07 PWR Misc 1.15E-06 2.69E-06 3.84E-06 BWR Corrosion 6.3 1E-06 6.97E-06 1.33E-05 BWR FAC 1.26E-05 1.37E-05 2.63E-05 BWR MIC 1.3 1E-06 2.18E-07 1.52E-06 BWR Erosion 8.71E-06 1.96E-06 1.07E-05 BWR Fatigue 1.55E-05 4.90E-05 6.44E-05 BWR Human Factors 5.22E-06 1.85E-05 2.37E-05 BWR Mechanical Failures 3.92E-06 5.44E-06 - 9.36E-06 BWR SCC 4.14E-06 1.36E-04 1.40E-04 BWR Water Hammer 4.35E-07 2.18E-07 6.53E-07 BWR Misc 8.71E-07 4.14E-06 5.01E-06 25

I~LJ rOon r. *tamess *ceei I 0-- 1! 6.0E-05 S4.OE-05 2.OE-05 0.011+00 , Corrosion FAC MIC Erosion Fatigue Human Mechanical SCC Water Mist

                                      /Factors                                      Failures    .*Hammer Failure Mechanism Figure 4.3-1. PWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism 0

Cr 1.600E-04 LA. 1.0E 1 Carbon Steel 2.ODE.05 I Stainless Steel . 1 .400 -04 113Carbon and Stainless St~ees S1.200E-04 O.ODE+OO B.ODE..05 2.000OE-05. 2! .OooE-O - Corosion FAC MIC Erosion Fatigue Human Mechanical SCC Water Misc Factors Factors Hammer Failure Mechanism Figure 4.3-2. BWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism 26

1..OOOE-04 7.OOCE.05 S6.OOOE-05 0 5.00OE-05 I._ 2.O0OE-05 S1.0OE-05 O.OOOE'OO Corroslon FAC MIC Erosion Fatigue Human Mechanical SCC Water Misc Factors Failures Hammer Failure Mechanism Figure 4.3-3. PWR and BWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism From these plots it was determined that PWR plants are dominated by fatigue failures and BWR plants are dominated by stress corrosion cracking failures. However, in general the most frequent failure mechanisms for both plants are corrosion, fatigue, mechanical factors, and stress corrosion cracking: These four failure mechanismswere analyzed as a function of pipe size in figures 4.3-4 through 4.4-7. For these plots corrosion includes general corrosion, flow accelerated corrosion, and microbiological corrosion. Stress corrosion cracking was not included with corrosion because the pipe failure method for stress corrosion cracking is different than the other corrosion types. Though mechanical failure frequency was not the highest, mechanical failures were chosen because they appear to be independent of pipe type and plant type. Human factors were ignored because they are a factor of quality assurance as opposed to the other failure mechanisms which are primarily a factor of operation. In regards to human factors it is not known if they have decreased with reactor operating experience because the dates of failures was not included with the OPDE data. 27

1.002+00 11.00E-011 i carbon teel - Stainless Stee I Carbon and Stainless Steel 1.OOE.02 Z C, 1.0OE-03 11.00E-04 1.002-05 1 OOE-06 4 5 6 Pipe Size Bin Figure 4.3-4. Pipe Failure by Corrosion as a Function of Pipe Size (PWR & BWR) O' 4, 0. a' 2 3 4 5 6 Pipe Size Bin Figure 4.3-5. Pipe Failure by Fatigue as a Function of Pipe Size (PWR & BNVR) 28

1.OOE+00 11.o11-01

.OOE-02

                                   -- *-Carbon Steel
                                   -w- Stainless Steel I.OOE-03 Carbon and Stainless Steel IA.
    !1.OO12-04 P    S4                  5          6 Pipe Size Bin Figure 4.3-6. Pipe Failure by Mechanical Failures as a Function of Pipe Size (PWR &

BWR) 1.OOE+00 I.OOE-02 - -tils te 1.00E-02 C0 0r E 1.OaE-o5 i.OOE-06 1.OOE-07 I 2 I 3 4 5 6 Pipe Size Bin Figure 4.3-7. Pipe Failure by Stress Corrosion Cracking as a Function of Pipe Size (PWR

                                           &BWR) 29

The frequencies Of Pipe failures by corrosion shown in Figure 4.3-4 are nearly independent of pipe size. With the exception of the smallest of pipe sizes (< 1.0 inches) the frequency of failure for each type of steel is relatively constant. Stainless steel has a lower frequency of failure due to corrosion than carbon steel, which is expected because stainless steel is meant to be corrosion resistant. Figure 4.3-5 shows that carbon steel is less likely to fail by fatigue than stainless steel for all pipe sizes. The figure also shows that as the pipes increase in size they fail less frequently by fatigue. This is more than likely due to greater movement of the pipes as they decrease in size. The amount of force required to fatigue a larger pipe is gr eater than that of a smaller pipe. Figure 4.3-6 supports the information from figure 4.3-3 that shows mechanical failures being relatively equal for all pipe sizes and types. The frequencies of the different pipes in each bin are roughly the same and they stay relatively constant across the spectrum of pipe sizes. The different failures that were grouped into mechanical failures as listed in the section 3.0 are excessive vibration, overpressurization, overstressed, and severe overloading. Though the instances of these failures are low they seem to affect all pipes relatively equally. Stress corrosion cracking appears to be much more prevalent in stainless steel pipes as opposed to carbon steel pipes as shown in Figure 4.3-7. The discontinuity in the carbon steel data is due to plotting a frequency of zero on a log scale. For both stainless and carbon pipes the frequency of failure increases for the largest pipe size (> 10 inches). 30

5.0 Conclusions from Data 5.1 Pipe Failuresas afunction of Pipe Size from OPDE Data

1. The main problem with the OPDE database is it does not have any resolution beyond pipe sizes greater than 10 inches.

2. For both PWRs and BWRs the results of the OPDE database underestimate the failure frequency for the smaller pipe size groups, and overestimate the failure frequency for the larger pipe size groups, compared to the NRC predictions. In both cases the OPDE data does not predict as drastic of a difference in the frequencies for small pipes and large pipes as the NRC does.,

3. The OPDE database excludes instances of steam generator tube rupture (SGTR) from consideration. By doing this the total number of failures in the smaller pipe size groups are reduced, and the calculated frequencies are lower at smaller pipe sizes than if SGTR had been considered. This may be one source of difference in the OPDE results and NRC prediction.

4. The OPDE database reports failures of stainless steel pipes are more frequent than carbon steel pipes for smaller pipe sizes in PWRs and stainless steel pipe failures are much more frequent than carbon steel pipe failures at all pipe sizes in BWRs.

5.2 Pipe Failuresas afunction of Pipe Size from Independent Data

1. The data set collected independently by our group compares very well with the trends observed in the OPDE data, but does not match the results predicted by the NRC.

2. The main problem with this data set is the limited amount of data points.

3. Failure mechanism plots were not made due to the lack of variety in failure mechanisms. The majority of the failure mechanisms were erosion/corrosion and stress corrosion cracking.

5.3 Pipe Failuresas afunction ofFailureMechanism

1. The failure mechanism that appears to dominate PWR plants is fatigue failure, and BWR plants are dominated by stress corrosion cracking failures. In general both plants are limited by corrosion, fatigue, and stress corrosion cracking.

2. For some failure mechanisms the frequency of failure increases as pipe size increases.

Stress corrosion cracking is one failure mechanism where this trend is seen. It should be noted that this does not necessarily contradict the NRC's assertion that larger pipes break less frequently. This conclusion only states that for some failure mechanisms large pipes fail more frequently. 31

3. Although the OPDE data does not show water hammer to be a significant' failure mechanism, it should be noted that the OPDE database listed 450 separate water hammer events where structural pipe integrity was challenged but not failed. Had this data points been included as probable failures, water hammer would have become one of the leading failure mechanisms.

        .JK 32

6.0 References

1) Lydell, Bengt & Mathdt, Eric & Gott, Karen, PIPING SERVICE LIFE EXPERIENCE IN COMMERCIAL NUCLEAR POWER PLANTS: PROGRESS WITH THE OECD PIPE

    - FAILURE DATA EXCHANGE PROJECT, ASME PVP-2004 Conference, La Jolla, California, USA, July 26, 2004.
                                   /

2) Nyman, Ralph & Hegedus, Damir & Tomic, Bojan & Lydell, Bengt, RELIABILITY OF PIPING SYSTEM COMPONENTS - FRAMEWORK FOR ESTIMATING FAILURE PARAMETERS FROM SERVICE DATA, SKI/RA, ENCONET Consulting GesmbH, Sigma-Phase, Inc., December 1997.

3) OPDE Database Light, OECD Piping Failure Data Exchange (OPDE) Proiect, OECD/NEA (2005).

4) Choi, Sun Yeong and Choi, Young Hwan, PIPING FAILURE ANALYSIS FOR THE KOREAN NUCLEAR PIPING INCLUDING THE EFFECT OF IN-SERVICE INSPECTION, KAERI and KINS, 2004.

5) DeYoung, Richard C., NRC - Bulletin No. 82-02: DEGRADATION OF THREADED FASTENERS IN THE REACTOR COOLANT PRESSURE BOUNDARY OF PWR PLANTS, June 2, 1982.

6) Information Notice No. 82-09: CRACKING IN PIPING OF MAKEUP COOLANT LINES AT B&W PLANTS, March 31,1982

7) Jordan, Edward L., Information Notice No. 82-22: FAILURES IN TURBINE EXHAUST LINES, July 9, 1982

8) DeYoung, Richard C., NRC Bulletin N. 83-02: STRESS CORROSION CRACKING IN LARGE-DIAMETER STAINLESS STEEL RECIRCULATION SYSTEM PIPING AT BWR PLANTS, March 4, 1983

9) Jordan, Edward L., Information Notice No. 84-41: IGSCC IN BWR PLANTS, June 1, 1984.

10) Jordan, Edward L., Information Notice No. 85-34: HEAT TRACING CONTRIBUTES TO CORROSION FAILURE OF STAINLESS STEEL PIPING, April 30, 1985.

11) Partlow, James G., Generic Letter 89-08: EROSION/CORROSION-INDUCED PIPE WALL THINNING. May 2, 1989. .

12) Marsh, Ledyard B., Information Notice 99-19: RUPTURE OF THE SHELL SIDE OF A FEED WATER HEATER AT THE POINT BEACH NUCLEAR PLANT, June 23, 1999.

33

13) Roe, Jack W., Information Notice 97-84: RUPTURE IN'EXTRACTION STEAM PIPING AS A RESULT OF FLOW-ACCELERATED CORROSION, December 1f1,1997.

14) Jordan, Edward L., Information Notice 86-106: FEEDWATER LINE BREAK, February 13, 1987.

15) Rossi, Charles E., Information Notice 89-53: RUPTURE OF EXTRACTION STEAM LINE ON HIGH PRESSURE TURBINE, June 13, 1989.

16) Rossi, Charles E., Information Notice 91-18: HIGH-ENERGY PIPING FAILURES CAUSED BY WALL THINNING, March 12, 1991.

17) Grimes, Brian K., Information Notice 95-11: FAILURE OF CONDENSATE PIPING BECAUSE OF EROSION/CORROSION AT A FLOW-STRAIGHTENING DEVICE, February 24, 1995.

18) Weaver, Brian, Event Notification Report 36016: MANUAL REACTOR TRIP DUE TO HEATER-DRAIN LINE BREAK, August 12, 1999.

19) Rossi, Charles E., Information Notice 87-36: SIGNIFICANT UNEXPECTED EROSION OF FEEDWATER LINES. August 4, 1987.

20) Rossi, Charles E., Information Notice 89-07: FAILURES OF SMALL-DIAMETER TUBING IN CONTROL AIR, FUEL OIL, AND LUBE OIL SYSTEMS WHICH RENDER EMERGENCY DIESEL GENERATORS INOPERABLE, January 25, 1989.

21) Rossi, Charles E., Information Notice 88-08: THERMAL STESSES IN PIPING CONNECTED TO REACTOR COOLANT SYSTEMS, April 11,1989.

22) Rossi, Charles E., Information Notice 88-01: SAFETY INJECTIONMPIPE FAILURE, January 27, 1988.

23) Martin, Thomas T., Information Notice 97-19: SAFETY INJECTION SYSTEM WELD FLAW AT SEQUOYAH NUCLEAR POWER PLANT, UNIT 2, April 18, 1997.

24) Slosson, Marylee M., Information Notice 97-46: UNISOLABLE CRACK IN HIGH-PRESSURE INJECTION PIPING, July 9, 1997.

25) Rossi, Charles E., Information Notice 91-05: INTERGRANULAR STRESS CORROSION CRACKING IN PRESSURIZED WATER REACTOR SAFETY INJECTION ACCUMULATOR NOZZLES, January 30,1991.

26) Rossi, Charles E., Information Notice 92-15: FAILURE OF PRIMARY SYSTEM COMPRESSION FITTING, February 24, 1992.

34

27) Grimes, Brian K., Information Notice 93-20: THERMAL FATIGUE CRACKING OF FEEDWATER PIPING TO STEAM GENERATORS, March 24, 1993.

28) Knapp, Malcolm R., Information Notice 94-38: RESULTS OF A SPECIAL NRC INSPECTION AT DRESDEN NUCLEAR POWER STATION UNIT I FOLLOWING A RUPTURE OF SERVICE WATER INSIDE CONTAINMENT, May 27, 1994.

29)NRC Bulletin 74-IOA: FAILURES IN 4--INCH BYPASS PIPING AT DRESDEN-2, 12/17/74.

30) Davis, John G., Information Notice 75-01: THROUGH-WALL CRACKS IN CORE SPRAY PIPING AT DRESDEN-2, January 31, 1975.

31)NRC Bulletin 76-04: CRACKS IN COLD WORKED PIPING AT BWR'S, March 30, 1976.

32) Thompson, Dudley, Circular 76-06: STRESS CORROSION CRACKS IN STAGNANT, LOW PRESSURE STAINLESS PIPING CONTAINING BORIC ACID SOLUTION AT PWVR's, November 22, 1976.

33)NRC Bulletin 79-03: LONGITUDINAL WELD DEFECTS IN ASME SA -312 TYPE 304 STAINLESS STEEL, March 12, 1979.

34) NRC Bulletin 79-13: CRACKING IN FEEDWATER SYSTEM PIPING, June 25, 1979.

35) Moseley, Norman C., Information Notice 79-19: PIPE CRACKS IN STAGNANT BORATED WATER SYSTEMS AT PWR PLANTS, July 17, 1979.

36)NRC Information Notice No. 81-04: CRACKING IN MAIN STEAM LINES, February 27, 1981.

37) Sheron, Dr. Brian, Proposed Modifications to ECCS Analysis.Reguirements, Presentation at Penn State University, September 23, 2004.

38) NRC Document, 10 CFR 50.46 LOCA Frequency Document (Attachment).

35

PIPE SIZE TOTALNO. PLANT TYPEI PIPE TYPE SYSTEM GROUP APPARENT CAUSE Camlabon GROUP OF RECORDS I IkCradc-Parlt IOionrf LeoI Leak Leak P/H-Le 1 Rutue , Smniteak IWai IlminlI PWR t0 PW* AUXC Corroon 2 PWR 10 3 1 3 MWR 3 CS AUXC COnT 6 1I-

                                                                                                                            ----     Is-                     10 5S 2                                                          1-     2 3

AUXC 4 6 3 5 _O PWR 6 6 6 1 __ 2

                                                                           ,f PWR                   AUXC PWR                   wU-XC NF.HuzanEnr                     2               1 PWVR PWR         CS        AUXC                                              6               1 PWR                                                                     2                                                                 I1 PWR
 --PWR        (      -AUXC AUXC                                                            12   t 3                                                  3               6            1 M~R   I                                                                                1 4              2 2

1 PWR CS /

                                                                                      -r 1717 PWR                     CS

[ PWR 8 I 3 I-

                                                                         ~6               I           ~I  --
                                                                                                                                                                                   -~~1 PWR
                                                                                                                                                                                -N 3                                                                   2 FPS                                                            4 FPS                                                            3 FPS                                                            3                                                                  3 MWR       eS           FPS PWR        CS           FPS             HF.HIuman arn                   3
                                                                                                                                            -I PWR                     FPS    UC. M*crtm4ob cay kno.ed Corosion        5 M:,R                                 ~S...~ivaci PWRj       w---               1-     4-

3 3 .I I I 1 1 --, 1 - 1 2 1 4 1 I PWli I a 6 3 CciOSWonalgJ - 4 2 2 Erosjo 1-ss FWVC IL 2 4 I I I PFR I *s 7 FWVC FAC -Fbw AecM*6aled Crofiow 1 4-FWC 27 FWC I 67 FWC 3 FWC FVVC PWVR I rss FWC Ir 2 2 1~~~ FwVC PWR I 83 PWR SS 2 6 1 PVVR I s3 I FWVC I PVVR SS I FWC 23 I 4 2

                                                                      -r-PWR I-  t- I-
                                                                      -F- --

13 i 2 3 2 1 PWR I ss I FVV I Th&malFatue - 8 23 5 5 - 2 PWR _I S FVVC I -3 I 4 -5 -3 2 PVVR I 5s FVVC IAVbrflabwguo 63 4 1 water Ha~mne Waler Hanymi PWR I CS I _ A _ 1 2 1 HFwa~n .f~ HFk.nK me PWR I CS S~voweaverbdng severe merleosdN 01 PWR Cs I LASA 2 6 4 POS Corrosion PCs Eroi~m PWR I CS PCS Erosica, PCs I PCs I I PWR 4 i~ 2

CS ~I ICs P Sever overiosoM 2 1 PCs Therm ealge MNR I C PCs PCs 1 1 2 1 1 ~ _ Pc-s 1 6 4 2 1 PWR ISs 4 RAS I I- Bnre-Fiactre RAS 1 4 1 5 I I I -I PWF I s* 2 2 3 PWR I ss I RAS 4 2 EIosi1o.cavbIoAn 4 2 I I __ I RAS I FAC-FlowAel~erated Coros*on I I I SPWR I £s I RAS I 1 2 1_ 6. 6 . I I 1 PWR I ss Fs 2 1 1 I I PWR I SsI RAS I I I PWR HF.Wei'k Err" 1 3 1 II y h~edC- 2 1 - 1 PWR ] as I PWSCC _ 3 I 7 [

                                                                                                                                              -~4 1        I         I 1    2       1    1            I owj ThermalFeb"u__             1    3__     1    5                                 I I    I  I PWAR I RAS                   vlro-asu              -- 2       1   tO        I7         I                    3 PRI    65   I    RAS   I _      VibraonsIgu~e              1    6       1    4         1         1     1                               -     3 MR        ss     - RCPB               GIA-SCC PWR    I   ss   I   RCPS   I        Corrow-.4sag'o             I                  1 I 63 PWR      ~    RCPBI    ___
                                                                                                        -       I ~     __    I    I  I I

S 3

                                                                 -7 aS I

Pv RCPB _rr HF:De]_gn 3 PWR _ S RCPS HF:WekuAError II RCPB 2 RCPB I PWR _ S RCPB I RCPB 'SCc RCPB 2 RCP8 44 10 Py RCP8 6 5 RCPB 3 2 PWR I Ss RCPB 2, RCPB PWSCC 7 RCPB Severe overbsaN 3 PR I RCPPB Severe oeveroaing PVVR I RCP8 TGSCC. Tre anjar SCC RCPB TGSCC. Týrns* anSýCC 1 4 RCPB TSC. Trargraerar CC PWR I SS RCPB Thermal fatl" 4 RCPB I RCPB PWRA 53 RCPB 1I-ThennaIFatgue C)" . Thermal Falkue. CVC ... PWR - I 6S RCPB V*iab-Feagu 10 1 66 Pm I as PWR I SS TT - SG I - PWR PVWR SG PWR SG PWR SG P51R CS SG PW5R SG 2 2 PWR SG I I PWR SIR BJA-SCC t 1 PWR 3 -2 PW5R 2 PWVR SS SIR 1 3 SS SIR I 3 PW 1 PV py as SIR 1 PV 3 PV 63 SIR 2 4 1 SIR 6 1 1 'V

PWR WRHF.WekVV Effo 1 3 I I I I I I I I I I I PWR I I SIR HF.WeMVg Error I 6 1 1 3 3 PWR ] SS 6SIR IPNR SS$ SIR 4 1 2

• 2 SS 2 3 2 I I I 2

PWVR I SS I SIR I TGSCC - Trwr.amirSOCC PVVR 1 6S 1 SIR I- TGSCC-Tfwngwuscc 6 3 PWVR-T-- _SS I SIR IThernW altgwo a S 2 SS 6 I P.VR 6 PWR 65 0 2 PVWR SS 2 PWVR SS 3 10 .

                  -   SIR  F- -        Vorabofliat5                         9 PVVR                                                                         3                                           3 7

PWR I CS I STEAM I PWR I CS STEAM I I 3 1 9 11 3 PWR I HFHIPwummemo -- 7 - 6 1 -- PVVR I HF.W~inge ror 1 6 1 2 -1 PWVR A Severe o V 6 2 PWR I CS I STEAM 9 I I. I I_-A 6 1 PWR 1 15,41

PIPE SE I TOTALNO. I PLANTTYPE PIPETYPE 1 SYSTEM GROUP _ APPARENT CAUSE GROUP 1 OF RECORDS 1 Caea-Fl Crack-Parl DeformalonI Large Leak

                                                                                                                                       -       T Leak I Pki-Leak I 4

Ru~txe

                                                                                                                                                                         -i- [

Sa-erance I SinaiLleak Il~altwina, I 2 CS AUXc 3 BWR 4 2 3 BWR 6 2 2 ErosOn-aw.talon 3 2 BWR 1

                                                                                                                                                                  -I BWRI          CS     I       AUXC 5    1      9    1                                                       3 8

BWR CS I AUXC 5 BWR A MIC - MfcbcboIcalyInlieadCorrosion 1 -4 2 I- I severe evenlcaan 3 3 severe avebacian 2 severeaOrsdoedng 2 2 BWR I CS I AUXC Unreporw I I CS AUXC

                                                          'vllralt at F;ag',

I Edlbn racezeF~q BWRI SS IC"rtaa System Corrosion I S - I C--- System I L____ Seve. vel&oadnq 11 2 FF.t"u-I BWR 1 6S CS 6 2 BW/R I CS EHC I 2 1 1 BWR I CS EHC , I Viltalton-lal"gue 3 BWR 1ISS 1 EPS 2 I SWR I I I BWR I CS S"evefoverloadrg__ 1 4_ BWR I CS I FPS 3 I I

2 2 2 aWR _ SS FWC I ConToaon 6 1 aWR 6S C 1 1 2 BaWn FVVC Ezo~ aWn_ jSS Erouan~amqtstcx 3 SWR FWC FAC- FbowAceWted Corrosuon 3 3 22 I I FWC FAC-Flow Atcelaodl Caromsi 20 I I BWR SS 6 1 aWRnF S FVC We" &To 5 1 BWR 1 ss1 _ FWC I eovsaoi.d__ BWR FWC Sevwe oIebadcIg 6 ss I 1 FWC SiCC. Sta,-nto i aWR, SS Thw'alFabgse .3 I 3 I I FWC Unreported 6 BWn Iss IS 2 BWR 6S 3 2 BWR 2 t

                     £4.                                                            ¶ I -

L4,SA bg,*-Viahn-Fa.e 2 4 _WR PCs Cofos-on 3 aWR Cs Fkh I FAC.FowAcceratedCofosfo 3 - aWR BWK

K PCs FAC - H~OWAacllertd Crjos.m, HF.We"kn error -I severeovealoactry i BWR I CS I PCs severe Overlodg Thecrmalatal9!, 2 VoUamn4al9.. ~1 6WR I CS I- PCS Vofabon.Iphgue 7 4 3 1 2 Cavial~raslon 1 I BWR I 6S RAS 3 Corrotoo 4 4 6 6 BWH ~S8~ HAS Ccnoson 3 BWR 1581 HAS corotTs~lfalgue 3I I1~ I BWR I 6& RAS 1 2 3 4 BWR I SS I RAS 2r 3 I BWR I SS I RAS 4 6 I 2 1 I 6WlR I SS I RAS I HF.W61tv i I 4- i - it K05CC.- klwdeHninb scc 10C-C.cbv"7muw 6CC aS b- A C0SCC. woga CC iGst=C. "O~rgamaruSCO 1 9g 15CC - k~VsuMrSCC BWR I SS $GSCC- ItergrartAo SCC Severe&,Oradng severe ov's""O. SWR RAS TGSCO. Trw-agaSC 4 BR S I RAS I 2 1 I I BWRI 6S RAS IThermaJ fatgue 5 - WR It fSSJ HAS ~I _ hm __tougeC yckfg 1_ 6 -_ BWR RA.- 1 2 13 7 I 4 1 BWR I S RAS I- Water Hannher I I BWR I S8 I RCPS SWR [I SSPs ICC~ ROb3-dS Ec-ý° EXI EAU Iseklacea SCC I

n BVVR* I & RCPS tk,,4ý; - txl&ý I -~ I RCP8_ 3 1 1 1 - I ,- - I I-BWR BVVR I ISS I RCPS HF:Fo.,Caaon Error 2 I BWR I SS RC8 I I1F:EPAJRMAWNT I III SWR 2 - BWR I S RCPS HF.Weku tror - 1 BWR I SS I RCPB II V- 4 2 I I I I BWR I SS RCPB 4 F-20 T 2 I __ I 1 1~ 2 1 1I BWR I ,S I RCPB I OverpressuAzaon 4 1 I BWVR I 8SS I RCPB F- - 2 1 I I V -- i BWR I SS I RCP8

                                                                                                                                                      ~I     I  I 3      1    1     1 1    3 BWR           6s          1   RCPB 4

8BWR -VSS 3 1 1 - 1 -1 I

                                                          -1                       1          2 BWR                                                     entiIlerackj's  __     I  a     1    4 ECSCC - Extenal ChlorideInrickced SCC     I .I      I     I ECSCC-- Elternal ClNofdeki~k~d SCC 6kl/t(

BWR Erosion nA* 8S I SIR Erosion 5 1 1 T- I - ý I - I 1 4- I --BWR 1 SS Is SIR FAC. FlMe.AceWId C~fro~ic 1 4 1 2 I I I SiR I Fab" 5 1 BWR I I I_ I I~ I I 8WR I as I SIR 2 I I , 2

8WR I SS I SIR II I I BWR I SS I-SR rCsCC- =w4 5CC 6 11C- Wap*~oiuqcaty kxkxed Cor I I BWR I Ovapratkwurflon ow~swaled BWR BWVR SIR I S&,ue o~w"Oa BWR SWR S I SIR I 1 3 3 BWR I SS I SIR I I 21

                       --I              VirbabWalgue I1 B  I  SS   I   SIR  I -- -           Wavo-Ial.

I I I II I -I BWR I CS I 3 1 I I I___I BWR I CS rFAC.FioAcck~etIedCorros.m 1 3 1I FAC - FbowAccerImtod Corrosion I1 STEAl I I I-STEAJ STEAJ STEAM BWR STE" 6 I I

                                                                                                   -I      I 2                        -- 4 BW     I STEAM  IVlab                   Fgue           1 65   1  1 8WR RWR

Appendix B 1 Haddam Neck PWR CS 2.25 4 Erosion GL 89-08 CANDU PWR CS 4 4 Thermal Fatigue Korean CANDU PWR CS 4 4 Thermal Fatigue Korean CANDU PWR CS 4 4 Thermal Fatigue Korean CANDU PWR CS 4 4 Thermal Fatigue Korean Millstone Unit 3 PWR CS 6 5 EroslonlCorrosion IN91-18 Arkansas Nuclear One Unit 2 PWR CS 14 6 Erosion IN89-53 DC Cook Unit 2 PWR CS 16 6 Erosion Bulletin 79-13 DC Cook Unit 2 PWR CS 16 6 Erosion Bulletin 79-13 Fort Calhoun Station PWR CS 12 6 FAC IN97-84 Surry Unit I PWR CS 30 6 Not yet determined IN 81-04 Surry Unit 2 PWR CS 18 6 Erosion/Corrosion IN86-106 Trojan 1 PWR CS 14 6 Erosion IN 87-36 Zion 1 PWR CS 24 6 Human Factor IN 82-25 FR (Framatome Reactors) PWR CS 10, 6 Corrosion Korean / FR (Framatome Reactors) PWR CS 28 6 Corrosion Korean

     .t. Diablo Canyon Unit .:, ...              WR    -CS ,             ,"            ,-.*-: . i ,--Thermal Fatigue ,
  .       -LovisaUnt ..:-. ;              ,.PWR:,          :C :'        -.                           ErosionfCorrosion;:..        .-.IN 91-18*..

t,,Sequoyah.Unft 1,  !,-P.WR' .CS-o* ,A..; -. '!'iThermal Fatigue :-..N 92-20-7.. . .--'..:s!Surry Unit 11 *..  : .. WR-: ,, .xi0CSt: . . Eroslon/Corrosion.7; 'q-N .. 91:18,.:*1: Wolf Creek PWR SS 0.25 1 Vibration IN89-07 KSNP Korean Standard Nuclear Power Plant PWR SS 0.375 1 Thermal Fatigue Korean Oconee Unit 3 PWR SS 0.75 1 Mechanical Failure IN 92-15 WH-3 . PWR SS 0.75 1 Flow Induced Vibration Korean WH-3 PWR SS 0.75 1 Flow Induced Vibration Korean H.B. Robinson Unit 2 PWR SS 2 3 SCC IN 91-05 Oconee Unit 2 PWR SS 2 3 Vibration IN 97-46 Prairie Island Unit 2 PWR SS 2 3 SCC IN 91-05 WH-3 PWR SS 2 3 Flow Induced Vibration Korean WH-3 PWR SS 2 3 Flow Induced Vibration Korean WH-3 PWR SS 2 3 Flow Induced Vibration Korean Crystal River Unit 3 PWR SS 2.5 4 Fatigue IN82-09 Fort Calhoun Station PWR SS 3.5 4 SCC IN82-02 Maine Yankee PWR SS 3.5 4 SCC IN82-02 Maine Yankee PWR SS 3,5 4 SCC IN82-02 Maine Yankee PWR SS 3.5 4 SCC IN82-02 Maine Yankee PWR SS 3.5 4 SCC IN82-02 Maine Yankee PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 SCC IN82-02 Ginna PWR SS 8 5 SCC IE Circular76-06 Foreign PWR SS 8 5 Thermal Stress Bulletin 88-08 Arkansas Nuclear One Unit I PWR SS 10 6 SCC IE Circular76-06 Oconee Unit 2 PWR SS 24 6 Erosion IN82-22 Sequoyah Unit 1 PWR SS 16 6 Fatigue IN95-11 Sequoyah Unit 2 PWR SS 10 6 Human Factor IN97-19 Su/yUnit 2 PW _ SS 10 6 SCC IE Circular76-06 Palo PWR SS.'.. Var,*".- .....-- HumanFacto'r1/2 ,, Bulletin.79-03:

     .," San'OniofreUnit 2--

,'.--.. . i ;.:-PWR,-t .  ? ar '. . - 7',-. -HumanFactor-::i,'5..F, ,"Bulletin,79-. 3. Sa Onfe.ntPWR %A' Sv 4ar '"HumanatrP -,.Bulletin 7M-3"

• TMI .. unit-1 3 'Z,*,-. PWR' .-*,.SS2, <,'. -CC  : ein79 - ,TMlunit

             .            ;,    ':-            .VVR'             .                  ,--                      SCC .            ,,*_.IN 79-19.-.
             .~~T~lunl;1~.~4:f'V           ~PWRT      .". SSIT1     ..                                      SC        b;P    :&;N791-.W

-'Plt unit I= .,.A PWR' '..SS'M - . SCC.

                                                                                                                ..                   IN 9919
      -ZPoint Beac     Unit'.I!                 W              ~              ~             ~       ~          :i~:-         ~       I 991
                                                                                                                                   )1

Appendix B (cont.) Plant Type I.Material Diameter Pipe Size Failure Mechanism Reference Group Dresden Unit 2 BWR CS 4 4 Human Factor Bulletin 74-10 Nine Mile Point Unit 2 BWR CS 8 5 Fatigue Event 36016 Vermont Yankee BWR CS 12 6 SCC IN 82-22 Cooper Station BWR SS 0.25 1 Vibration IN 89-07 Pilgrim, BWR SS 1 2 Corrosion IN 85-34 Browns Ferry 3 BWR SS 4 4 SCC IN 84-41 Browns Ferry 3 BWR SS 4 4 SCC IN 84-41 Nine Mile Point Unit 1 BWR SS 6 5 SCC Bulletin 76;.04 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 'Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Hatch Unit 1 BWR SS 22 6 SCC IN 83-02 Hatch Unit I BWR SS 22 6 SCC IN 83-02 Hatch Unit I BWR SS 22_1 6 SCC IN 83-02 Hatch Unit I BWR SS 22 6 SCC IN 83-02 Hatch Unit I BWR SS 22 6 SCC IN 83-02 Hatch Unit 1 BWR SS 20 6 SCC IN 83-02 Hatch Unit I BWR SS 24 6 SCC IN 83-02 Montecello BWR SS 22 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02

 **,* - . Browns Ferr. 1        7,;.BWR-. .        * '          ,'                   . -                      N I82-24      :.,
           ?';-~ednU~             BW,       ~       '*-{4---;:*    5,-T*A;,/   E'*:.V,"
                                                                                     ,Freezing        ~, i*lN 94-38,*:*-

X.*,;"* iHighiighte~d plantswere :notused in the-dataanalysis due to missinginformatiom-., 'V':

Appendix C. Collapsed OPDE Database Collapsed OPDE Raw Data as function of Pipe Size Pipe Size Group Resulting Number of Failures Plant Type (inches) CS SS CS+SS 0.0-1.0 154 544 698 1.0-2.0 74 154 228 PWR 2.0-4.0 78 75 153 4.0-10.0 126 112 238)

                  > 10.0       93            126           219 Total      525           1011          1536 0.0-1.0     118            257           375 1.0-2.0      32             75           107 BWR             2.0-4.0      32            227           259 4.0-10.0       50            234           284
                  > 10.0       39            291           330 Total      271           1084          1355 0.0-1.0      272            801          1073 1.0-2.0     106            229           335 2.04.0       110            302           412 4.0-10.0      176            346           522
                  > 10.0      132            417           549 Total      796           2095          2891

Collapsed OPDE Raw Data as function of Failure Mechanism Plant Type Failure Mechanism Resulting Number of Failures CS SS CS+SS Corrosion, 106 28 134 FAC 119 121 240 MIC 43 1 44 Erosion 96 12 108 Fatigue 92 501 593 PWR/ Human Factors 36 126 162 Mechanical Failures 22 37 >59 SCC 5 169 174 Water Hammer 0 2 2 Misct 6 14 20 Total 525 101) 1536 Corrosion --29 32 61 FAC 58, 63 121 MIC > 6 1 7 Erosion 40 9 49 Fatigue 71 225 296 BWR Human Factors 24 85 109 Mechanical Failures 18 25 43 SCC 19 624 643 Water Hammer 2 1 3 Misc 4 19 23

             .. Total        271          1084         1355 Corrosion      135           60           195 FAC          177           184          361 MIC           49            2           51 Erosion        136           21           157 Fatigue       163           726          889 PWR+BWR       Human Factors      60-         211           271 Mechanical Failures  40           62           102 SCC           24           793          817 Water Hammer        2            3            5 Misc          10           33           43 Total        796          2095        2891'

Appendix D - References

                -  I I) Lydell, Bengt & Mathet, Eric & Gott, Karen, PIPING SERVICE LIFE EXPERIENCE IN COMMERCIAL NUCLEAR POWER PLANTS: PROGRESS WITH THE OECD PIPE FAILURE DATA EXCHANGE PROJECT, ASME PVP-2004 Conference, La Jolla, California, USA, July 26, 2004.

2) Nyman, Ralph & Hegedus, Damir & Tomic, Bojan & Lydell, Bengt, RELIABILITY OF PIPING SYSTEM COMPONENTS - FRAMEWORK FOR ESTIMATING FAILURE PARAMETERS FROM SERVICE DATA, SKI/RA, ENCONET Consulting GesmbH, Sigma-Phase, Inc., December 1997.

3) OPDE Database Light, OECD Piping Failure Data Exchange (OPDE) Project, OECD/NEA (2005).

4) Choi, Sun Yeong and Choi, Young Hwan, PIPING FAILURE ANALYSIS FOR THE KOREAN NUCLEAR PIPING INCLUDING THE EFFECT OF IN-SERVICE INSPECTION, KAERI and KINS, 2004.

5) DeYoung, Richard C., NRC - Bulletin No. 82-02: DEGRADATION OF THREADED FASTENERS IN THE REACTOR COOLANT PRESSURE BOUNDARY OF PWR PLANTS, June 2, 1982.

6) Information Notice No. 82-09: CRACKING IN PIPING OF MAKEUP COOLANT LINES AT B&W PLANTS, March 31,1982

7) Jordan, Edward L., Information Notice No. 82-22: FAILURES IN TURBINE EXHAUST LINES, July 9, 1982

8) DeYoung, Richard C., NRC Bulletin N. 83-02: STRESS CORROSION CRACKING IN LARGE-DIAMETER STAINLESS STEEL RECIRCULATION SYSTEM PIPING AT BWR PLANTS, March 4,1983

9) Jordan, Edward L., Information Notice No. 84-41: IGSCC IN BWR PLANTS, June 1, 1984.

10) Jordan, Edward L., Information Notice No. 85-34: HEAT TRACING CONTRIBUTES TO CORROSION FAILURE OF STAINLESS STEEL PIPING, April 30, 1985.

11) Partlow, James G., Generic Letter 89-08: EROSION/CORROSION-INDUCED PIPE WALL THINNING. May 2, 1989.

12) Marsh, Ledyard B., Information Notice 99-19: RUPTURE OF THE SHELL SIDE OF A FEEDWATER HEATER AT THE POINT BEACH NUCLEAR PLANT, June 23, 1999.

13) Roe, Jack W., Information Notice 97-84: RUPTURE IN EXTRACTION STEAM PIPING AS A RESULT OF FLOW-ACCELERATED CORROSION, December 11,1997.

14) Jordan, Edward L., Information Notice 86-106: FEEDWATER LINE BREAK, February 13, 1987.

15) Rossi, Charles E., Information Notice 89-53: RUPTURE OF EXTRACTION STEAM LINE ON HIGH PRESSURE TURBINE, June 13, 1989.

16) Rossi, Charles E., Information Notice 91-18: HIGH-ENERGY PIPING FAILURES CAUSED BY WALL THINNING, March 12, 199L.

17) Grimes, Brian K., Information Notice 95-11: FAILURE OF CONDENSATE PIPING BECAUSE OF EROSION/CORROSION AT A FLOW-STRAIGHTENING DEVICE, February 24, 1995.

18) Weaver, Brian, Event NotificationReport 36016: MANUAL REACTOR TRIP DUE TO HEATER DRAIN LINE BREAK, August 12, 1999.

19) Rossi, Charles E., Information Notice 87-36: SIGNIFICANT UNEXPECTED EROSION OF FEEDWATER LINES, August 4, 1987.

20) Rossi, Charles E., Information Notice 89-07: FAILURES OF SMALL-DIAMETER TUBING IN CONTROL AIR, FUEL OIL, AND LUBE OIL SYSTEMS WHICH RENDER EMERGENCY DIESEL GENERATORS INOPERABLE, January 25, 1989.

21) Rossi, Charles E., Information Notice 88-08: THERMAL STESSES IN PIPING CONNECTED TO REACTOR COOLANT SYSTEMS, April 11,1989.

22) Rossi, Charles E., Information Notice 88-01: SAFETY INJECTION PIPE FAILURE, January 27, 1988.

23) Martin, Thomas T., Information Notice 97-19: SAFETY INJECTION SYSTEM WELD FLAW AT SEQUOYAH NUCLEAR POWER PLANT, UNIT 2, April 18,1997.

24) Slosson, Marylee M., Information Notice 97-46: UNISOLABLE CRACK IN HIGH-PRESSURE INJECTION PIPING, July( 9, 1997.

25) Rossi, Charles E., Information Notice 91-05: INTERGRANULARSTRESS CORROSION CRACKING IN PRESSURIZED WATER REACTOR SAFETY INJECTION ACCUMULATOR NOZZLES January30, 1991.

26) Rossi, Charles E., Information Notice 92-15: FAILURE OF PRIMARY SYSTEM COMPRESSION FITTING, February 24, 1992.

27) Grimes, Brian K., Information Notice 93-20: THERMAL FATIGUE CRACKING OF FEEDWATER PIPING TO STEAM GENERATORS, March 24, 1993.

28) Knapp, Malcolm R., Information Notice 94-38: RESULTS OF A SPECIAL NRC INSPECTION AT DRESDEN NUCLEAR POWER STATION UNIT I FOLLOWING A RUPTURE OF SERVICE WATER INSIDE CONTAINMENT, May 27, 1994.

29)NRC Bulletin 74-IOA: FAILURES IN 4--INCH BYPASS PIPING AT DRESDEN-2, 12/17/74.

30) Davis, John G., Information Notice 75-01: THROUGH-WALL CRACKS IN CORE SPRAY PIPING AT DRESDEN-2, January 31, 1975.

31)NRC Bulletin 76-04: CRACKS IN COLD WORKED PIPING AT BWR'S, March 30, 1976.

32) Thompson, Dudley, Circular 76-06: STRESS CORROSION CRACKS IN STAGNANT, LOW PRESSURE STAINLESS PIPING CONTAINING BORIC ACID SOLUTION AT PWR's, November 22, 1976.

33)NRC Bulletin 79-03: LONGITUDINAL WELD DEFECTS IN ASME SA -312 TYPE 304 STAINLESS STEEL, March 12, 1979. 34)NRC Bulletin 79-13: CRACKING IN FEEDWATER SYSTEM PIPING, June 25, 1979.

35) Moseley, Norman C., Information Notice 79-19: PIPE CRACKS IN STAGNANT BORATED WATER SYSTEMS AT PWR PLANTS, July 17, 1979.

36) NRC Information Notice No. 81-04: CRACKING IN MAIN STEAM LINES, February 27, i981.

37) Sheron, Dr. Brian, Proposed Modifications to ECCS Analysis Requirements, Presentation at Penn State University, September 23, 2004.

38)NRC Document, 10 CFR 50.46 LOCA Frequency Document (Attachment). ("

 ..                                                                         NEC-UW.22 CORRECTED PP7028 Piping FACoJnspectior Program FAC INSPECTION PROGRAM RECORDS FOR 2005 REFUELING OUTAGE TABLE OF CONTENTS TAB                                                                               Pages I  'FAG 2004-2005 Program EWC Program Scoping Memo & Level 3 Fragnet              2-5 (4 pages) 2    2005 Refueling Outage Inspection Location Worksheeis /                      6-19 Methods and Reasons for Component Selection (14 pages) 3    VYM 2'004/007a Design Engineering - M/S Memo: J.C.Fitzpatrick to           20-37 S.D.Goodwin subject, Piping FAC Inspection Scope for the 2005 Refueling Outage (Revision 1a), dated 5/5/05. (18 pages) 4    VYPPF 7102.01 VY Scope Management Review Form for deletion of FAC          38-43 Large Bore Inspection Nos. 2005-24 through 2005-35 from RF025, dated 11/1/06 (6 pages)

N 5 2005 RFO FAC Piping Inspections Scope Challenge Meeting Presentation, 44 -46 5/4/05 (3 pages) 6 ENN Engineering Standard Review and Approval Form fromn VY for: "Flow 47-48 Accelerated Corrosion Component Scanning and Gridding Standard",

     ,ENN-EP-S-005, Rev. 0. dated 9/22/05 (2 pages) 7    ENN Engineering Standard Review and Approval Form from VY for; "Pipe       49-50 Wall Thinning Structural Evaluation" ENN-CS-S-008, Rev. 0. dated 9122/05 & VY Email: Communication of -Approved Engineering Standard date 9/27/05 ( 2 pages) 8   EN-DC-1 47 Engineering Report No. VY-RPT-06-00002, Rev.0, "VY Piping        51 -69 Flow Accelerated Corrosion Inspection Program (PP 7028) - 2005 Refueling Outage Inspection Report (RFQ25 - Fall 2005) (19 pages) 9   Large Bore Component Inspections: Index and Evaluation Worksheets          70 - 327 (258 pages) 10   Small Bore Component Inspections: Index and Evaluation Worksheets         328 - 347 (20 pages)

Page 1 of 347 NEC037099

ENN Nuclear Management Manual Non QA Administrative Procedure I ENN-DC-183 Rev.1 Facsimile of Attachment 9.10 Program or Component Scoping Memorandum, 2004-2005 Program Scope Memro Vermont Yankee - Engineering Department WBS Element: FAC Inspection Program Proiect Number:]

Title:

Piping Flow Accelerated Corrosion (FAC) Inspection Program 2004 & 2005 Program Related Efforts; rtment: DesignEngineering--Mechanical i Structural Owner: Sames Fitzpatrick Backup: Thomas O'Connor Procedure No. PP 7028**, Vermont Yankee Piping Flow Accelerated Corrosion

Title:

lnspectionProgram Detailed Scope of Project (Explanation): Engineering activities to support ongoing Inspection Program to provide a systematic approach to insure that Flow Accelerated Corrosion (FAG) does not lead to degradation of plant piping systems. Currently** Program Procedure PP 7028 controls engineering and inspection activities to predict, detect, monitor, and evaluate pipe wall thinning due to FAC. Activities include modeling of plant piping using the EPRI CHECWORKS code to predict susceptibility to FAG damage, selection of components for inspection, UT inspections of piping components, evaluation of data, trending, monitoring of industry events and best practices, participation in industry groups, and recommending future repairs and /or replacements prior to component failure. Expected to adopt a new ENN Standard Program Procedure ENN-DC-315 (which is currently under development with an accelerated development date of 6W30/04). Expected Benefits (Justificationl: VY committed to have an effective piping FAC inspection program in response to GL 89-08. Consequences of Deferral: Possible hazards to plant personnel, Loss of plant availability, unscheduled repairs, and deViation from previous regulatory commitments. Duration of Prograrm: Life of plant 2004 Key Deliverables, or Milestones: Completion Estimate 'Complete Focused SA write up & generate appropriate corrective 6/18/04 actions (coordinate activities with program standardization efforts. Completion of RFO 24,documentation, write and issue RFO 2004 7/23104 jp n RjoQeport ___ ___ ______ Software QA on XP platform for CHECWORKS FAC module Version 8/13/04 1.OG Issue 2005 RFO Outage Inspection Scope. Including Scoping 9/1/04 worksheets. Update Piping FAC susceptibility screening to account for piping and 8/13104 drawing updates- Include effects from NMWC, power uprate, & life extension. Update piping Small Bore piping database and deyetop new priority 10/01/04 logic for inspection scheduling, Page I of 2 I () 4A-NEC037100

ENN Nuclear Management Manual Non GA Administrative Procedure ENN-DC-183 Rev.1 Facsimile of Attachment 9.10 Program or Component Scoping Memorandum 2004 Key Deliverables or Milestones: - continued Completion Estimate Update CHEOWORKS models using Versibn 1.OG with latest 2002 12/31/04 RFO & 2004 RFO Inspection data (Note ideally results are to be used in determining the 2005 inspection scope, however schedule milestones override po rq9_acm loqic.. Adoption of ENN--DC-31 5 ENN Standard FAC program 10/31/04 Procedure to include all previous improvements identified Self Assessments. Ongaing Program Maintenance. Includes: procedure revisions, 12/31/04 program improvements, benchmarking, attendance at industry (EPRI CHUG) meetings, evaluation of industry events (industry awareness) for effects on VY, license renewal project input, and fleet support. ..... 2005 Key Deliverables or Milestones, Perform Prqgram Self Assessment (minimumonceper-cycle) . 4/1/05 Conversion of CHECHWORKSIOG models to SFA Version 2.1x 9/1/05 RFO 25 support 11/15/05 Completion of RFO 25 documentation, develop RFO 25 Outage 12/31/05 Enspection Report - Ongoing Program Maintenance. Includes: procedure revisions, 12131/05 program-improvements, benchmarking, attendance at industry (EPRI CHUG) meetings, evaluation of industry events (industry awareness) for effects on VY, and fleet support. 2006 Key Deliverables or Milestones: Issue 2005 Outage Inspection Report 1115106 Update SFA Predictive Models with 2005 RFO data. 4/15/06 Ongoing Program Maintenance. Includes: procedure revisions. 12/31/06 program improvements, benchmarking, attendance at industry (EPRI CHUG) meetings, evaluation of industry events (industry awareness) for effects on VY, and fleet support. Estimated Budget or Expenses: Amount/Hrs Captured in DE Mechi1Structural Base Budqet N/A Others Impacted By Project, ........ Estimated Hours System Engineering -_--- 40 _Engineering Support Reactor Engineering Design Engineering - - - - - - -

        ,;Fluid Systems Engineering                                       40 Electrical / I&C Engineering Mecharnical / Strucburat Design Level 3 Fragnet: (Attached)                                          --------------------------------

Performance Indicators for FAC Program are contained in the Program Health Report (Attached) Page 2 of 2 NEC037101

2004-2005 Piping FAC Inspe in Program Level 3 Fragnet YEAR 2004 (2 "d half) (Time Line from 6/01/04 to I2131/04) Preparer Reviewer TOTAL - Est. Es. Delivery Task No, Task Description (HRS) (HRS) (HRS) Start I Completion Estimated Estimated. Estimated. Date Complete Focused SA write up &generate appropriate correctve 04-1 actions (cobrdinate activlties vAth program standardization 20 10 30 611104 6/18/04 efforts). Completion of RFO 24 documentation, write and issue RFO 20040 04-2 Inspection Report 60 30 *" "90 6/11404 71"23104 Software OA on XP platform fdr CHEGWORKS.FAC module 04-3 Version 1.0G 20 10 30 71/104 8/1 3104 Update Piping FAC susceptibility screening to accournt for piping 04-4 and drawing updates. Include effects from NMWC, power uprate, 40 20 60 7/12104 8113104 a life extension. Update piping Small bore piping database and develop new 04-6 pfio6ty logic for inspection -scheduling. 40 20 60 916104 10/01104 04-6 Update CHEOWORKS models using Version 1.0G with lates't 2002 RFC &2004 RFO Inspection data "60 80 240 8/23/04 12131/04 Issue 2005 RF Outage inspection Scope. Including Scoping 04-7 worksheets. 40 20 60 812104 _\ 9/11/04 04-S Devetopmentfadoption of ENN-DC,-315 ENN Standard FAC program Procedure to inlude all 80 40 120 6/2304 10/31104 previous improvements identified Self Assessments. ______ 04-9 Ongoing Program Mainternarce. Includes: procedure revisions, 160 40 200 (51104 12/31/04 program improvements, benchmaTking, attendance at industry (EPRI CHUG) meetings, evaluation 6f industry events (industry a...a% reness) for effects on VY, LR.project input, and fleet support. .......... . . ...... ..... TOTAL (From end of RFO 24 to December 31, 2004) 620 270 890 HRS Page1 of 2 NEC037102 C

2004-2005 Piping FAC Inspe. on Program Level 3 Fragnet YEAR 2005 (111/05 TO 12/31/05) Preparer Reviewer TOTAL Est. EM. Task No. Task De~scrlptkon (HRS) (HRS) (HRS} - Start Delivery Estimated Estimated, Estimated. Completion Date Perform Program Self Assessmert (minimum once per cycle), 05-1 40 20 60 3/1/05 4/01105 - Conversion of CHECHWORKS 1.IG models to SFA Version 2.1x 05-2 360 180 540 4/1/06 9f01/05 RFO 25 Preparation &Outage Support 05-3 160 80 240 9/1/05 11/15/0504 05-4 Completion of RFD 25 documentation, develop RFO 25 Outage Inspection Report 60 30 90 11/15/05 12/31/05 05-5 Ongoing Program Mainteriance. Itcludes: procedure revisions, program improvements, benchmaridng, attendance at industry -40 20 60 1/01/05 12/31/05 (EPRI CHUG) meetings, evaluation of iridustry events (industry awarenessj fbr effects on VY, and fleet supportt - ' Total Hrs 990 I-t- Page 2 of 2 NEC037103

VY Piping VAC Inspectlori Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection 2 By- Review z rYt Note: Refvised for VY and industry Events and Opert8tinMg*'rience on 311/05 Piping components are selected for inspection during the 2004 refueling outage based on the following groupings and/or criterla, Large Bore Pipin. LA: Compohents selected from measured or apparent wear found in previous inspection results. LB: Components ranked high for susceptibility from current CHECWORKS evaluation. LC: Components identified by industry events/experience via the Nuclear Network or through the EPRI CHUG. LO: Components selected to caribrate the CHEOWORKS models. LE: Corriponents sfubjected to'off normal flow conditions. Primarily isolated lines to the condenser in which leakape is indicated from the turbine performance monitoring system. (through the Systems Engineering Group) LF: Engineering judgment I Other LG.: Piping idehtif*Ied frotm EMPAC Work Orders (malfUnctioning equip., leaking valves, etc.) Small' ore n SA; Susc'tibte piping locations (groups of components) contained in the Small Bore Piping data base which haMV not reeivead an initial inspection. SB'. Components wlecede from measured or apparent wear found in previous inspection results. S;C: Cornp'ostsi.It~fi~ildy induStri,ý&U tt/"X4iefienee via the Nuclear Netwotk or though the EPRI CHUG'.

                          $0:             Corn*'onents   .po     \o subjoc.ad b* off normal flow"conditions. frhmarlliy isolated lines to the condenser in whfich leak-ae 1s                    alndi*t           :from the tubifie perfborman                                         monitoring system. (through thegystei"                                              Etgini'rihg.

Group). SE: Engineering JudgmentI Other. SG: Piping identified from EMPAC Work Orders (malfunctioning equip., leaking valves, eic.) Pe.a....ter Heater Shalls No feedwalir heater shetl Inspections will be performed during the 2005 RFO. All 1Q of the Ieedwater heater shells have been replaced with FAG resistant materials, Page 1 of 14 NECO37104

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LA: Large Bore Components selected(identified) from previous Inspection Results From the 1995/199611998/199912001/200212004 Refueling Outage Inspections (Large Bore Piping) these components were identified as requiring 16ture monitoring. The following components have either yet to be inspected as recommended, or the recommended inspection is in a future outage. Inspect, Loc. Component ID Notes /Comments I Conclusions No. SK. 0 FD13L 1996 Repbrt: calculated timeýto Tmin is 11.5 & 12 cycles based on a 9619 FD 13SP06 single measurement. The 2005 RFO is 6 cycles since the inspectlon. UT ins*p*pt ellow Rnd downstream pIpe In 2098 - 96-36 002 FD02SP05 1996 Report: calculated time to Train is 9,5 cycles based on a single measurement. The 2005 RFO is 6 cycles since the inspection., UTtlnppgjt elb.w an4 dwtsttropm p00e in 2WQ7 96-37 005 FD07SPOI I......

                                                            -*       port: caiutd tieto Thiui is 96 cycl.e8             s based on a single mes*urelent. The 2605 RFO is a cycles since the inspectiOn,

__9_t UT0ix0teI w .0440 6't#"inn207 0 96-39 005 FDO7SPO2ULS 1.96; Repor:'tal: ,ia.tt"hie t Tiri is 10. " 5cycldes based on a single measurement. The 2005 RFO is 6 cycles since the inspection. 9$-OS 005 FPOZELOU-06 1.9 V0 Rep idrt: c~alcuilatad(44 et6o1,T.m in'is; 7.& 6.7*ylesbaý4 -on a 9'8;07 FDO7EL07 single measureemrnt. The 2005 RFO is 5 cycles since the irrsfctio. Given no signoricant wear found in adjacent compOnents (RSL =1 4.3 cycles on FD07SP07) dofer inrsfsction until lFO26, UT i1t6it-it FI17 .0SP4 single UT inspection. The 2.5: RFO is 4 since the.fp61. o6n. toytes, 99-16 .011 D. P05  : .. &A t..

                           ~~C i~cP4#s..w                            M~6hfiedaUW W0b                 nto  pe

• ie qpstre'ain.Q*untebi f P0D-1 4SP03 2.0.4. Given that..ft o*ly low. readfgs wetre at. t pý0-.-,0ae o o re

/ hiýatbrs located undorthe elbJoW. UtlwpdI elbow Fd114&0-'d4 99-32 017 F004T E0 I (pipe cap) 1'Repor: calculated time to Tmin is 6.2 & 6.8 c les based on a 99-33 CND-Noz32-A single measurement. The 2005 RFO is 4 cycles since the ins peotfon,

                                       ...................  ..UT inspect   elbow and downstream pipe In 2005 99-35       019        FD06TEOI (pipe cap) 1999 Rep56ort: calculated time to Tmib, is 9.6 & 8;5 cycles based on a 99ý36                  OND-Noz32-C                       single measurement. The 2005 RHF is4 cycles since the ihspe*tion.

016 FDISELO1 U is,~4et"101bo.~at downstrampeii20s 02-08 .... 0162 ... 2 recotrmenrdatn to Inspect the ebow-in 4!097 based on as$irigle (8EL 02-09 FDIs8*S02US measurement. fe-inspect elbow and downstream pipe in 2667 (3 04-03 001 FDOITEO5 2004 recommendation to inspect tee in 2008 based on the default wear rate of 0,005 inch/cycle. Rle-inspect upstream elbow and tee In _2008.

04-06 002 FD02RD1CFO. 2004 recommendation to ri-inspect in 2011 based on the default wear

              "                                            rate of 0.005 inch/cycle, Re-Inspect reducer with downstream elbow and tWe In 2Q*7.

Page 2 of 14 NECO37105

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets /Methods and Reasons for Component Selection LA: Large Bore Components selected(identified) from previous Inspection Results -continued Inspect. Leo. Component ID Notes /Comments / Conclusions No.

• SK,.

04-08 -66 1F FD02TE01

• 2004 recorhmendation to inspect ee inl 07 based on the default wear rate of 0.005 inch/cycle. Actual point to point'measurements from 1999 to 2004 indicate no wear. Given EPU operation, re-inspect with I.upstream elbow and reducer In 2007. -

04-09 001 F003$1S401 2(" .recorimeridadfio to ihspet pipe section in 2011 based on a single inspection and the defauft wear rate of 0.005 inch/cycle. Re-in spec*t in 2011. 04-10 001 FD07SPO2DS 2004 recommendation to inspect pipe section In 2008 based on a sin te inspection. Re-Inspect with downstream elbow In 2.08.A 04-13 001 FD14L*03 200 racodmmendatýi to ir*tpect FRow 13 pup piece to DS -vae In: 20Q8 is based on a single UT inspection. Re-Inspect In 2008. 04-23 001. MSD9TEtO1 to 2004 recomnrehdcti0n to inspet piPe section in 2010 du6 to localized ____ _ .SD9O 08T we..r directly under 2 line..s..Rl hl*e.t In 2Q19. 04-23 001 MS39-ELO5 204 w eiind4fti0n to inzspet pipe section in 2010 base on a single Inspection. fe-lpet in 2g. Turbine Oross-around Pipng Previous lnternal Visual UT & Repair History:

Rr6pfaed .IFoAI 18 RF(17

• RF- W AF0.IO YF.*0i0 'RF1Z' RFC2 jFOa3 F- St00.4

             .   .                                                        -       V           ..................

D .....* .. .:**isa v ... _. Yv .......

,t-fl       W..7:.:ighal wyVr.               VIUTJ          Wuti      VTWV        V         V

____ ~ ~R. R *

• ____ _ __

i*p sections replacbd with GE .0A2.42E. elbows pn the & *C lihas are otiginal GEs pedfcflitfon DOA687D., eloows on A"&D lines are DSOA67E (Thorn =0,065 inch),

• 30" AB;C replae;d with A691 CL22 (2-1/40r), Flitings A234 WP22. (Tnom,= 0.625 inch) 30" B remains GE 850A242D, fittings and GE DSOAS7D carbon steel (Tnom = 0,50 inch).

NOTE: Reference Dwg. No. 5920-6841 Sh. 1 of 2 needs to be updated with correct information. This will be performed during the EPU design change effort. The HP turbine rotor was replaced in 2004. Internal visual inspection of all four 36"Odameter tines was performed. An Internal visual inspection of the 30"C line (firsl inspection since thel 1993 replacement) and the 30" D line was performed. 2005 RFO based on increased flows abd the possibility of different flow regimes in both the 36 & 30 inch piping, perform a visual inspection. LP turbine work in 2005 RFO may provide opportunity for access to the 30" lines, As a ,minimum inspect (2) 36 inch lines and the carbon steel 30' B line. Page Sof 14 NEGO37106

VY Piping FAC Inspection Program PP 7028 - 2004 Refueling Outage Inspection Location Worksheets) Methods and Reasons for Component Selection LB: Large Bore Components Ranked High for Susceptibility from CHECWORKS Evaluation The current CHECWORKS wear rate calculations contain inspection data up to the 1999 RFO and wear rate predictions are current to the 2001 RFO. The.2001 and 2002 RFO inspection daja has been entered into the CHECWSRKS database. However, updated wear rate calculations are not conplete, and won't be in time to support the schedule date for issuing the inspection scope for the 2005 outage. Based on a review of the 2001 and 2002 RFO inspection data for components on.the Feedwater, Condensate, and Heater Drain Systems, the CHECWORKS models still appear to over-iredict actual wear. Nothing new or unanticipated was observed in either 2002 or 2004. Feedwater Swtem Listed below are components which meet the following criteria: a) Ae~ative tite to Tmin fromi the predictive CHECWORKS runs which include Inspection data up to th4 1999 RFO. b) no inspections have been performed on these components or the corresponding components in a parallel train sirice the 1999 RFO. Cornp0nent J Loadtion Location Notes FhQS 005 Tg 21

                                    'F-PRElev.               ir                         -Woinpto VtO7Tt01            006      T.A: Heater Bay'Elevs 228     Coronnetits on dther tVain were jrlnedted in 1998.

FD07EL1 I & 248 Results indicate minimal Wear. After updating the model with newer da*ta, assess need CHECWO..h.-Kss ir.speeii',ns 1oraedfitJonaI in-20Q7 BIFO.

ýFDOEL1[2           006     T.B Heater Bay Elev. 248      F0edWft-r heater replacement occurred in 2004 RIF.:

Informal visual jnspections of internals and cut pipe profile indicated a stable red oxide and no distinguisghable FD.8"EO0.1 012 TB Heater Bay .Glevs 228 1ntOr"ridi*dib cempohent.s FD0BELC6 &FD08SP08 were, F'DOSEL:O7 & 248 lnspet6ed in 1998. Results in'dicate minimal weai. Aftr updating CHEC WORK-s model iAth newer data, assess need for inspedting comnponents on tWe train SFID8EL4*):B ,012 T.B HaerfBny 9te. 246 h04 raplace'ent c6tred in

                                                         'FeoWa..rheater                                      IWO.

Informali visual inspeD.tins of internals ahd cut pipe profoe indicted a statble red, oxide.andno distiftguishable wear perttn., FD56O 13, RX Ste-am Tunnel El. 266 Internal Qlsualcif elbow. performed Wit1996 dutlhngeheck valve replacement, no indication of wall loss at thit.tiffia. Corresponding component on line 16"- FDW-14 Was inspected in RF024. After updating CHECWORKS model with newer data, assess need for inspecting _this colponent in 2007 RFO, Page 4 of 14 NEC037107

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection LB: Large Bore Components Ranked High for Susceptibility from CHEOWORKS Evaluatioo --continued > Condensate System Only one component wasidentified as having a negative time toTrain. This was CD30TEO2DS, the downstream side of a 24x24x20 tee on the condensate, header in the feed pump room. The CHECWORKS prediction for the downstream side of the tee has a small negative hrs relative to the remainder of the components in the systerm and relative to the upstream side of the same tee. Other tees on the same header have been previously inspecteod and show no significant wear. The CHECWORKS model includes UT data up to the 1999 RFO. The inspections on this system performed in 2001 indicate mininal wear. Compoenrts CD30TED2 and CDSOSP04 were inspected in 2004. This data along with the 2001 inspection data will be input to CHECWORKS to better cafibrte the model. Mois*ure $aearator Drains &Heater Drain System N6 components idehtifled as having negative times to Tmin. No components wete selected for inspection in 2001, 2002, or 2004 based on hih susceptibility. However future operation under HWC will change dissolved oxygen in sy6temf. A separate evaluation has bean performed and components were selected fbr ihspection in 2002. See Section LD below. Extraction Steam System Three comrponents on this system with negative time to code min, wall: The piping is Chrome-Moiy. ES4ATE01 & E§4ATV.2, 30inch diameter tees inside the condenser have neqgtie prediction (-3426t4rs.) for time to mliWb;ll. The rieo.aiVe tines t6 train may be-conservative based on the modeling 10i'hn[ques used. Reffneinert of th.e .T.*.df-tliis s~t~m is in progress. The hegtiie Ait6 Wtkhiih isrftost likelya funodn-of-tatk of inspection data vsi-*.f.tJ We,

• Dup .. to etehi al lagqlng on this pipirig and the location inside'the condons.er, no:conje.tS are seleeed",ft.xu*nal UT-irillpecti in 2004 based Wthigh susceptibility. HoWever, an opp*.rldnity to perform anh lfrtirnalvisd'aI itf.fiWed of all th" Extraction -teami lirles Inside the condenserduring planed LP turbine work in the 2005C.AFO rW'y prfit ilsef. 94e Section LE below, Note the short section of straight pipe oni line 12"-ES-1A at the connection to the 36 inch A cross around is. ,ssumid to be. AI GSr. B carbon steel is not modeled In CHECWORKS." Tlis componentwas inspected in 20f4 bY etern*al UT and an internal visual inspection frron the 36" crossaround line.-

( Page 5 of 14 NEC037108

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection f (- LC- Large Bore Components Identified by Industry Events/Experience. Review of FAC related Large Bore Operating Experience (OE) and/or piping failures reported since April 2003 beitW Plant - Type ... Description & Recommended Actions at VY 8/S/2W04 Mihama 3 - OE1936&/OE18895: Rupture of Condensate line downstream of restriouion ofifice. PWR PWR system highly susceptible to single phase FAG due:to low DO. Similar region of system as 1986 Surry event (5 fatalities). Based on info gathered by INPO/CHUG/FACnet the location was omitted from Orevious inspections due to clerical error, once discovered mandgement missed opportunity to inspect and deferred inspection until 9/04, Too late. Lesson: make sure all highly susceptible locations get inspecded. PWR Condensate/feedwater piping is much more susc6ptible to single phase FAC than BWR with 02 injectioh. Given that, previous inspection history, and condensate CHSCWORKS modeling; inspect piplto S of all flow orifices in the higher temperature cenden.sate system thaLt have riot b,.een previously inspected in RFO25. Inspect CD30(E01 I 0D00WELII CD00Z02 in ROW5 (r*peat. tnspe'etlon from 1.89). Alto, inspect-Cosiftol JtMS.iELO4/ ClP04' In (I~2 (pw ihs~fi' fl). 10/17/03 Duane Arnlod - OEt17300i Through wMt leak in 4" diaWmatr chrome-mofy Ilaver Drain System BWA bypass line to the condenser- The line was a temporary installation due to delayed FWD heater insta~lation; The cause of the leak. a*pears to be droplet :impingement erosion due to use of a .bypasscontrol valve. The .eeqwuivalaent fres at VY are*the Heater vaiv.08. Drain ThesebypAss lines-to. thea~ttac~hed line h~aveRTD~s to .rt.nitpr I**l~a.,..0A.1V6 oondetnserdois'tre*am into.hi"h .evol cU.dntol the .nda'n..w;r arM system.). S~ni~e1oshv ~ W~o W osDor for 9I40 gouth Texas -OSI7378: Pittingb fMn.n"~W~aae~pn ....... dbdr~ Project4 - PWPA Polishin S~m. Pipe is abnSel low i erhe'a4e(9Ot 1-F neurq!al pW-, andv~elty of 12.2 P1./sec Tortuous (low p.Iband (c*ýdrtirobfiisw may -be Impinoemreint. PWR.-sytern Low. dissolved o.*.yge Equi t.nttsys"tm.at -C is Condensate 1imrnineralir&Sjystem Which is.low terip -and:*sre.Cp, N-.AC2L ____ _______as not: svmeptthle to. F -AG o...dto vii N .3 tvO o00h. 107/0-3_Qa IV~d. 2- OE7 Wrlhi M4 intyt- -nrWf(*1Mkf ii.0n0 M-5i j~in-'b 1tý oPDWPuiis. M~r as.high 6Ittdro uI $tgi tedý t~ syafi h'Isr ha lo . .theefr rn4 u'imW1 ls

                                       .duto slngle.0phase FAG-than I3WR feekýw.ter- pilpig:*AtVY-II              A~ fee~lkat puthp disfrntn            es..nd dowftrf pip'g hate multipe.tio-df.in                            *. No

________ _ further ao nsar anitsjas*d fr*rfit*a . -". 101/V03 Clinton -BWR OEl7412I}OEl947i: Throu6"hwall leaký in 2AB heater vent Jihes tofte'oldseY (lager bore lines assumed given description of backing rings in piping). Alparerit cause attributed to steam jet impingement from wet steam. Equivalent line at VY is common 4 inch feedwater heater vent line for No.4 FDW heaters. This line is included in the SSB databas.e since it connects to (2) 2-1/Z' lines. thipection priority will be determined in the small bore rankins anqpdoritization. 1111 9/03 1-ope Creek - 0E177=0 Pinhole leak wl hnigi ~i abnsel~tato ta BWR supply line to Steam Seal Evaporator. Location of wear is downstream of pressure safety valves. Apparent Cause of leak &wear is due to liquid droplet impingemeht due to high flows from failure of pressure safety relief valveý. No ecuivalent _ lfuiratio a t VY_ 1/24/04 LaSalle 1 - BWR OE 171W9 [IOE18381: Tough-wall holes in extraction steam piping inside condenSer. Location of holes at inlet nozzles to No.2 FOW heaters located in the neck of the condensers (2! lowest stage). All 12 nozzle are C.S. with A335-P11 upstream piping. VY has only the No. 5 FDW heaters in the neck of the oondenser. The No. 5 FOW heaters were replaced with Chromo-moly shells., ES piping is A335-Pl 1 or equivalent which is FAC resistant. No further.actions are anticipated from this OE. Page 6-of 14 NE0037109

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection LC: Large Bore Components Identifled-by Industry Events/Experlence - continued Date Prant -- Type Description & Recommended Actions at A' 2/17/04 Peach Bottom 2 GEl 8637: On line leak in 10 inch mahn steam drain line header to the condenser. BWR Hole was located directly below the connection oi I" main steam lead drain. The header was replaced with 1-1/4 Chrome material approx. 5 years before the leak. Also, ROa in steam drains were modified. The cause was attributed to steam impingement. Additional information to follow after next RFO. The only large bore drain collector at VY is the 8 inch diameter low point drain header, line 8"MSD-9, Flow is through steam traps and LOVs vs. a continuous flow through a restriction orifice. This line is now part of the AST ALT boundary. Inspections of the entire bottom of this header were performed during RF024 with recommendations for

                                  ..repeat inspectiQns in 2010.

8/26/04 Palo Verde 3- OE20386: Through wall leak found on a 10 inch flashing tee cap on the LP PWR feedwater-heater drains. Problems with inspection of flashing tees in preoram. Only 14 out of 153 susceptible locations have UT data at Palo Verde 1,2,3. Theire are no flashing tees DS. ofLCVs on the heater drain system at VY. The onty flashing tees. at VY are located on the .WD pump mrin flow lines at the condenser. lnho6ofion of all 3.1ineri. 6_POW.4, 6"F.DW-$nd 6"FW-, is schedul.ed for RFO 25. 0)24-/04 Palisades- PWR 02119.494: Wall thinning in *oa*:n steel Extraction Steam pipilng Incroased localized wear downstream of Bleeder tfip valve. -Equivatent piping at VY is Extraition team pilling downstream of the revwtse current valves. ES piping at VY i0 ?5 wj 1'4ý1 is)tAO resistant. N~fuftter acticri is fequifpd fotillis OE

 /18104        Catawaba 2 -       0E'ioago: Wa~ll thinin§.dfoq~hfu chfrrtare lOW piping. TWOd areais are PWR                not considered spocific to Catawba: I )A.ra *Wher4 m feedwater bypss rýg valveqs renters     the feýdwatr                                             #~suscptible valves.. PWM feddwatfer system*header     and 2) chemistry   doWnstream has             o *the main loW D.O.. therefore  m.ore:     er reg to wall loss.due to sIngle phse 'FAC than BWR. feedwater piping. At VY area 1) do"e, not exist (bypass linesO dump to the condenser) 2) Inspections have'e'en psrfq.me-d cspstrwan apq downstream of both MOin Ifed T159. valvos. Wfl 6&tibh of 11/.3/04      Da~ne Arnold  -    OE~tf:W(             h~igdwstretvi, ofors Colig etoRtrn Heade.6r.;solation BWR                ValVe. Appar~enrt cause was cavitton -er*.sion duw to lhofling in valva d0uing  !   N I
                                  &"ROC .tebting. At VY, the.equivalent valves are Vi0-34A & 34M. T1e dW of oavltti.on present Is dopendent of the system design and may vkry from lfai"t to plhnt. Previous UT inspections were performed on valve bodies and downatreamn reducers in early 90s. No signilioant wear was found. Consider inspection of downstream piping in RFO26 if additional OE warrants It.

2/6/0... Calvert Cliffs 1 - OE20127: Through-wall leak in 6 inch steam vent header for MSR rain tank. VY _ PWR does -not.have same configUriion. No Moistur* $eparator Re-heaters 2117t05 Clinton ,BWR OE20Y246; Catastrophic fafiure of turbine extraction steam line bellows inside condenser. Found through-wall holes ES piping DS of bellows due to FAC. Apparent cause was attributed to the steam jet from the holes inducing vibrbtion of the expansion joint that led to high cycle fatigue failure. At VY extraction steam piping inside the condenser is A335,P1 1 or equivalent which is FAC resistant. No further actions are anticipated from this OE. 5/9/01 Grand Gulf - Pin Hole Leak in 4 inch carbon steel elbow.in RHR min flow line. System has low BWR use at VY (<2% of time). ( Perry also found thinning at elbow per C.Burton at CHUG meeting.) A review of VY drawings VYI-RHR-Part 14 Sht.1/1 and VYI-RHR Part 15 Sht. 1/1 show elbows downstream of restriction orifices- Previous VY Inspections downstream of orfices on HPCl/and CS systems found no problems. Keep OE listed for future consideration. Page 7 of 14 NEC037110

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LC: Large Bore Components Identified by Industry EvenWExperience - continued Date Plant - Tepe Dscription ,&Recommended Actions -at VY 9/24102 .1P2 -PWR Pin hole leak on 26 12 cross-under piping (HP to MSR) in vicinity of dog' bons at expansion joint under location of weld overlay localized wear under/arourid a - Visual previous weld overlay repair. VY has solid piping (no expansion joints). 2905. Inspections of Wt*'B CAR carbon.steel will be performed In 1/15/02 Surry 1-PWR Leak in 8 inch Condenser drain hoader for 3*/4 pt. FOW Heater v6nt. Also CHUG thinning in Gland. Steam Piping inside the condenser and theo2" Condnser Drain Meeting header from MS Drain trthp lines. The only large bore. drain collector at VY is the 8 inch diameter low point drain header, line 8"MSD-9. This fine is now part of the AST ALT boundaryw Inspections of selected components on this line were pertotmrd during RF024 with recommendations for repeat inspections in 2010 (Seotion LB above). Given this line is part of the ALT Boundary Inspect approx. 2 it. loog seotion at condenser wall during AFO2(6L.2007) or RFO2Y (200$). Lo. Large Bore Components Selected to Calibrate CHECWORKS The CHEOWORKS models have been upgraded to include the 96, 98, &99 RFO inspection data. The 2001 and 02 ingpation data has bean loaded however wear rate analyses have not been completed at this time. the Condensate System. were inspected In 2001 co.rrpbnents on the higher temperature end ofminimal to calibrate die CFIEOWORKSr-tr. The ins8ection data indicate wear and should reinforce the aSSsssm Wit of low wear in the Condlersate* *yýtem. Additional componrntsaelectedfor inspeCtion in 2004 in Section LB above will bb&used to calibrwatethe C-fECWORKS moreL. / Hectbr.*D0.6in5/.*Moeistira Separmtor Drains Pr~io;r tb.i0 002 RFO .there was'limited inspectIon data for the Heater Drain system. The current CHEOWORKS S(l".b i and.totse pass 2)indicate low wear rates. During 2,002 a number of new lnspections vtere peiff tho arbon steel piping up~stream-of the level control;valves .(LCv)to obtain a basliýne:priortt operation

         *.e(on-*

oW.hiydron water chemistry. Piping down stream of the LGVs is FAC resistant niaterial except tar ihlet 1b N6,5 Feadwater heates. No additional components on the Heater Drain system will be inspected in 2005. Feedwater:- No inspections on hine 18"-FOW-12 have been inspected: Inspect FD12EL06 and FDI2SPOBUS in 2005 Main.Steam Only 2 components In the Main Steam system on line 18'MS-7A in the drywell have been inspected to date- Inspect MS1DE=LO7 and tSIDSP13US in 2005. (Note this,also addresses a ffcense renewal consideration for monitoring of Main Steam Piping), Page 8 of 14 NECO37111

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets ( Methods and Reasons for Component Selection LE: Large Bore Components subjected to off normal flow conditions Ldentified by turbine performance monitoring system (Systems Engineering Group). The Systerhs Engineering Production Variance Reports for 2003 listed the `W and C"', !aedwater pump min flow valves'as leaking into the condenser. Threre are sections on carbon steel piping at the connection to the condenser on all three lines. As a minimum Inspect the "B" and "C" lines in 2005, There have been concerns with cavitation at condensate min flow valve FCV-4. An internal inspection of the valve performed in RFO 24 showed some damage to the valve internals. However, due to a leaking isolation valve the coiinecting piping was flooded and an internal visual inspection could not be performed, UT Inspect the upstreamn aEnd ownstream piping during RF025. The valve is operated during outages and startup at relatively low temperatures for PAC to occur. The piping is un-insulated and close to the floor. No insulktion removal or scaf olding Will be r6quired. Since startup from 2004 (RFO24), no other leaking valves or steam traps have been identified (to date) using the Tutbin Pe..dormr ance Monitoring (T PM) system., However, if new data indicates leaking valves then, additions to the outage scope may be required. LF: Enýgineerlng Judgment /Other Ninh A*,ME Section X1 Glass 1 Category B-J welds are to be inspected by the FAG program per Codq Case N-560.in rutof.ac*l.sf*n XI votumetric weld inspection, The VY !$1 Progrm Interval 4.sohedute for irntpedtion of thes4e WIlds is astflldws: TR-U'";ti Outage Section Xl Description FAC Program Components IS[ Program Weld

           '*               *04--3              ipstream pipe to tee      A Feedwater on Sketch 010
              -             FW¶9-F3C            tee to reducer          FD1QTtO1 1r*trval 4                  FW19-F4            redtcer to pipe         FD*10l.1I Perlod 1                      FW2I-Fi            tee to pipe             FD1SSP4 Outage 1.                                                                rD21SP01 Fallr2011 (RrO29)            FW 18-3A            upstream pipe to tee    '13 Feedwhter on Sketch 016 Interval 4                   FW20-3A             tee to reducer           FD18TE01 Period 3,                    FW20-F1             reducer to pipe          PD20RD01 Outage 6,                    FW20-FIB            horizontal pipe to pipe FD.20S01 FW18-F4             tee to pipe             FD1BSP04 Continued CPage 9 of 14 NEGO37112

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LF: Engineering Judgment/ Other -continued ExtendedtPower Uprate (EPU) Feedwater system: EPU evaluation for Feedwater System: The primary focus of Work to date (for PUSAR and RAls) was on velocity changes given only.slight increases in temps and no chemistry chanJes. With all 3 FDW pumps running the 16 inch diameter lines to the 24 inch FDW header have approx. [1.2(2/3) = 0.80120% reduction in velocity. Velocties in the remainder of the system increase approx. 20%. The highest velooities are at the 10 inch reducers upstream and downstreaM of the FOW R[G valves. The expander and downstream piping have multiple inspection data.With FDO7RDO$3DO7SP.03 last inspected in 2001 and FDORDQD03/FDOOSP02 last inspected in 1999. Both of thfe* segments shsuldd be re- inspected after some time of operation at EPU flows. Assuming EPU starting early in 2066, inspect components FP60R0DO & FDO8SP02 in 200D to obtain an up to date pre-E'U measureritet. Inspect FDi07R1DO31 FD07SP03 In 2007 for a post EPU measurement. Condensate System: Given the 8/04 Mihama event: consider additional component in the condensate system for inspection: downstream of f16w orifices &Venturies: FE-102-4 and downstream pipe co 24"-8 venturi type (TB condensate pump room overhead) Given low operating tetp.era*tres and upstream of oxygqn injection point, scope out and evaluate for inspeCtIOi .In RFO2S-In 2007 FE-52-1-A to FE-2 *1 E onCndensate Pe-m]AetaIzer System ( Restriction Orifices). Gfvein low'. opHerMfng temiperatOprs and upstream of dxygenr injection point,, scope out and evaluate for in-sptetlon in RýOSS In.2M67 FE-il02-T7and downstream pipe on 14*C-21 venturi type TB Heater.Bay El 237.5 Given low operating temperatures and usdd fdr start-up, scope out and rev'iia!.UfO; inspeotioh in RF02G* at -R FE-1i02-2A oil 2-G30*C40 ioc6tod In the T&IPa b6Vý~D u p turi type) Previously riA inspeced in 1R89 liI.*ýnet FE bnd do*wnstieam olp[g-In RP025 FE-102-8 on 31, l*o6aed in the TB FPR 8boveFDW pu.mp IB (venturi type) No previous inspection data. Inspeot FE arnd dowistream piping in Ift'oas FE-1 02-2C on 20"C-32, located in the TB FPR above FDW pump 10 (venturi type) Previously inspected in 2001 All Extraction Steam piping is A335-Pl 1, a 1-1/4 chrome material, except for a short carbon steel stub piece in line 12'-ES-1A at the connection to the 3' A croSs around line. An internal visual inspection of this stub piece wVs performed with the cross around inspection in RF024. Also an UT inspection of ESIASP01 was performed in RFO24. Extraction Steam piping in the condenser has external lagging which requires signiwcant effort for removal when performing external UT inspections (plus there are significant staging costs). The piping is A335-P1 1. However an ipportunity to perform an internal visual inspection of all the Extraction Steam lines inside the condenser during planed LP turbine work in the 2005 RFQ maypresent itself. Page 10 of 14 NEG037113

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection LG: Piping Identified from EMPAC Work Orders (malfunctioning equip., leaking valves, etc,) Word searches of open work orders on EMPAC vmre performed for the folIowingrIkeywords, trap, leak, valve, reptace, repair, erosion, corrosion, steam, FAC, wear, hole, drain, and inspect. No previqcsly unidentified components or piping were identified as tiquiring monitoring during the Fall 2005 FFO. Note: the internal baffle plate in Condenser B for the AOG train tank return line to the condenser is to be replaced in RFO 25 (ER 04-14541 ER 05-232 /ER 05-0274). Erosion on baffle plate is from condenser side (not piping side). internal visual inspection of LCV-1 03-3A-2 during RFO 24 indicated some type of casting flaw. The System Engineer suspects possible leaking by the normally closed valve. The downstream piping was last inspectedin 1990. The line typically has no flow. Re-evaluate using the Thermal Performance Monitoring System Data and consider inspectibn of downstream piping in RF026. Through wall leak in the steam seal header supply line 1SSH4 disovered on 9/24/04 (CR-VTY-2004-02985). A temporary leak enclosure was instalfed and a planned permanent, repair is scheduled for RFO25. The leaks are on the bottort of un-insulated piping upstream of the gland seal. Field inspection of the leak location shows that the piping at the leak sloping dowrn to tho gland seal, not sloping up to the seal a shown on the design drawings. UT data on the topeof the piping hter the leak shows fill wall thicknest. At this tirbe, the exact nhechanism which caused the leak is not knoWn. Additional inspections to determine the extent of condition on the 3 other gland seal steao supply lines are required lfnspAt the B0 der elbow and approx. 2ft. of downstream piping on lines 1SSH3S 1SSH4, 1SSH5, and 1 durinsg F-O ,'45.Also flsod on IAdustryOE and similar piping geometry, inspect 2 of the FPE lines r" (1 SiE3 arid 1i'St durin0 #oV2.l

                                                        /

Page 11 of 14 NEGO37114

VY Piping FAC Inspection Program PP 7028 - 200S Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection Small Bore Pining SA- Susceptible piping locations (groups of components) contained in the Small Bore Piping data base which have not received an Initial inspection. Locations on the continuous FOW heater vents to the condensdr" on the No. 3 heaters were inspected in 2002. The continuous vents on the No. 4 heater were installed new in 1995. The start up vents operate less than 2% of oprating tine. No wear was found in Srevious inspections on Heater Vent piping from the No.1 &2 heaters. Given that and the lower pressure in the No. 4, shells a complete inspection of the remainder oa the No. 4 heater vent piping can be deferred. The existing small bore date base and the piping susceptibilityanalysis is under revision, No addtfonal comrponerts from Revision I of the data base will be inspected, SB:;Compojhefls selected from measured or apparent wear found in previous inspection resultsý. Small Bore Point No. 2& 2-1/2'1 MSD-6 @ connection to oondenser A at Nozzle 33 (Inspetion No. 96-SB01 Identified a low reading-at weld on stub to condenser). Upstream valves are normatly closed- TPM system does not indicate any abnormoal flow. Inspect this piping In RFo 26 A through wall leak in the turbine bypass valve qhest 1t' seal le$k-off line form the No, I bypass vales occurred in 200.. (VY Evenrit Report 2006a044). A temporar le;k enclosure was lnstgfled (T.M.2003-002) to contain the leak). W.O- 03-0$04 was writin to inspectlrepafrf.eplace/line. A locaUz;ýd iikfoiNike (c*rbon steel) replacent of the leak location was perfrvmrd in .RFO 24. Additional inspections on thisline identflfi0 looalizbd Wall klss and'6ne additk6rihl like-for-like repair was performed: Engineering Request ER 04-0963 was writteb to coihpletely replace Ibis ppitig With chrorna-moýy piping. (Dresden has already done this). The replacerint (ER 04,0364) is curtently stflbduled for RFO 2P. If thlis ativity gets "de~soped" thei, additional InspectOns will be re-qired to insure ihepiiirig is aOtalbfe for contlined oj$rItiot-V\

                                                                                                                                                -N..

Page 12 of 1.4 NEC037115

VY Piping FAC Inspection Program, PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection Small Bore Pipiung SC: Components identified by industry eventslexperience via the Nuclear Network or through the EPRI CHUG. Date Plant-Type Deseription & Recommended Actions at VY 11/712003' Limerick 1, OEl 7818: Through vali leak in 1 inch drain line back to condenser off ES piping BWR at the connection to the large bore line. Normafly no flow in line due to NC. valve. Piping downstream of valves to condenser on all 3 liles w"s scheduled for replacemdnt. Location US of valve Was thought not to be susceptible. ES piping at VY is FAC resistant A335-Pl I with no drains back to the condenser, Lesson from this event is any carbon steel line in a Wet steam system is susceptdble &should be monitored. Also full line replacement insures all suscept1b6e.pipi'g is replaced. 1/16/04 Clinton - BWR El 7654: Pofebtial tend for adverise equipment condition downstream of orifices. (Rel. Previous experience a Clinton with CRD p.ump minifow R1s). Iinspect CRD pjump_ min flow orifi.es also piniog !)S of RO-.64-2 in RPO25 12006/04 V.C. 'Summer - 0EI9798: Conipt failrotof-a 1 in-ýh ES linie at the ocat.iof of a prvio.usly PWR installed Fermanite clamp repair. Previous teak at weld installed in MAY20"04. Soe presentation at January 2,006 CHUG meeting. (They di not do Ut on the Pipe tp assure styntura! in riorr

                                                                              . t. instaling-.. clamp.)

3/1/05 MoGuire 2- Though-walfl *kin a 2 inch carbon stfl yvent itia, on the MSR heating steam PWR vent.line. Caused..kPy FAG when flashinqocourred upstream of Rol (desighn " Itj No.MSRS or eguplaivalIht l,0,ti6n at VY. cneti o

                    -6iiigtn     -     S0vttd JIbIe gt i5Mi~6001_I ~~r"   - I0 vml a           er~

dd oet!o Eq-uivaleht t PHWR HHS system at ;VY. (INKPo Eventi 931-930429-1) Threaded'connections typically on 6otad6nsate side ofHHS pipig. Low"r eiergy/conisequece 6f jek. iniclude KHS Piif0g. in FAG SuRoeptlbty-Revi1w, and in the.Small Bore Oatbat'se. L4tjrgorqulnkihh lriW and oesuHto o iue ~nlud&n 6/14/99 DatLeaktorl 2 -  !*oh steam trep dislareip&at.Iht..cfed connetion."Equivalent tb HHS - PHW.R sytem at VY. (INP. Evyentf 39*..4-1) i 1 Same as avb'.e,_ 9/1/01 3Petach

                  -BWR' Bottom        (From    i7714Y/0*  CHUG    M.De            on 10*tft.4.10 h..e$i*.

co*mbiner W're-he~a.terdi'a.lnt lih"4le *fd~ehs0r, Perform dO".#dd

                                                                                                     .. le**r'ofn rifq.l [ifH   G'as, Re'-

via'w-:di"Ad"o ___________smaf bore~rdata to1 nlude'46~ r a hdin 4nlooscwec of failurie. 1166/102 Hat&1i/2 .BW14t Condnse in Lekae due. to thboudh 'Well.eoit ekmoo -/ ?noh "sdlop CHUG Mtg. drains similar lines eventSinsie. the condenser. at Byron Unit1I (bE Lines 1260)9)Inad unit w*re (051 eachColumbia 21 K c*ap.'d cut.:ad Um'herick & Dresden. VY slop drain lines inside condenser were walked down ddring 8F024. Some external erosion on piping and supports was found. 1115/02 Catawba 2 Leak in HP turbine pocket shell drain 1 inch dia. OEM showed pipe as P- 11. CHUG Mtg. PWR However, A-106 Gr. B was installed. Inspections were be perWormed on this'line in 2004 to base line condition prior to HP turbine rotor replacem.et. ......... 1/15102 'Dresden 2 f Thinning found in Bypass valvo leak-off ine to the 7.stage extraction steam CHUG Mtg. BWR line. Line is 2" Sch. 80, GE 84A39B. Lowest reading was 0,070" fobnd using Phcsphor Plate radiography. Une was replaced with A335 P-1I. Same line as 2003 VY through wall leak. Partial CS replacement was. performed in RF024. Piping is scheduled to be replaced with A335. PI I in RF025 (ER 04-0965). Page,13 of,14 NEC037116

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Setection Small Bore pipinn1 V SD:Corrtponents subjected to off normal flow conditions, as indicated froo,'he turbine performance monitoring system (Systems Engineering Group). No small bore lines have been identified by Systems Engineering on or before 3/1/05. SE: Engineering judgment Look at piping ODSo orffices based on BWR CE Condensate: Given the 8/04 Mihama event: consider additional comporient in the condensate system for inspection downstreamn of flow orifices & venturies. FE-1 02-6 and downstream pipe on 21/rC-43 venturi type (TB heater bay elev. 230+/- Given low operatitg ternperAtures arid upstroam of oxygen injeclion point, soope out and evaluate for inspection ih 1496 in 2007 -- SG: Piping Identified from EMvPAC Work Orders (malfunctioning equip,, leaking valves, etc.) I S0e LG above. The EMPAC search performedin LG above is applicable to both Large and Small oomp6diihts. Page 14 of 14 NEC037 117

MEMORANDUM Vermont Yankee Design Engineering T"\9; S To S.DbGoodwin Date May 5_ 2005 From James Fitzpatrick File # VYM 2004/007a Subject Piping FAC Inspection Scope for the 2005 Refueling Outage (Revision 1a) REFERENCES (a) PP 7028 Piping Flow Accelerated Corrosion Inspection Program, LPG 1, 12/6/2001. (b) VY.Y Piping F.A.C. Inspection Program - 1996 Refueling Outage Inspection Report. March 23,1999. (c) V.Y. Piping F.A.C. Inspection Program - 1998 Refueling Outage Inspection Report, April 2,1999-(d) V.Y. Piping F.A. Inspection Program - 1999 Refueling Outage Inspection Report, February 11, 2000. (e) V.Y. PipingF.A.C. Inspection Program - 2001 Refueling Outage Inspection Report, August 11,2001. (f) V.Y. Fiping F.A.C. Inspection Program - 2002 Refueling OutageInspection Report, January 20,2003, (g) V.Y. Piping F.A.C. Inspection Program - 2004 Refueling Outageonspection Report, February 15, 2005 (h) DISCUSSION Attached please find the Piping FAC Inspection Scope for the 2005 Refueling Outage. The scope includes locations identified using: previous inspection results, the CHEOWORKS models, industry and plant operating experience, input from the Turbine Performance Monitoring System, the CHECWORKS study performed to postulate affects of Hydrogen Water Chemistry operation on FAC wear rates in plant piping, and engineering jydgment. The planned 2005 RFO inspection scope consists of 37 large bore components at '16 locations, internal itispection of three legs of the turbine cross around piping, and 5 sections 6l small bore piping. Also, any industry or plant events that occur in the interim may necessitate an increase in the planned scope. I will be available to support planning and inspections as necessary. 11you have any qtestions or need additional information please contact me. (Revision 1 identifies Small Bore Inspections due to Industry OE).

• (Revision la adds component Nos, Jo SSH & SPE piping & corrects inor typos in Attachment) am $. Fitzpatrick DYi n Engineering Mechanical/Structural Group ATTACHKMENT: 2005 RFO FAC Inspection Scope 3/11/05 (3 Pgs) Revised 5/5/05 CC LLukens Code Programs Supenrisor D.Klng (181)

T.MOoonnor (Design Engineering) Nell Fales (Systems Engineering) NEC037118

ATTACHMENT ts,...YM 2004/007a VERMONT YANKEE PIPING FAC INSPECTION PROGRAM 2005 INSPECTION SCOPE (515/05) Page I of 3 LARGE BORE PIPING: External UT Inspections Point Component ID Location Location Previous Reason / Comments / Notes No. *- Sketch I nspections 2005-01 F.1 4ELS03 008 T.B. Htr. Bay Elev, 267, 1999 1999 recommendation for repeat inspection. 2005-02 FD14SPO3US 008 " C " 1999 2005-03 FDO4RD01 017 T,B. Htr, Bay8Elev. 245. 1999 Inspect per 1999 calculated wear rate. 2005-04 FD04TE01 017 9. . i9 1999 2005-05 Cond Noz 32A 017 " 1999 2005-06 FD05RD01 018 T.B. Htr. Bay Eev, 245. 1993 TPM system indicated leakage by normalfly 2005-07 FD05 TE01 018 " " 1993 closed valve. 2005-08 Cond Noz 328 018 .. . . 1993 2005-09 FD06R.DOI 019 T.B.,Htr. Bay Elev. 245. 1999 Inspect per 1999 calculated wear rate. Also,. 2005-10 FDOTE01 019 " " " 1999 TPM system indicated leakage by normally 2005-11 Cond Noz 32C 019 1999 closed valve. 2005-12 FD08RD03 011 T.B. FPR Elev. 231 1999 EPU flows increase . 2005-13 FDO8SP02 011 ".. 19999 1. 2005-14 FD12ELO6S 007 T.B. Ftr. Bay Elev. 264. NO Checworks Model Calibration'. Asbestos 2005-15 FD12SPO8US 007 " " NO removal required. 2005-16 CD30FE01 037 TB.1 FPR Elev. 241 1989 FE-102-2A (Mihama Event) 2005-17 CD30ELI 1 037 above "A" FOW pump 1989 2005-18 CD3OSP1 2 037 1 1989 NEC037119

ATTACHMENT t*. IYM 2004/0070 Point Component ID Location Location Previous Reason / Comments I Notes

     ,No.                             Sketch                                    Inspections 2005i9        CD31 FE01               038      T3B. FPR Elev. 241                   NO            FE-i02-2B (Mihama Event) 2005-20       CD31 EL04               038      above "B" FDW pump                   NO             Asbestos removal required.

I 2005-21 CDS 1SP04 038 NO.............. . 2005-22 C....iD21iRD02 040 T.B. Htr. Bay Elev. 230. NO Inspect piping upstream and downstream of 2005-23 CD21RDO1 040 NO FCV-102-4 (piping is not insulated). 2005-24 ISSH3EL05

• Turbine deck at packing NO LP Turbine Steam Seal supply lines due to 2005-25 1SSH3SP06US 3 Htr, Bay Elev. 254. through wall leak at elbow on line I SSHW, 2005-26 ISSH4EL01 Turbine deck at packing NO 2005-27 1SSH4SP02US " 4 Htr. Bay Elev. 254. , *See markup of Dwg. 5920-1239 2005-28 I1SSHSELO1 Turbine deck at packing NO 2005-29 1SSHSSP02US " S.Htr. Bay Elev. 254.

2005-30 1SSH6EL06S Turbine deck at packing NO 2005-31 1SSH6SPO8US 6 Htr. Bay Elev. 254. 2005-32 2SPE3EL01 Turbine deck at packing NO LP Turbine SteamPacking Exhaust at packing 3 2005-33 2SPE3SPO1US 3 Htr. Bay Elev. 254. and 5 due to through wall leak at elbow cn line 2005-34 2SPE5EL01

• Turbine deck at packing NO 1SSH4.

2005-35 2SPESSPO1 US

• 5 Htr. Bay Elev. 254.

___* .... *See Markup of Dwg. 5920-1239 2005-36 MSIDEL07 080 RX Stm Tunnel Elev, NO EPU and LR data required for Main Steam lines 2005-37 MSIDSP13US 080 254 to 260 NO LARGE BORE UT NOTES:

1. Coordinate minimum extent of insulation to be removed wfth J.FRtzpatrkck or T.M. O'Connor Hrom DE-MS. "

2. A =No" in the previous inspection co[lmn Fndicates asbestos abatement may be required, Page 2 of 3 NEG037120  ! 11 :

ATTACHMENT t& VYM 20041007a LARGE BORE PIPING: Internal Visual Inspections (with supplemental UT as required Inspection Point No. Description 2005-38 36" CAR A ( 36 inch diameter Line A Turbine Cross Around under HP turbine) 2005-39 36" CAR C (36 inch diameter Line C Turbine Cross Around under HP turbine) 2005-40 30" CAR B (30 inch diam ete r Line B Turbine Cross Around upelýr east side of heater bay) SMALL BORE PIPING 'Si-ai Bore S.B. System Description Location Drawings Reason /Cominents Inspection Data Number Base No. 05-SB11 119 Condensate 1" piping DS of R.- 64-2 TB. Heater Bay . 191157 Sht, 1 Industry OE17654 5920- FS1 -17__ 05-OSB02 128 CRD V"PIping D.S. of R.O.-3-24A -Rx. SW Elev, 232,5 .G191170 / G191212 Industry 0E17654. P38-1A /G191215 129 15-803 CRD 1"Piping D.S, of R,O,-3-25A RX. SW EIev. 232.5 G191.170/G191212 IndustryOE17654 P38-IA / G191215 05-SB04 130 CRD I" Piping D.S. of R.0,-3-24B RX. SW EIev. 232.5 G191170/G6191212 Industry 0217654 P38-1B /G191215 05-SBE0 131 CRD 1" Piping D,S. of R.Q.-3-25B Rx. SW Einev. 232.5 G19117O/0191212 Indusry OE17654

                                                         ......... P38-1S              / G 191215         .   ......

Page 3 of 3 NEC037121 . 1. :.

(COL"M LUEW F) MATCH LIIS 5~tCH HflO/i CF J6XIWRE3U REVISION It II/24/91 1" OTIA OUTLET rf, VERMONT YANKEE PIPING EROSION-ICZZE HEATE El-IýA DE; CORROSION INSPECTION PROGRAM F*EWE~ATER LVE 1"-FDW-14' ThR811E BUILDNCM4EATER BAY REFERENCES* 0191157/019112.GI9 9B3,k-928-FS~I25' COMPONENT LOCATION SKETCH No,0B0 I Appendix A PP 702S O3iginal Page 13 of 102 NEC037122

               \,

K C-' 0 Appendix A PP 7028 O*iinal Page2 of 102 NEGO37123

Zcsoo- o~

  ! H.

N VERMONT YANKEE PIPING EROSION- -4 CORROSION INSPECTION PROGRAM TURBINE 8UEDNG-FEED PUMP ROOM/I-EATER BAY F-GDWATER LINE 4',-FDW-5 REFERENCES G 19t-57,G I91) 82,G11193 5930-"FS--24,.59 20-F S-125 COMPONENT LOCATrON SKETCH Nqo.018 Appendix A PP 7028 Odial Pa g23 of 102 NEC037124

        /

4 z m¢ 0J 43 App-ndix A PP 7028 OriginPa PýF 24 d 102

I

• C
• V_

I _9 I Appendix A PP 7028 Ofiinal Page 6 of 102 NEC037126

F012Et07 REVISION I: 1f/24/91 VERMONT YANKEE PIPNG EROSION-CORROSION INSPECTION PROGRAM FEEDWATER LINE 18' PDW-12 RU5LDG-HEATER SAY -TURBfthE, REFEREN4CES: C0191 157,GC1911RZ:GI19 110,5920+F5-125 COMPONENT LOCATION SKETCH NoO07 Appendix A PP 702,8 Original Psgc 12,of 102 NEG037127

J

                                                                                        -   EL241'-O' (FLANG D SPOOL PIECe]

16'X20 PWOUCMf

                                                                                                        *15 F11WATFA PUMP 11 VERMONT YANKEE P1PtNG EROSION-CORROSION INSPECTION PROGRAM TURBINE 6ULDNG-FEEDWAThR PUMP ROOM                             CONDENSATE LNE :Y0'-C-30 (CONTINUED)

REFERENCE-S: 19l57,GClg 116,6 91f1Z7,5928- ES-IHS6 COMPONENT LOCArION SKrCýw No. 037 a-Appdix A PF70"28 O:iina, Page 42 &f i'2 NEC037128

EL Nil-Ot FLAN4GS SPQFL PIEC

                                                                 -. . .. 96X2                                 REDUCER NrEEOWATMf PUMP 0N REVISIONC - 7/13/90 VERMONT YANKEE PPING EROqON-.

CORROSION INSPECTION PROGRAM "TURBINE BULDMNG-FEI)WATER PUMP ROOM CONDfJ'4ATF LINE r-c-ai

• ; * ~~RE F ER FE M

R ES t 9 1 7 GI 8 , 9 ! 1 7 .x 2 - S ] 6-

      ,,-1,,,                            8'SCOMPONENT                                      LOCATION Y(ETCH      No. 00.6 Appendix A   PP 7028 Oxiginal    Pagc 43 of 102 NEC037129

              ~~VanCAL Q.                                                                   ,

ccbz'%?N oo z

         .,4.

CC 4REViSION 1 6/17/93 FN ERsoI 4 3/4- VERMONT YANKEE PIPING EROSION-CORROSION INSPECTION PROHG*RAM TUR8INIE OULDINPd-EAThSR DAY -*,a 3 CONDENSATE LINE 14'-C-21

                        .. C ..... , 12-F-I                    c MPONPENT LOCATION SKETCH      No.040 Ir" tk~I  aA     L  UAOrtJprfuul   rage 45 of 1U2

P'tJLflJ~Ar6 $ 3Ec1 ýOLor $PGo Lye d4PL

                         ~ZS$2     C'     II~ftŽI CEG
                     ,t~

F r IJV~ 1 Z-hAin -1s 155 twom N Vn I

                                                                                                              /~4           NSA Isly 2~~~~ý~

4 -i- .0&tcnt..th t E "1/2m. . ~Al .,-~ 1wH~ No 01 C 2 v/ I 15c IV'% (is~cP) -, t I tLFY/

Nfl Ri NOZZlE VERTtCM ELSI 6'-6' C",ý vfý-A4 >CEG ELSOW A I FE1 (4Q MED MS.OWI

                                        'a                 ,l,,

LNF M57DTEL06 REVISION ti 6/23/93 VERMONT YANKEE PIPING EROSION-f CORROSION NSPECTION PROGRAM I MANSTEAM UNE I8E-M$-11)D & fWS--MS-7D j RYWELL & STEAMý TUNNEL REFERENCEt G19i167,019i 162 , 5920-FS-13 COMPONENT LOCATON 5KETCH Appe"cix A -'-uzsVJnginaJ No.O00 Prge I ooft 102 NEC037132

P \ec to OWO ",*co.- tG.O*?9w9B$-i 9 E,.&,, C8ot 4 Q.fjislot-e) 7 FIELP TO Rift PWG IH AM~ fi'acwrs rw- isC psa PCOSDkW CO 19477 rjso w(~f4 CI WA AL "U.'- mc~-xn-w.' 44*E Sf pa (

           ~,~~,

FA

  'r 11    U j

tb(-6 . pL . EL OW'?2& 1AS 6I HIq ________ A-v~n-Y I~E I Ib

     *I "I,

I N]

It. 4'.

                                                                       'I J2
  /

10501, C~Ak S," +/--'(a$*iO~ H, z C-.. V oo K

                                                                                    'FS rz
-~  -4 CtJ
                              ;, 4.                                                  Dr-rAlu. ' C7 ThW¶ ISO)AtTRC.D0 j~~jjj       ~   a~r.ffOJnj r:rsrc,,
       .tl             .4          . rg p47'     I

B'~s~) 11 U

                                             -   14 iw~                                      1, NOTES; I

a. ReAtO 6 ir el DOWIS 5,PIýPUL & tApg OtEAxfttfl

                                                                                                                      $,He H15U4P7*Uv O&an flT *St                       M ro                                                                 A &A4P4140 cw wJ t .a lp rN Prntl-anJ P"4t             11.4W5CT T& YfLen Lu4tnf AMP WI1.4ugdMVJ LANW6 taE I     li I
                                                                                                                      'A". t.Wq'T LeiFM               .4A4L          "00rA*,PAV 4 :

I Blu,

• t-S I & '1. PA- s. -A0 IMPP UxLPtiMataI *4 NtIA?ý

                                                                                                                                                             'AHtt.w   .

VENcl VA'tp Ito1 4041J7$' NypftIAaI tt,.nqo?. Lkv. 4a*4.Ntiwt- rCl. 2%.LS ON I;' A3~'d*HQNWvA 2It, PMtLY~A6. '",k WUfeuWP!L- ISS1Ifl~rSEbEh agy J- -

                                                             ,       nt" I ,

K t [ I I iF t I i MW ii LI i* ~ II7TA~ I It

• a A

             .10     e-w-REFERkErJCE                        DWVGS.

Old3AAOF pAItan-dtcr A fl*N 4 ~ i?4- ~ .9 rl. aSMAN ro. 4i '% C~o-*Tn~t. Dfld S' -CltBq' 4WSfl-W m0 1"tr', r 511 ii 110 vsun~w r

                                                    -15.

V1 rfl S1-C r .I .- YISPAt AMB

                    /l PP 1
                                                                                                      -  m-v~fldt li 1,4KhZ       IMLLdt F0*~ oOfl~0IfldJ 222' 4,
                                                                                                                                      'wJ4~ tdVCtEAR       I~AU? UMlOn          I W'?Y?. SPlAt                              j R~ACFtN      00t0t0%. MOP      05W I{*OSAULC          I NM #5P11mF4.AftfltI'd'                     j 5fl~cM ~4 I            Be  t541'1'¶1                                        .5          .7      1 18               14                 ~19 lE I I*IItNle NEt!U3l13~

I it I~f>i

                                                                                                            '7
                                                                                                                                                                 ~I9uUn1             r I)                (C                    t4 J3

             )

VERMONT YANKEE vk(ý 4-SCOPE MANAGEMENT REVIEW FORM Date: * ... Div! Tracking Number: . ----- (Assigned by Work Scope Control:Coordinator) Referenoefloc t f2,- - k Work Order Numnber: .fl4fl3 i2ý$z. CR, TA Ct Approved Det~pt. Mg~r. Location of Work to be Performed;u.: f nPJ) ADDITION DELE.ION CHANGE--... Description r~ tell4SiU4a t a~ hg o~.

                                              $ustification for Request Review Process Additional Cost:

Dination and Schedflg Impact:_l Assigned DeptA/Mhn-flours to Complete  : Source of Manpower/Other Scope Impacted: Dose, Chemistry, Safety hnplication: Engineering Impact - Man-Hours/Engineering Dept._....... - Optionmal Ways to Address: K Approval Process Piease urovide a brief iistification Scope Review Committee Recommendationi/Planning Pri,,,orhy: 4 (p6vLo' 4--a Priority "C" WO Responsible Dept Approval Genaeral Manlager, ]* .,i,, Plant Operations: ve Date;_________, EMPAC Change Made for ea tCo e& Priority__ _ / SCC Date Log Updated: -.. Copies to Work Control, OutageoSchedu.. VYYPPP 7102.01 PP 7102 Rev. 2 Page I of I " NECO37136

Prepared By: James Fitzpatrick Date: 11/1/05 RFO 25 FAC Program inspections location nos. 2005-25 through 2005-35

References:

Work Order 04-004983-000, FAC Inspections Work Order 04-004983-010, Surface Preparation on SSH piping TM 04-031 Work Order 04-004884-006 ER-05-01 90 CR-VTY-04-2985 CA3 ack~hQ~ou nd:. CR-VTY-2004-02925 documents a steam/water leak on the turbine steam seal piping, line 1SSH4 to the No.4 packing.'TM 2004-031 installed a temporary leak enclosure on this Fine. Inspections on Turbine Steam Seal Piping were included in the scope of the FACrprogram for RFO 25 per CA3 of CR-VTY-2004-02925. The purpose of these inspections is to determine the extent of condition on the remaining steam Seai piping. Work Scone These inspections require access to the SSH & SPE piping on elevation 272 of the Turbine Building. The piping is located under the LP turbine appearance Jagging deck pfates and requires removal of section of the plates to access the piping for surface preparation and inspection. It was intended that these inspections be performed along with restoration of Temp Mod 2004-031 (W.O. 2004-4884-006). Discussion Restoration of TM 2004-031 was removed from the outage scope on 10/24/05 due to interference with critical path work planned on the LP turbines. A detailed rationale for delaying restoration of the TM from RF025 was developed by George Benedict on 9/98/05 and is attached here. The same reasoning and technical basis applies to these inspections. In addition these inspections are not programmatically required under PP 7028 (Piping FAC Inspection Program). The inspections were added to the RFO 25 scope to determine the condition of the piping at parallel and similar locations on the Steam Seal piping as the 2004 through wall leak., The system is a low pressure system with piping located in the heater bay or under the turbine deck plating. Deferral of these inspections does not pose a significant personal safety hazard as exposure to these lines during operation is minimal. The possibility of a leak at another location orn the Steam Seal piping still exists- However, the low operating pressures and the results of UT measurements made on the 1SSH4 line at the location of the existing leak indicate that any failure would be a pinhole type leak vs. a catastrophic failure of the pipe. NEG037137

a ~Entegy, E Prepared By:Date: 9/28105 G. Benedict Replacement of N4 Steam Supply-Piping Work Order 0448$4-06! TM 2004-031 ER 05-0190 History: The steam seal supply line to TB-I-lA, N4 packing developed a leak from what appears to be the result of pipe erosion oh one of the pipe radiuses. Team Inc. was contacted to develop on-line repair options and determined that the most appropriate long term repair would be to install a pre-fabricated clamping device. The clamp was fabricated as recommended and success fully installed per the above referenced Temporary Modification (TM 2004-0341). The permanent repair for the N4 steam seal supply line is currently scheduled to be implemented during RFO 25. The pipe clamp and the degraded section of pipe will be removed and new piping will be field fit ad installed, To facilitate thii work, it will be necessary to remove sections of the LP turbine appearance lagging deck plates to gain access to the piping. Use of the overhead crane will also be required to renmov&install piping and deck plates. LP Turbinea-nd Solw*4oj During RFO 25 a significant amount of work will be performed on the LP turbinae which are located in the immediate area of the degraded N4 steam seal supply line. The LP turbines will be completely dtismantled to facilitate the installation'of the new 8' stage diaphragms and to perform the required ten year inspection. The location of the degraded steam seal line is directly between both LP turbines and implementing the LP inspection in conjunction with the steam seal line repair will create personnel safety hazards, potential equipment damage, and logistical complications. NEC037138

Prepared By: . -Beneadict Date: 9/28105. -E Energy The following represents the specific issues that will be present during the implementation of the N4 steam seal line replacement and the LP turbine inspection: Personnel Safely:

              ,  Fall and drop hazards will be created by both work crews in proximity to both work areas. Open holes will exist on the turbine deck appearance lagging deck plates and in the area between the LPinner casings and exhaust hoods., Although, personnel protection barriers atid equipment will be utilized to mitigate fall and drop hazards, personnel awareness, focus, and goal will be on each individuals own task. The drop and fall hazards will be continually changing as each work activity prgresses and although personnel are required to communicate changes to safety hazards these types of changes will be extremely difficult to manage due to the pace of the LP turbine inspection activity.
              > The crew working on the steam seal piping will continually be interrupted due to overhead hazards from materials being removed and returned tothe LP tarbine centerline. Once again due to the pace of the LP turbine inspection and ihe fact that the steam seal piping replacement crew will be in and out of the work area which isnot visible from the turbine floor only iacreases the potential to inadvertently transfer a load over the piping replacement crew.

Equipment Safety and Quality:

              > The removal and installation of the steam seal piping will involve welding and grinding activities. Shielding can and must be installed to prevent inadvertent weld flash, slag, and grinding dust, however, performing these types of activities in the vicinity of open bearing oil suxmps, exposed shaft journals, and bearing babbitt surfaces increases the risk for accidental damage.

Schedule and Logistics The LP turbine work is the primary critical path activity for the Outage and any delays encountered by the implementation of the N4 steam seal supply line repair will most likely result in an increase in duration. The repair of the steam seal line will require a moderate use of the turbine building crane-to removelinstall deck plates, piping, and appearance lagging. In addition, crane support will be required to remove damaged pipe...install and fit-up new pipe sections.. remove new section to perform non-field welds. ..and permanent instiallation. There is zero turbine building crane availability during RFO 25.

               )  The open hole caused by the removal of deck plating will cause the "A" LP to be logistically separated from the "B" LP on the right side of the centerline which NEC037139

a S...Dat': PrepareJd

                                                                                    >        By (. Benedict 9/2.8/05 t5ýn tergy' will create a delay in the ftansfer of tooling and materials between L.,P "A"and

• Asbestos concern: There is a potential that the steam seal line being repaired contains asbestos insulation. Any asbestos insulation issues could shutdown work on the turbine deck.

Maintenance resources: Maintenance crews assigned to the steam seal line repair have 7 shifts available t'o perform this repair- If there are any delays in perfbrming the repair (e.g. coordination issues or emergent issues during the work), th*e maintenance crew would be required to leave the steam seal pipe repair and return to the refuel floor. Team Inc. was contacted to determine the feasibility of operating the unit for an. additional cycle with the Team clamp in place. The response from Team Inc. was.very favorable with regard to operating an additional cycle with the clamp in place. According to Jim Savoy (Team Inc. District Manager) many commercial industrial facilities that have utilized clamps similar to the *, , one installed onr the N4 steam seal supply line have operated for extended periods much greater than the requested 1Sr'months. The steam seal supply is approximately 2 - 5 lbs. of pressure with a maximum temperature of 255 degrees F. This is considered very low in comparison to many of the applications that Team Inc. has installed similar long term clamps on, If the clamp is left installed for an additional operating cycle there is a risk that the clamp will leak once the plant is placed back on-hihe. Although considered a low probability, the risk is due to the thermal cycling of dissimilar materials that are utilized in the clamping and sealing process. If a leak were to occur Temn Inc., would re-inject the clamp with sealant which has beern successfully performed at other locations. N NECO37140

VERMONT YANKEE

                                                                                                           .................      y........

SCOPE MANAGEMENT REVMEW FORM Dated 0 $C Tracking Number:__ (Assigned by Work Scope Control Coordinator) WYork Order Number:; i- f Reference Docunient 1M zoq- 6 3 (IR, MM, TM. 0028. etc.) Initiator: IC A/1(C r Approved By: _ ___ Dept- Mgr. L~ocation of Work to be Performed,.~ ~~ ADDITION E] DELETION[ CI3ANGE ]. t f Description

             , ;.                                  ....                                 ~~ctsa4t~                 /a Justification for Reques suA,/A        C.d/44                           W 4*4lo n                          /4 7bit /' p 40,9" RIeview Process Additional Cost; DOratiott and Scheduling Impact:

Assigned Dcpt./Man-Hours to Complete: ------ Source of ManpowerlOther Scope inpacted: Dose, Chemistry, Safety Imp~icarion: .................... Engineering Impact - Man-Hoursiflngineering Dept. Oprioria1 Ways to Address:........ Approval Process Please provide aj Igetlusti.ication Scope Review Committee Recomrmendation/Planning Priority:_. . Priority "C' WO) nsib Dept Approval. Planit Mans jo)%AA prv Disapprove Dateý: L-______ EMPAC C~oýr Event Coe rity ........ SCC / DaCI Log Updated: ___ Copies to Work Control, Outage Scheduling. .. . ; _  ; VYPPF 7102.01 PP 7102 Rev. 1 Page 1 of I lPC #15 NECO37141

RFO-25 Piping FACinspections Outage Scope Challenge Meeting 5/4105 Shoq or cryptic summary of what the project involves and why we need to complete thepmiectin RFO 25 (e.*. reculatory reauirement, risk to generation, orooram requirement, appropriate mangqement of the asset.) In response to USNRC Generic letter 89-08, inspections of piping components susceptible to damage from Flow Accelerated Corrosion (FAG) are performed each refueling outage. The planning, inspection, and evaluation activities are currently defined in program procedure PP 7028, "Piping Flow Accelerated Corrosion Inspection Program". Before the start of RFO25, VY will transition to a new Entergy procedure "Flow Accelerated Corrosion Program", ENN-DC-31 5. Desqciption of the scope-of the proiect. what it encompasses, options that have been considered (identifu minimal required vs. discretionary - could be deferred Scop.) Other outage scope that interfaces'With or can be included in this promect; Impacts on others. The scope of the inspections for each refueling outage is based on previous inspection results, predictive modeling, industry and plant operating experience, postulated power uprate effects, and engineering judgment. The scope for the Fail 2005 RFO is defined in Design Engineering-MIS Memo VYM 2004/007, Revision 1. The 2005 RFO Scope includes: External Ultrasonic Thickness (UT).Inspection of 37 large bore components at 16 locations. Includes:

• 5 components recommended for repeat inspections based on prior UT data
• 2 components for CHECWORKS model calibration s 6 components based on Operating Experience (Mihama Event)
• 6 components downstream of leaking N.C. valves (identified from TPM)
• 4 components based on increased EPU flows

              % 2 components D.S of FCV -104-4 (suspected cavitation)

• 12 components based on current through wall leak in SSH at LP turbines External Ultrasonic Thickness (UT) Inspection of 5 sections of small bore piping based on industry experience. Includes 4 sections of piping downstream of restriction orifices at'the CRD pumps.

Internal Visual Inspection of two 36 inch CAR lines to assess changes in flows from HP turbine modifications installed in RFO 24. Internal Visual inspection of the only remaining carbon steel 30 inch diameter line 3O"-B. that have been identified. Pre-outacie sc*ope and lon*g lead-time parts/contracts None Page I of 3 NECO37142

I '1. RFO-25 Piping FAC Inspections Outage Scope Challenge Meeting 5/4105 Initiatives, creative opportunities, unique problems associated with the proect. None The inspection process used is the industry standard. Removal of insulation and surface preparation are required for the UT equipment. Remote methods which do not require insulation removal are still in the development stage, and do not currently have the accuracy required to trend low wear rates (EPRI CHUG). Phosphor Plate Radiography which is currently being adopted to screen small bore components without insulation removal is primarily applicable to PWR plants: Limited use 2 n BWRs, Design Engineering - M/S has minimized the number of Inspections performed each RFO. VY has traditionally trended well below industry average number of components inspected each RFO. This is primarily due the original design of the plant and replacements with Chrome-Moly piping- Recent trends in numbers of components inspected at other plants show reduced numbers of inspections based on piping replacements. 1dentify additional organizational support required, and specifically, management support Inspections will be performed by the ISI personnel. Scheduling and staffing will be coordinated with other ISI activities. Inspections are performed using approved NDE procedures. Training on inspection procedures is performed under the 181 program, Grid marking per new ENN Standard ENN-EP-S-005 Primary DE-M/S interface is the ISI Level fil and/or 11 Program Engineer for coordination in review and approval of inspection data. Interface with craft & other plant groups is normally through established links in the ISI program. Unusual .situations which require additional support will be raised to management level as required, Two DE-M/S engineers (J.Fitzpatrick & T.O'Connor) currently trained in evaluation procedures and have prior VY FAC Program Experience. Other DE-M/S engineers with pipe stress experience can be trained on short notice. The number of inspections Is slightly higher than the last two outages, Coverage will be provided 7 days a week (or as required) to evaluate UT data. The FAC Program Coordinator (J.Fitzpatrick) is responsible to insure that inspections are performed and the data is evaluated in accordance with the program requirements. Activities will be coordinated with the 11 coordinator (Dave King), Any problems that arise that can not be handled at the engineer level, will be elevated per outage management guidelines (30 minute rule,.etc.). Page 2 of 3 NEC037143

 //

RFO-25 Piping FAC Inspections, Outage Scope Challenge Meeting 5/4/05 Identify any preparation issues necessary to meet upcoming outage mifestones.

• Coordination with LP Turbine work for inspection of SSH components (physical space)
• Coordination with LiP Turbine/Condenser work for ventilation path (opening) for the 30" S Cross Around Line and for a window to perform inspections (noise issue).

ER for Design Engineering - Fluid Systems to develop a (paper) Design Change to reduce the piping design pressure in the Feedwater Pump Bypass Lines at the condenser. Current design pressure for the piping attached directly to the condenser is 1900 PSI. Local sections of carbon steel piping remain at the condenser. Leaking valves during past operation cycles may have resulted in increased wear in carbon steel section of line. Identify if all ne ce<ssary outage and pre-outage WO's for the projoct/proprarn scope are gener-ated Work Orders to for support activities and inspections (0.44983-000 series) v/j, t4ex9 "'jdentJfy if any opportunitiies to performn any part of this scope could be cpleted pre-outage? The only components which are not high temperature and are in an accessible location during plant operation are 4 sections of small bore piping downstream of restriction orifices at the CR0 pumps. These may be inspected during operation. However, this is a high noise area. Page 3 of 3 NEG037144

Engineering Standard Review & Approval Form Engineering Standard Change Classifieation Ne Revised El Cancel t TEditorial L Tempora (TCN) . +/-. Engineering Standard Title Doc. No. Rev No, TON No. Flow Accelerated Corrosion Component Scanning and ENN-EP-S-005 0 VNA Gridding Standard Funclional Discipline . Engineering Standard Owner Engineering Standard Preparer I Engineering Programs Jeffery Goldstein Ian Mew SSite Condtcling Reviews ANO

          'P DI

[E ECH JAn IL01 GONS IPNPS I v RUSS

                                                                                       ¥ L

mwPo WFS i... ElI lei~ew TYpe Yes- No Reviewer Napel hire Date Technical Review (See Note below for Deslgn Change Standards) 0 [ James C. Fitzpatrick v Independent Design Verification (See Note bel.w for Design Change Standards) 10C FR50.59Process Applicability Review (attach sceaning and evaluation doumtent) 0 C] James C. Fitzpatdc (See NoWe belmow for Design Change Standard) Irv , Note: ReWeews for EOesgn Change Stopctards are bocumented within the appkmlche ER. ER Num ____

              ' An ER Nurnber Crioss Dislpfine          Is required oý.Dsign Change ReviewsI                         l Standards.
                                                                ].. on..

• A Rvies Gros Dscilie L 0Reviewer Name /Signature 'Date NIA Site Engineerinq Standard Champion Scott D. Goodwin _____-__

A Editorial Change /TCN Approval Name, LSi4nature: ]Date: Comme~nts Section Comnments Made Below I:.:* CoMmrtsAtce TCH Change Below 'TCN Change Attached TCN E~ffec -tive/ExpiraltonDate J ...... CormmentsfTCt qhanae, This standard replaces VY specific TComponent Gridding Guidelines' previously contained inAppendix A of VY NDE procedure NE6,05.3 NE-8053 has been superseded by ENN-NDE-9-05 All VY comments were resolved during dcevetopment of this standard. Jb NEC037145

/ 41 NECO37146

 -a.
                                                                                                        -Týis I Engineering Standard Review & Approval Form                                        )
                                                                                                                       ?t,/4 [6Mt-S                           N   0   Reise Engineesryn Standard Change Classification C           Cac             0        Editorial                    Temporary
                        .Pp Engineering Standard Title                                     Doc.- o.               Rev No. TON'No.

Pipe Wall Thinning Structural Evaluation ENN-.4-.S,-OOA I 0 Functional Discipline tqEngineering Standard Owner Engineering E Slandard Preparer

t. Penny H. Y. Chang Civil/Strctural Site Conducting Reviews; ANO lP Ql

[ EON A

• GONs PNPS .. RBY ] l WO WF3 _

Review Typ YeaN Reviewer Na /ipe ixii.r Date Techncal Review 0hA (See Note below for Oeslgn Change Standards) James C. Fitzpetick - Independent DesignA'orificatllon /. . (See Notebelow foOesig_ Cange Staa_ k.um~sReview r* ]-)-0 ] games C. Flzatdok 10CFRSO.59/Preeess Applicability ICmem James G. Fitzpatirck (*L, (attach screening wyl, evaluation LL~tNote below for Dtsg CaseSanads2 Note: Reveaws for DR.esign Change Standards ate Documented within the " applIcable ER, E Numbs-

              'An ER Number Isrequkred for Design'GhanaeS andwar orilj. Oolk.

Cross Discipline Reviews . ... Reviewer Name I Signature Date (Depoartmenr Name) __________ Site Engineering Standard Champion Scott 0_ oMO (?22 Editorial Change I TCN Approval Name: Signature: Date: _____Comments Section Comments Made Below _ Comments Attached TCN Change Below L TCN Change Attached ITON Effectivel~xpi ration Date _ .... Comments/TON Change: AM VY comments resolved duing development oi this standard- ) NEC037147

Page 1 of I Fitzpatrick, Jim

    .om:     Fftzpatrick, Jim

_ent: Tuesday, September 27, 2005 11:45 AM To: VTYEngineering-Mechanical Structural; VTY._.EFINDL

Subject:

FW: Communication of Approved Engineering Standard FYI This is a new fleet standard for evaluation of thinned wall piping components wtich will replace ENN-DC-1 33. ENN-DC-133 will be superseded. VY Department Procedure OP 0072, "Structural Evaluation of Thinned Wall Piping Components wilt be revised or superseded as requirdd when ENN-DC-315 is adopted. Use: Entry Conditions for this Standard will be in ENN -DC-315 "Flow Accelerated Corrosion Program" and ENN-DC-185 "Through wall leaks in ASME Section XI Class 3 Moderate Energy Piping Systems". WPO has the responsibility to revise the references to ENN-DC-133 in these procedures. Qualifications(trainnq":.- At present there is no ENN QUAL CARD for use of this Engineering Standard, Calculations performed using standard are documented per ENN-DC-I 26..4Based on the scope of this standard, on y Design Engineering - Civil/ Structural personnel and the Mechanical types in EFIN with previous pipe stress experience have the charter and background to apply this standard. Summary oi Changes from ENN-DC-1 33 as applicable to VY: 6 More formalized ties to ENN-DC-31.5, Wear rate determination for FAC program inspections is the responsibility of the FAC Program Engineer

• Calculation of component Wear, Wear Rate and Predicted Thickness is consistent the same as DP0072. The only change from OP0072 is a reduction on thh Safety Factor (SF) from 1.2 to 1.1.

         "    The methods used to calculate the code required thickness for pressure and moment loads are consistent with DP0072, but presented in a different format.
         ,    No significant changes to application of ASME Code Case N-513 for though wall leaks
         " Added attachment for guidance in calculation of component wear rates.

• Excet spreadsheet templates are available to facilitate calculations.

From: Ettlinger, Alan Sent: Monday, September 26, 2005 9:33 AM To: Casefla, Richard; Fitzpatrick, Jim; Lo, Kai; Pace, Raymond Cc; Unsal, Ahmet

Subject:

Communication of Approved Engineering Standard In accordance with EN-DC-1 46, as the Site Procedure Champion (SPC) at your site, please inform and communicate to applicable site personnel, the issuance of the following fleet NMM Engineering Standard. ENN-CS-S-008, revision 0 Pipe Wall Thinning Structural Evaluation This standard supersedes ENN-DG-133. The standard can be accessed in O0EAS on the Citrix server. The standard becomes effective, and will be posted on September 28, 2006. - Ifyou have any questions, please give me a call. 10/2212005 NEC037140

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of

                                                       ))

Entergy Nuclear Vermont Yankee, LLC ) Docket No. 50-271-LR and Entergy Nuclear Operations, Inc. ) ASLBP No. 06-849-03-LR

                                                       )

(Vermont Yankee Nuclear Power Station) CERTIFICATE OF SERVICE I, Christina Nielsen, hereby certify that copies of NEW ENGLAND COALITION, INC.'S OPPOSITION TO ENTERGY'S MOTION IN LIMINE in the above-captioned proceeding were served on the persons listed below, by U.S. Mail, first class, postage prepaid; and, where indicated by an e-mail address below, by electronic mail, on the 19th of June, 2008. Administrative Judge Office of the Secretary Alex S. Karlin, Esq., Chair Attn: Rulemaking and Adjudications Staff Atomic Safety and Licensing Board Mail Stop: O-16C1 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001 E-mail: hearingdocket@nrc.gov E-mail: ask2@nrc.gov Sarah Hofmann, Esq. Administrative Judge Director of Public Advocacy William H. Reed Department of Public Service 1819 Edgewood Lane 112 State Street, Drawer 20 Charlottesville, VA 22902 Montpelier, VT 05620-2601 E-mail: whrcville(aembarq mail.'com E-mail: sarah.hofmann(dstate.vt.us Office of Commission Appellate Adjudication Lloyd B. Subin, Esq. Mail Stop: O-16C1 ' Mary C. Baty, Esq. U.S. Nuclear Regulatory Commission Susan L. Uttal, Esq. Washington, DC 20555-0001 Jessica A. Bielecki, Esq. E-mail: OCAAmailgnrc.gov Office of the General Counsel Mail Stop O-15 D21 Administrative Judge U.S. Nuclear Regulatory Commission Dr. Richard E. Wardwell Washington, DC 20555-0001 Atomic Safety and Licensing Board Panel E-mail: lbs3@nrc.gov; mcbilgnrc.gov; Mail Stop T-3 F23 susan.uttalinrc.gov; jessica.bielecki@nrc.gov U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: rew@nrc.gov Anthony Z. Roisman, Esq. National Legal Scholars Law Firm 84 East Thetford Road Lyme, NH- 03768 E-mail: aroisman@nationallegalscholars.com K

                                                                                             /

Marcia Carpentier, Esq. David R. Lewis, Esq. Lauren Bregman Matias F. Travieso-Diaz Atomic Safety and Licensing Board Panel Pillsbury Winthtrop Shaw Pittman LLP Mail Stop T-3 F23 2300 N Street NW U.S. Nuclear Regulatory Commission Washington, DC 20037-1128 Washington, DC 20555-0001 E-mail: david.lewis@pillsburlyaw.com E-mail: mxc7@nrc.gov matias.travieso-diaz(*pillsburvlaw.com Lauren.Bregmanarnrc.gov Diane Curran Peter C. L. Roth, Esq. Harmon, Curran, Spielberg, & Eisenberg, L.L.P. Office of the Attorney General 1726 M Street N.W., Suite 600 33 Capitol Street Washington, D.C. 20036 Concord, NH 03301 E-mail: dcurranaharmoncurran.com E-mail: Peter.roth@doi.nh.gov Matthew Brock Assistant Attorney General Environmental Protection Division Office of the Attorney General One Ashburton Place, 18t" Floor Boston, MA 02108 E-mail: Matthew. Brockgstate.ma.us by: Christina Nielsen, Administrative Assistant SHEMS DUNKIEL KASSEL & SAUNDERS PLLC}}