ML081780743
| ML081780743 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| Issue date: | 06/20/2008 |
| 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-98 | |
| Download: ML081780743 (142) | |
Text
{{#Wiki_filter:SHEMS DUNKIEL KASSEL & SAUNDERS P L LC RONALD A..SHEMS* GEOFFREY H. HAND
. KAREN L. TYLER BRIAN S. DUNKIEL** REBECCA E. BOUCHER ASSOCIATE ATTORNEYS JOHN B. KASSEL DOCKETED EILEEN I. ELLIOTT USNRC OF COUNSEL MARK A. SAUNDERS June 20, 2008 (5:00pm)
ANDREW N. RAUBVOGEL OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF June 20, 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 the NRC Staff s Motion in Limine to Strike Testimony and Exhibits Filed by New England Coalition, Inc. This filing attaches an expert witness report, NEC-UW_03, which discusses the following documents that Enterigy 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 I COLLEGE STREET - BURLINGTON, VERMONT 0540 1 TEL 802 / 860 1003 . FAX 802 / 860 1208 -www.sdkslaw .com 03
*Also admitted in the State of Maine
**Also admitted in the District of Columbia
Pursuant to the Protective Order governing this proceeding, an unredacted version of this filing 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: SarahHoffman and Anthony Roisman. A redacted version of this filling 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
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UNITED STATES NUCLEAR REGULATORY 'COMMISSION ATQMIC SAFETY AND LICENSING BOARD Before Administrative Judges: Alex S. Karlin, Chairman Dr. Richard E. Wardwell Dr. William H. Reed In the Matter of
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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 NRC STAFF'S MOTION IN LIMINE TO STRIKE TESTIMONY AND EXHIBITS FILED BY NEW ENGLAND COALITION. INC. New England Coalition, Inc. ("NEC") opposes the NRC Staff'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 Boald'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 the NRC Staff 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 technical 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 infederal 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 aredesigned 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")(emphasis in original). The majority of the NRC Staff's arguments for exclusion of NEC's evidence go to its weight, not its admissibility. I. The Board Should Deny The NRC Staff's Motion in Limine A. NEC's Contentions 2A and 2B The NRC Staff observes that Dr. Hopenfeld's "experience lies in the areas of material/environment interaction," but then inexplicably contests his qualifications to testify concerning this very subject in the context of NEC's Contentions 2A and 2B. Dr. Hopenfeld has amply demonstrated his substantial training and experience that qualify him to testify regarding Entergy's analysis of the impact of the reactor environment on certain metal components. His rebuttal testimony states in relevant payt: 2
I have a Ph.D in mechanical engineering, concentrating in Heat Transfer, Applied Electrochemistry, and Fluid Dynamics. I have 46 years of experience in the area of material/environment interaction (corrosion, erosion, fatigue) and related instrumentation.... I have reviewed and approved material fatigue related issues for the FFTF and the CRBR reactors, and I have participated in the development of related codes and standards.... I have managed experimental programs related to fatigue and corrosion in nuclear and fossil plants. I worked on PWR steam generator material-related issues for eight years at the NRC. I have published many papers in related areas in peer-reviewed scientific journals. To address the issues NEC raises in its Contentions 2A, 2B, 3 and 4 requires a broad knowledge of heat transfer, corrosion and material fatigue. I believe that I have the expertise necessary to provide the Board with a competent assessment of the fatigue.., issues relevant to the determination of the effects of the BWR environment on ... fatigue life. Exhibit NEC-JH_63 at A4; See also, Exhibit NEC-JH_02 (Dr. Hopenfeld's Curriculum Vitae). The NRC Staff contends thai the Board should exclude Dr. Hopenfeld's testimony concerning two issues because the Staff disagrees with his conclusions. These issues are:
- 1) whether NRC Staff witness John Fair provided accurate information in testimony to the ACRS regarding the ANL equations; and 2) whether the ASME Code requires an accounting for the impact of environmental conditions that are more aggressive than air.
The NRC Staff s disagreement with Dr. Hopenfeld is not reason to exclude his testimony from the record. Both the accuracy of NRC Staff representations to the ACRS and the requirements of the ASME Code are relevant and genuinely disputed issues that the Board should evaluate in light of testimony and other evidence submitted by all parties. Finally, the Staff contends that the Board should exclude Dr. Hopenfeld's direct and rebuttal testimony that the evidence Entergy has submitted to the Board does not include certain information necessary to prove the validity of Entergy's CUFen analysis. 3
This testimony is clearly relevant to whether Entergy has met its burden of proof, and merits the Board's consideration. B. NEC's Contention 4
- 1. Testimony of Ulrich Witte Ulrich Witte has reviewed Entergy's records of its flow-accelerated corrosion (1AC) 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 program appropriately implements industry guidance and complies with NRC requirements included in Vermont Yankee's current licensing basis (CLB).
The NRC Staff contends that the Board should exclude Mr. Witte's testimony concerning the compliance of Entergy's FAC program with Vermont Yankee's CLB because this issue is outside the scope of the license renewal proceeding. Mr. Witte's testimony concerning whether Entergy's current FAC program complies with NRC requirements and industry guidance is relevant and 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 the Board should theref01re evaluate the quality of this program to determine whether it can provide reasonable assurance of public safety during the renewed license term; and 2) because Mr. Witte has identified flaws in program implementation, including a failure to consistently update the CHECWORKS model with plant inspection data, which bear on NEC's claims concerning the time necessary to recalibrate the model to post-EPU operating conditions. 4
The NRC Staff moves to exclude Mr. Witte's testimony concerning Entergy's "commitments" under its current license because the Staff disagrees with Mr. Witte's definition of the term, and-believes that "Mr. Witte's identification of commitments is flawed." NRC Staff Motion in Limine at 7. The NRC Staff s disagreement with Mr. Witte on this issue is not reason to exclude Mr. Witte's testimony.. Mr. Witte has identified the documents he reviewed in evaluating Entergy's "commitments." See, Exhibit NEC-UW_03 at 11. The Board has the information necessary to evaluate Mr, Witte's testimony and should consider it. The Staff contends that Mr. Witte's direct testimony should be excluded as unreliable because some statements contained in his report, Exhibit NEC-UW_03, are unsupported or incorrectly cited. 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. See, Exhibit NEC-UW_03 at 10-13. NEC disagrees that an expert witness must provide a specific citation for his every statement. Mr. Witte has, nonetheless, identified a number of citation errors in the copy of his report filed as Exhibit NEC-UW_ 03. He has, also determined that one of his Exhibits, NEC-UWI 5, is incomplete; and a second, NEC-UW_20, was printed from a corrupted file.' 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. Mr. Witte converted this document to a text-searchable format from a PDF file. The conversion changed the substance of some of the text. The corrected versionof this Exhibit is printed from the PDF file Entergy produced to NEC. 5
The following lists some of 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. .0 Entergy failed to consistently update CHECWORKS with plant inspection data. Mr. Witte's references include the following documents: Exhibit NEC-UW_10, Condition Report CR-VTY-2005-02239 ("The CHECWORKS predictive models for the Piping 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.".); Exhibit NEC-UW_08. See, Attachment A at 15 n.29, n. 31, n. 32, and 19 at n.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. E There was a pipe rupture in 2006. Mr. Witte cites the following document: Exhibit NEC-UW_07 at NEC038428. See, Attachment A at 20 n.49. Finally, the NRC Staff takes issue with certain conclusions Mr. Witte draws from his observations of Entergy's program, such as that Entergy's failure to update the CHECWORKS model with plant inspection data weakened the predictive capability of 6
the software, and that Entergy's FAC program only partially'complies with relevant provisions of the Vermont Yankee CLB and therefore will not constitute an adequate \ aging management plan for FAC. The NRC Staff 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 his qualifications and the information he considered. His testimony merits the Board's consideration.
- 2. Testimony of Rudolf Hausler The NRC Staff contests Dr. Hausler's qualifications to testify on NEC's Contention 4 on grounds that Dr. Hausler lacks "actual experience using, CHECWORKS." NRC Staff Motion in Limine at 11. The Board should reject this argument because the Staff does not specify any portion of Dr. Hausler's testimony that would necessarily depend on actual experience using CHECWORKS. In fact, Dr.
Hausler's testimony concerns the qualities of FAC that make it necessary to recalibrate an empirical FAC model such as CHECWORKS following a significant increase in flow velocity, and the difficulty of accounting for variations in FAC rates related to geometric discontinuities in an empirical model. He also provides general statistical analysis illustrating the time needed for recalibration of an empirical model such as CHECWORKS. Finally, he interprets certain data concerning the accuracy of CHECWORKS. See, Exhibit NEC-RH_ 01 at A6; Exhibit NEC-RH_03; Exhibit NEC-RH 04 at A6; Exhibit NEC-RH_05. Dr. Hausler is amply qualified to provide this testimony. See, ExhibitiNEC-RH 02 (curriculum vitae of Dr. Hausler); ExhibitNEC-RHO1 at Q2 - Q3 (discussing Dr. Hausler's education and professional background). 7
The NRC Staff also contends that Dr. Hausler's testimony is "unreliable" because he did not produce as Exhibits certain textbooks andd papers referenced in his expert report, Exhibit NEC-RH-_03. Dr. Hausler's testimony is based on his own amply demonstrated professional training and experience. His report is not rendered "unreliable" by his failure to produce copies of all his technical references, many of which he authored himself (as the NRC Staff observes). II. The NRC Staff's Motion in Limine Should be Granted with Respect to One Portion of the Testimony of Ulrich Witte. The Board should 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 altered some of the text of the document, including the number of 2005 inspection data points. NEC will file a motion to withdraw Mr. Witte's testimony concerning this issue. The Board should deny The NRC Staff'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. This testimony appears in Exhibit NEC-UW_03 at 20 and Exhibit NEC-UW 01 at 5, and should be excluded. 8
June 20, 20082 New England Coalition, Inc. by: Andrew Raubv el Karen Tyler SHEMS DUNKIEL KASSEL & SAUNDERS PLLC For the firm Attorneys for NEC 2 NEC's Opposition to the NRC Staff's Motion in Limine to Strike Testimony and Exhibits Filed by the New England Coalition, Inc. is timely filed on June 20, 2008 under 10 CFR § 2.306, which extends the deadline for response to a filing by one day when service by e-mail is received after 5pm. NEC received the NRC Staff's motion after 5pm on June 12, 2008. 9
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 FAGC 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 by Entergy 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 requirements. 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, 2004', 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, 1spoke 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, fNEC038514). 2 Exhi6it 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. 3 Exhibit NEC-UW_14. 2
into question the results of FAC inspection during RFO 25 and RFO 26, in which power up-rate design data apparently is as yet not incorporated. These program implementation delays are substantive, and based upon the 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 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 required I to be identified, investigated, and remediated expeditiously. 4 Promises to correct the deficient program at some point in the future are not sufficient, unless all reasonable alternative 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 410CFR 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, defective 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 6\ 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 Vermont Yankee. ( 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 with 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 NECWc I0l ...-. _ ........... ..... .. . . , , ...... - -{ Deleted: 7 6 Kepco Ordered to Shut Down AMihama Reactor. The Japan Times, September 28, 2004, available at http:i/*earch.iapantinmesco./p.i/membermnenbet., html?nn2004092at6.hun. I" 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 value 8 . Procedure ENN-DC-315, was revised and in effect 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 we]re in fact still being implemented in February 2008, when Staff inquired on this subject. 7 Exhibit NEC-UW_07 Cornerstone Rollup, Program: Flow Accelerated Corrosion, Program Infrastructure Cornerstone, Quarter: 3 rd, dated 10/03/2006, page NEC03_1_9 ("Corrective Action Plan to complete_open . - Deleted: 1 LO-CA tasks developed 10/02/2006, (CR-2006-02699)"). See also pp. NEC038422. NEC038424. NEC038426-28-see also footnote 3. 8 Exhibit NEC-HJ42, VY Piping 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,NECO17888. 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 Deleted: Formatted: Highlight Exhibit NEC-UW_20, .PP7028 Piping FAC Inspection Program, FAC Inspection Records for 2005 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 1 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 predictfailures has 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 was therefore void.' 2 J showed an trend of increased frequency of rdinspection. 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. Seepage NEC037107. The condensation system showed one component with negative time to Tmin. The Extraction Steam System indicated three components with negative time to code min wall. Page NEC0Q 7_108._ _ . .. . . . . . ..... - Deleted: 7 12Exhibit NEC-UW-I 1, 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. 7
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 uponyrepeated passes with new grid points and new rankings selected. Data input and passes by CHECWORKS were-not accomplished on an outage-by-outage basis.14 With only 63 points examined in RFO 2615, the baseline for the 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 Statifon, 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 " Exhibit NECUW_7 at NEC(0.3.,84,2..4. . .. .. . . .. .... ". .. Deleted: 10 ,4Exhibit NECUWZ2,_VY Piping FAC Inspection Program PP 7028- 2005,FAC Inspection Program - - ' De Dleted: UW-20 Records for 2005 Refieling Outa.ge atEC_ -'*37'12
-NEC037120. .. . f Deleted:_7 Exhibit NEC-UW-I 1, 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 significant 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% 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 16. 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 EPRI guidance.17 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 CO 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 . Pleasant Prairie, a fossil plant with similar conditions, endured a catastrophic FAC failure at 13 years, causing two fatalities' 9, 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. 6Exhibit NECO-j. at 7 CNEC017894). Deleted:U-2 17Exhibit NECUW-04; Exhibit NECUW-0,5 at XI.M17 .....---- - Deleted:------- 'g Exhibit NEC-UW_22 U.S. NRC NUREG 0933; Issue 139: thinning of Carbon Steel Piping in LWRs (Rev. 1)_at 1-4. 19Exhibit NECUW-21, Milwaukee Sentinel, March 9, 1995. 20 Exhibit NECUW-20 at NEC037109.. ... .. .. . -.. .. .. .. .. ..... -- 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 the Clinton Plant failure. III. Licensing basis for management of flow-accelerated corrosion at VY and review of the program implemenltation 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 witlh implementation; Part D, my independent observationsbased 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 CorrosionProgram" effective December 1, 2006.
22
- 4. Commitments made by the licensee including the following:
- 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 c 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. 10661 .R1, published by EPRI in 1999;
- x. Official Transcript Advisory 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); 22 Items 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 Results. (NEC001 13191) 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 refueling outage; xviii. ENN-CS-S-008, rev 0, effective 9/28/2005, pipe wall thinning structural evaluation; xix. DP-0072. 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-VYI, Engineering Programs, dated 11/22/2004; xxii. EPRI review of Yermont 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 Propram with respect to the licensint basis.
- 1. The current licensing basis goal is to preclude negative design margin or pipe rupture due to Flow-Accelerated Corrosion and is centered around use 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 __I (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.24
- 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 23 These documents 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. Page,2*4ncludes a failure rate for BWR plants. The.
- Deleted: s probabilistic risk assessment for BWR plant FAC failures is reported as 1IE-5 (higher than reactor accident threshold PRA for Design Basis Accidents). ( Deleted: and 30 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 changes to the p3lant.26 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 28 that Entergy was aware of the problematic state of the program for many years. 25 Exhibit NEC-UW_06 at 152-157; Exhibit NEC-UW_08 at 2. 26 Exhibit NEC-UWI5 at20, 2 This Exhibit provides industry-wide data on FAC failures. The high rate of - Deleted: 18 failure in BWR plants underscores the need for precision in implementing an FAC program. . Deleted: 30 27 Exhibit NEC-JH 3-Aat, 3-3.A..J. [Deleted: UW 28 Exhibits NEC-JH4' at NECO17893-912; Exhibit NEC-UW-09 at NEC038514, NEC038515, ""Deleted: 16 NEC038529. NEC03853]-038533: Exhibit NEC-UW 07 at NEC038422. Deleted: ; Exhibit NEC-UW_16 at 4-1 Deleted: UW-05 14
- 5. T 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."1 The Octob~er 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
-LDeleted:, 10 29 Exhibit NEC-UW-08at 1. 4-( . . .
DOeleted: 1; Exhibit NEC-UW-12 30 Exhibit NEC-UW-09_at 2, NEC03853 I-NEC038555. "CR-VTY-2004-03062" and "CR-VT'Y-2004-03061." - - - .Deleted: 9 Deleted: letter 3 Exhibit NEC-UW-02.at NEC038424 ("CHECWORKS models and wear data analysis updated with all ,.. Formatted: Highlight 2d06.'") ........... previous inspections in 3 d quarter SFormatted: Highlight 32 Exhibit NEC-UW 14, Email from Beth Sienel to Jonathan Rowley. Feburar, 20. 2008" t Deleted: i
;~'.Deleted: .
33- -- - - j- Formatte d: Highlight
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 susceptible 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 34fl. " Exhibit NEC-UW-0&at 5-6: NEC-IJ%-20 at NEC037103. -... [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 thinning 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 b'yond 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 C 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 16 Exhibit NEC-JRI,* at NEC017893. See also NEC-UW-20 at NEC037108. Deleted: UW 17~Exhibit NEC-JH_43 attNECO2O 18. j Deleted: 05
. - Deleted: 5
[ Id. atNEC_2_0197... Deleted: 41 17
- 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,
-1Deleted:"
the report notes the need for program management to ensure ppdate of susceptible 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, 20060 2 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.,, 44 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 -, .at2(NE.C038.5 1.4).................. .............. -- Deleted: I1I 40 Exhibit NEC-UW-.9 at 5 (NEC0385 17).............. Deleted: I I 41a
- Deleted: Exhibit NEC-UW-I I 42 Exhibit NEC-UW-0. at NEC03841 9, NEC0384227-
-"- Deleted: 9 43 Exhibit NEC-UW-0,7 at NEC038424.- SDeleted: 9 44 Exhibit NEC-UW- latl . ................ ......
-- 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 FAC 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 notes'plafit 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 48 conflicts were identified with missing programmatic requirements.
- 16. A flow-accelerated corrosion related pipe break associated with a 1" elbow, SSH (WO 06-6880), appears to have occurred in 3 rd quarter 2006. 49
- 17. Entergy apparently reduced the number of FAC inspection data pointsbetween the 2005 refueling outage and the 2006 refueling outage, in violation of its commitment to increase inspection data points by 50%. The 2005 refueling outage inspection called for 4' Exhibit NEC-JH 44 at 17.(
46 Id. at 18. 47 Id. at 19. [" 48 Id. at 27-29. / 49 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. I 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 superseded.5 2 This error potentially invalidates the baseline requirement of CHECWORKS, in accordance with NRC-endorsed guidance, 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 avoid procedure makes the results f 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.
s0 Exhibit NEC-UW- 1 at 4. Deleted: 4 Exhibit NEC-UW-1,ENN_-C-3_15)_at 1; Exhibit NEC-UW 19 PP7028). Deleted: 5) Deleted: 20 52 Exhibit NEC--f-4,.?42 at NEC017888.- Deleted: 20 13 Exhibit NEC-UW-06 at§ XL.MI7. Deleted: 05 I4 Exhibit NEC-,JI-38 at 4-5 ............................. Deleted: UW-06 20
- 19. No indication is provided that plant isometrics were updated as required as of 10/22/04.55 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. 57 Trending to the high -end of the range is appropriate where variables affecting wear rate, such as flow velocity, have significantly changed, asat 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). " Exhibit NEC-JH_44 at 19. Deleted: 7 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
K 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%."8 Of this group, at least three - Clinton, Dresden, and Quad Cities - appear to have FAC-related issues.59 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 5' Exhibit NEC-UW_ 18, Union of Concerned Scientists, "Power Uprate History," July 12,/2007. '9 Exhibit NEC-UW 20 at NEC037109. NEC037116: JHI 42 at NECO]7894 NECO17897. NECO17898: J-H 43 at NEC020196, -(Deleted: UW-05 22
2005, regarding use of the tool and the applicant's intention to conduct benchmarking testing during RFO 25 and 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.
Zj (
NEC-UW_15 CORRECTED PENNSTATE Department of Mechanical and Nuclear Engincering (814) 865-2519 College of Engineering Fax: (814) 863-4848 The Pennsylvania State University 137 Reber 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. I had the students normalize the data in such a fashion that we could then compare to the break frequency spectrum curves generated byfthe 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 1 Pennsylvania State University Dr. L.E. Hochreiter April 2005 I
( 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-bf-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 frequenrey 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 D ata C ollected ......................................................... .............................................................. 8 2.1 OECD Pipe FailureData Exchange Project.......................... 8 2.2 Independently CollectedData .............................................................................. 9 3.0 Collapsing and Analyzing the Collected Data ......... '........................................................ 12 4.0 Results and comparisons ................................................................................................. 15 4.1 FailureFrequency as afunction of Pipe Size ........................................................... 15 4.2 FailureFrequency as afunction 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 3
( 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 PWsRs 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. BWR 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
- List of Tables Table 1-1. NRC Total Preliminary BWR and 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 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 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 reactor coolant makeup system. Currently, the evaluation criteria for these types of accidentsistate 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]:
- a. Peak cladding temperature must not exceed 22000 F.
- b. Maximum cladding oxidation must not exceed 0.17 times thetotal 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 the 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 [381. This table is replicated below. Table 1-1. NRC Total Preliminary BWR and PWR Frequencies. Plant Effective Current Day Estimates (per cal. yr) Type Break Size 5% Median Mean 95% __________ (inches) _____ _____ __ ____ _____ 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 BWR7 6.6E-08 1.4E-06 6.OE-06 2.3E-05 18 1.5E-08 1.IE-07 2.2E-06 6.3E-06 41 3.5E-11 8.5E-10 2.3E-06 8.6E-09 1/2 7.3E-04 3.7E-03 6.3E-03 2.0E-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 PWR7 1.IE-08 6.3E-07 2.3E-06 8.8E-06 s8 5.7E-1 0 7.5E-09 3.9E-08 i.5E-07 41 4.2E- 11 1.4E-09 2.3E-08 7.OE-08 K 7
2.0 Data Collected For this project our'group c0llected 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 FailureDataExchange 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 databasedid 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 plant 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 it was 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 CollectedData [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-I. Excerpt from "OPDE-Li ht" Database PLANT PIPE SYSTEM APPARENT CAUSE PIPE SIZE TOTAL NO. Crack- Crack- Deformation Large Leak P. Severancea 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 1 BWR SS SIR Severe overloading 6 I I BWR CS STEAM Water Hammer 6 I __"_"___ BWR SS RCPB IIF:Welding Error 3 7 1 1 1 4 IBWR SS RAS TGSCC - Transgranular SCC 2. 7 I 1 1 4 BWR SS SIR IGSCC - Intergranular SCC 4 4 I 2 1 BWR SS RAS IGSCC - Intergranular SCC 4 56 1 32 9 1 13 BWR SS SIR 0 1I BWR SS RCPB TGSCC - Transgranular SCC I I " BWR SS SIR IGSCC - Intergranular SCC 2 3 I _.WR SS RCPB Overpressurization 4 2 I 13WR CS AUXC Vibration-Fatigue 5 1 I Table 2-2. Description of 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 AirSystems Carbon PCS Power Conversion Systems (incl. Steam Extraction Carbon Lines, Heater Drain Lines, etc.) RA§ 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 Steam turbine steam(from nuclear boiler/steam generator up to admission) Carbon 10
Table 2-3. Definition of OPDE Pipe Size Grou s. Size Corresponding Corresponding Pipe 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<I0.0 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) 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 from "small leak" only in terms of the geometry of the throughwall defect Pinhole__Leakand the 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 Full circumferential crack - caused by external impact/force, including high-cycle amechanical 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 Analvzing 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. 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 2.0-4.0 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 1 7/8 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 simplification 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. Stres's 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 Afier 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 l/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. Next, for 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 several causes of failure were, combined together into one failure mechanism. category. The collapsed form of this database is 'Provided in Appendix C. Independent Database 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 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. r 14
4.0 Results and Comparisons 4.1 Pipe Failuresas a/unction ofPipe Sizefrom OPDE Data 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 BWVRs. 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 (1/cal-3 rs). Plant Pipe Size Groups OPDEResults NRCPredictions 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 3.9E-08 0.0-1.0 8.2E-05 4.7E-04 1.0-2.0 2.3E-05 1.3E-04 BWR 2.0-4.0 5.6E-05 2.4E-05 4.0-10.0 6.2E-05 6.OE > 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 pip~e size groups and overestimate the failure frequency for the larger pipe size groups compared to the NRC predictions for both PWRs and BWRs. 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. 15
1.OOE-08 0.0-1.0 J1.-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 icarbon and stainless steel pipe failures in both BWVR 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 J
At * " NRC BWR Prediction 1.OE-04
, ~'*-.4 -. . 1.OE-05 - -
L'.."", . I .0E Z 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 4.1-2 Normalized rupture-frequencies as a function of pipe group size for both carbon and stainless steel pipe failures in both BWR and PWNR 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 (1/cal-yrs) 0.0-1.0 37 9.8E-05 1.0-2.0 14 3.7E-05 PWR 2.0-4.0 10 - 2.7E-05 4.0-10.0 29 7.7E-05
> 10.0 21 5.6E-05 Total 111 0.0-1.0 31 8.2E-05 1.0-2.0 5 1.3E-05 2.0-4.0 6 1.6E-05 BWR 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. 1.0OE+D0 1.0OE-012 OPDE Results
- -NRC Mean X X NkC 95th Percentile 1.00Eo02 - NRC Median -
* " "* ,,,NRC 5th Percentile 7i 1.0OE-03 .
,, 1.00E-05 *".*
LL I.OE0 -1 V. +
- x 1.00E-07 ,
0 Zj, U 0.0-1.0 1.0-Z0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (inches) Figure 4.1-3. Normalized Failure Frequency Distribution for ]?WRs. 18
1.00E+00
, C NRC 5th Percentile "1.OE-03 F 1.00E.04 IN
/
L1.OOE-05 ..... . LL 1.00E-06 i.OOE-07 0 1.001E-08 1.00E-09 1.001E-10 0.0-1.0 1.0-2.0 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 datacontained in these tables was normalized based on the total number of failures for the given plant'type (1355 for BWRand 1536 for PWR). Table 4.1-3. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05 Both Carbon Steel and Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only Steel Pipes Pipe Size Normalized Failure Normalized Failure Normalized Failure (inches) Number Number Number rlaieFiue of Failures Frequency of Failures Frequency of Failures Frequency (l/cal-yrs) (1/cal-yrs) (llcal-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 Both Carbon Steel and CarbonSteel andesStainless SaCarbon Steel Pipes Only Stainless Steel Pipes Only Pipe Size _____Steel Pipes ________ inhes (inches) Faiumbes Number Normalized Fai u Number mber ormalized Failure ormalzedFreqenc Number. Normalized Failure
'of Failures Frequency Failures Frequency of Failures Frequency (1/cal-yrs) (l/cal-yrs) (_/cal-yrs) 0.0-1.0 375 822E-05 118 2.6E-05 257 5.6E-05 1.0-2.0 107 l.1E-05 32 7.0E-06 75 1.6E-05 2.0-4.0 259 2.61-05 32 7.0E-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 PVWRs. 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 preyiously 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
1.005-04
&Z1.00E-05 LL~
S1.00E-06 1.00E-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 4.1-5. Normalized pipe failure frequencies as a function of pipe size for PWRs. I,. U.
- 0 0
z 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 pipe size for BWRs. 21J
--4-Carbon Steel 1.OE-03 3
-+-Stainless Steel
--*-NRC PWR Prediction S1.OE-04 u.1.0-05 tL I *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.OE-02
*- Carbon Steel 1.0E.03 - -- e-Stainless Steel
-* * "*-NRC BVWR Prediction 1.oE.04 e
I. 1oE-o05 1.0E-07 S1.0E.06 0.0-1.0 1.0-2.0 20-4.0 4.0-10.0 > 10.0 Pipe Size (inches) Figure 4.1-8. Normalized pipefailure frequencies as a function of pipe size for BNVRs 'sing the Modified Analysis Method.
K Table 4.1-5. Summary of PXVR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method. Both Both Carbon Steel and CarbonSteel ands Stainless SCarbon Steel Pipes Only Stainless Steel Pipes Only
*Steel Pipes___ ____
(ipeSize (inches) Number Normalized reeny Failure Number Normalized Feeny Failure Number Normalized Failure Frequency of Failures Frequency of Failures Frequency of Failures (l/cal-yrs) (l/cal-yrs) (l/cal-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 I 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 PWVR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method. Both Carbon Steel Steel Pi and es Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only Pipe Size Normalized Failure (inches) Number Normalized Frequency Failure Number Normalized Failure Number Frequency of Failures' Frequency of Failures (l/cy of Failures (l/cal-yrs) (l/cal-yrs) __(l/cai-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.OE-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 -- 1011 --
4.2 Pipe Failuresas afunction of Pipe 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 (i/cal- rs). Plant Pipe Size OPDE Data NRC Independent Type (inches) 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.OE-06 2.3E-05
> 10.0 7.2E-05 2.2E-06 2,2E04 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. 02.- OP DE resul
. 1.1-03 U.U i1.E-04 1.E-07 I.E-08 0.0-1.0 1.0-2.0 2.0-4.0 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 throughout 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. N "2 23
F --- OPDE resuts t.E-03 -' - r 1.E-0"4 I.E-0O I.
- u. l.E-OG S1.E-07 1.E-OS 1.E-09 1.E.10 0.0-1.0 1.0-2.0 204.0. 4.0-10.0 > 10.0 Pipe Size Oinches)
Figure 4.2-2. Normalized pipe failure frequency as a function of Pipe Group Size for BWRs. Overall, the two indepenident data sets show contradicting trends when compared to the NRC normalized frequencies. Instead of the double-ended guillotin&'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 theý independent data found. 24
4.3 Pipe Failuresas afunction of FailureMechanism 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 Failure Mechanism 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 3.11 E-05 PWR Mechanical Failures 4.23E-06 7.1 IE-06 1.13E-05 PWR SCC 9.60E-07 3.25E-05 3.34E-05 PWR Water Hammer 0.00E+O0 3.84E-07 3.84E-07 PWR Misc 1.15E-06 2.69E-06 3.84E-06 BWR Corrosion 6.31E-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
IDCarbon &Stainless Steel I Z 8.OE-05 2 F!6.0E-05 0 C 4.OE-05 g r 2 .OE-05 O.OE.OO-NJAl Corrosion FAC MIC Erosion Fatigue Human Mechanical SCC Water Misc Factors Failures Hammer Failure Mechanism Figure 4.3-1. PWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism 1.600E-04 1.400E-04 0 Carbon Steel
- Stainless Steel
- Carbon and Stalnless Steels 40i.2OaE-04.
V 1.ODOE-04 , LL 6.OOOE-05
- 6.OOE.*i5 C4.OOE.05!
2.00OE-05 O.OOOE+OO / -U Corosion FAC MIC Erosion Fatigue Human Mechanical SCC Water Misc Factors Factors Hammer FailureMechanism Figure 4.3-2. BWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function of Failure Mechanism 26
4
- J 10 Carbon Steel 9.000E-05, t Stainless Steel 03Carbon and Stainless Steel
*8 . 0 00E-0 5 . I
.C ý
*-6.000E-05
- C 5.OOOE-05 7.OOOE-05 t:- 4.000E-OS 3.00012-05, 1,00012-05 Corrosion 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 PVWR 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 mechanisms were 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 corrosionbecause 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
1.0012+00 1.00E-.01
-.-*Stainless Steel Carbonand Stainless Steel 1.00E.02 I -
1.ooE-03 U. 1.00E-04 1.002-06 1 2 3 4 5 6 Pipe Size Bin Figure 4.3-4. Pipe Failure by Corrosion as a Function of Pipe Size (PWVR & BWR) 1.004E00 1.00-E01 Carbon Steel
--*- Stainless Steel 1.00E Carbon and StainlJess Steels 1.00E-03
- a. 1.002-04 1.002-05 1.00E.06 1.0E2-07 2 3 4 5 6 Pipe Size Bin Figure 4.3-5. Pipe Failure by Fatigue as a Function of Pipe Size (PVVR,& BNVR) 28
1.OOE00 1.00E-02 11.OOE-03
- CL C,
I .OOE-04 11.00E04, I ' 2 3 4 5 6 Pipe Size Bin Figure 4.3-6. Pipe Failure by Mechanical Failures as a Function of Pipe Size (PWR & BWR) abnte 1.OOE-O1 1.OOE-02 11.00E-03 Cr E 1.OOE-04 11.0012-05 4 nng:" - 1.OOE-07 1 2 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 greater 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 OPDEData
- 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 ofPipe 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 of FailureMechanism
- 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 datablase 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.
32
6.0 References
- 1) 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 N-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.
33
- 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, 1991.
- 17) Grimes, Brian K., Information Notice 95-I1: 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 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: 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 STAGNANTL 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, 1981.
- 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).
35
r - ______ PLANTTYPEI PIPE TYPE SYSTEM GROUP I APPARENT CAUSE GROUPE OFOiAL PIGRP RECRORS NO. Crack-Fu Cradck.PanDefonna on Lrge Leak Leak PkI.-La.al Ruu I Severace I Si! I Leak Wal trMq PWR tCS Ca',tabon I PWR I CS Cawabor4aosicn AUXC -1 CavitaIn..eroslon 6 1 AUXC I Ca~alno'oak~ Corrosion 2 I AUXC Corrogcon 3 3 3 PVVR CS AUXC Coroson 4 AUXC Corroveon 20 6 Corrosion 6 6 I 10 1 PWR Ero.won-camttson 6 PWR I EbosLon-corros-on 2 PWVR Erosiorn-rroslon 1 2 PWR EFco,,sn.=OAnoon 3 PWR CS AUXC 4 13 Ero.*n-caorosin 20 PVWH EroULrn..coros ejo PVNR 20 PWVR CS Ex1tenM Irct I PWR I PWR PWR HFCONSrANST - 4 4 2 1
-1 2 PWR CS AUXC HF.Ikznan Error 2 AUXC HIFtKaluonError AUXC HF.W*6&n Error PWR AUXC HFWIktt5 EIrnu 1 -- 1 PWR CS AUXC - Macr~ouo9caty hlJwo MEC 2 I I
'AUXC AUXC PtRv CS AUXC- y kdxed Co'rowon 5 12 1 1 1 PWR CS AUXC 4 2 1
PWR S t 3 3 PWR CS I I CS 6 CS I PWR CS ESC 2 EHS 3 EHC 9 EHC Il 3 1 2 4 3 4 3 PWR 2 PWII 2I PWR Cs FPS HF.Wek3OI Error PWR CS 4
- Se~r.o~.r~.4ng L2 ~3 <F -
PWR FlWN PWR CS FPS
-1
-I I 1 1 2 CornoTu, 1 6 I A PWR I ss I FWC I Ercsm 5 I I
PWR I Ss -E A c6' W ted Corrov on 4 1 7 a 50 P,5R I s I FWC I - Fugue 3 1 PWR I 5 I FWC I 1 2 2 2 PWRI HF.Designrror I - I I 1 I I PVVR I ss I FWC 6 I I I I I- I PWR I SS I FWG I HF.WCLVV error 1 3 I I PWR I sS I FWC I Someroverloaadcg - 2-- 1 5 I 1 4 1 1 I1 9 1 1 3 -
-PVVR I sII S 3--
18 PWR _ I SS I FWC 4 2 1 - 1 - I 1I 2 1 PWR I sS I FWC Watv Hanmer 5 1 1 1 1 1 1 1 I PWR LSA HF.Human efTfr I 2 1 1 PWR I CS I A-SA I _ eSe ov~eoa0ng. 3 _ A
-PWR I CS PCs I Cwo,,on 1 1 2 1 1 I
I FACG-Flo. CCeGlrat6d CoMrOon 2 I .1 3 1 ý, PCs FAC. FbowA*.eWAld Ctnoumon 1 5 3 1 1 _6 1 20 1 I
- PVWR I cs I PC I
Seee Obro~ 1o~ 2 -- --- I 2 1-- 17 1 - -
6 I I I I I _ I I I PWR Cs PC.s 3 PCS 6 4 4 RAS 2 2 I 3 4 RAS 8n046-Flact,.e 1 RAS Ij 2 5 2 2 as '6 42 4 2 4r -2 3 I - Eown-cah1mofn 1 PWR I SS RAS FAC - FnowAcerated C.To5ro 1 I -2 I RAS I 2 1 PWR I SS I RAS HF.FriMcaon Efror 2 1 1 HF.Huian error HF:HAnm error PWRm 6I RAS HF.REPAIR/AWNT ~~1 S4 I 3-- 2 7 3 4 4 2 4 2 ~1~ PWR S 2 2 3 7 4 5 4 2 3 2 3 PWR I SS RAS I 3 -PWR-I RAS 3 2 RAS 4 RAS 3 3
-I-RAS Thumal Fabgjo 4 10 -
ThemnW Fabgk-Cych"~ 3 4 -1 RAS 5 -70 PV 1 0 2 I 3 443-
-30 2 2 7 7 1 25 1 4
S -4 RAS Vwrat-llague 6 RCPB RCPB I S RCPB CUgTrosion I 2 1 I
2 2 I P¶VR 16S RCP8 I I 9 1 2 ' I I - I 10 PWR I RCPB PWSCC 2-I I 4 2 PWScc- I 1
- . 1 2 1- 1 3 3
PWR1 6s 7 -I 1 I 4
-I- I I 4 PWHR -1 as I RCP8 I - TheraJtfat" PWR 5I - fm,*laltgue r" I M110 RCPB RCPBS V
Vbrab- r-Filgue 2 -- 1 3 107O 7 PV 2 1- I- ~ F 1-
'PV PV I
1- - l CS SO ,Crosicao . 1 I 2 3 PWR 6 1~~~ 2 m 2 I- B/A-ý - 3 1 1 2 2 PWR 1 63 . SIR __ .c~tbrowasio 2 -r -- I. -I PWR T
-r HF.CONSTANST -- - i PWR 1 63 3 1
-6PVVR I SIR I 6 I
65 a SIR I HF.We&2Ng Error 3 2 PWR SS I , SIR
- SIR I - ~Ovaierst&d I 1 1 3 I
6 Ss I SIR PWSCC 1_ 5 1 17 Sae wadoaam~ 1 6 2 I I I PWR 1 65 1 SIR TGSCC- I I I PWR SIR__ I Thema -agI-, 4 1 3 2 1 4 1 PWR I , S I SIR I -. 7heimeIFalu.~Cyckrig PR I as. I SIR I Vi8hraborabg - - 1 - 3 2 1 6 PWR I SS ( SIR I - oraborlfltqbg - 1 3, 1 -- I I 3 4 PAIR I C9 I~ STEAM------I CorroworbWal"e 1 6 1 1 1 I I I - PWR I CS~ I SEAM I FAC Flo Actaj ~s 2 1_ to 1 9 __PWR I GS I STEAM- I FAC Flo A--are - Iors 14 I- I I - I - 10 1 2 STEAM I 1 2 HF.Weong Error
- PI PWR I ~CS I STEAM __I ---
P% PWR -CS T- STEAM I V,~lb~ ---- I I I - III I I ~ _1 _- I I I 1541
PIPE SIZE I TOTALNO. I PLANTTYPE PiPE TYPE I SYSTEM GROUP APPARENT CAUSE GROUP, OF RECORDSI Cra:-Fd I Crack.P&1l I efcmalun LaroeLea" Leak PA4.-LeakI r I Severei* BWR BWR CS CS WAUK Iýon 2 4 AUXC 3 I AUXC 4- i AIJXC '-BWR I CS 2 I AUXC 6 7 2 1 AUXC 3 AUXC 6 1 BWR I CS AUXC 3 4 2 2 4 7 3 5 9 i 3 5 6** 8 2 2 6
- BWR AUXC I 6 2
4 BWR _ CS I AUXCj IMIC tam eay Ut&cad Corosnio 6 3 5 I 36 BWR I CS AUXC Sowe ovee odng 2 8 2 AUXC 3 - 4 2 2 71 7 1 2
- 6WR I ENC HF.Hk*j¶¶a e,& -o 4 2
3 2 8WRII Ca I E tC I 3 I 65 FPS 2 CS I Cs Corrosn I Cs FPS IA _ 5 2 Cs CS CS FPS -_F _ CS CS CS FPS - 5 BWR Cs 4 L I1 FPS5 1 6 2 2
FWC I Coirmavo Caffo~ I C- [ - - r 2 Cceroum BWR as CZTo-&-o 2 BWR IS Co wwo 8WR as# OWR BINR FWC -F BWR FWC 2 2 SWR SWRt 21
-F OWR Eroion~,
8311 -F FWC I FAC. Fhow acl lred CoTrosion I I -r FWC FAC- F&Dw Acceleraied Ccoi~on, vFWC FAC.- FlowAccelerated~ Corowan 22 FWC FAGC- FloeAcCrealed CaiTosai 2 - I 1 WR I SS FWC Fat"u -r HF.CONSTANST 4 FWC HF.CONSTANST FWC HF.CONSTANST WR 63 HF:Fkzoanorror H F:W"h-V Eirce 2 2 H-FWe"dn error IGSCC. - keagrariilr SCC FVVC I Sevee verioading i severe wovelolo 3 Seweeovedoodrig 4 FWC severe velolv 6 FWC severe cverloaedm . 6 FWC S=CC Srwvam-reIndrokdCwovrosion Ua-ck~ 2 I B81R I SS FWC 81CC- szaauwtaV1~w carowm cr!LAMn 4 61CC.- Stainfale kxkmCad Cosion aCrong. 6 W-CC.St~raisrle bk~r1~d Caoaer1 Craddr-g 6 8WR I S--- FWC 2 3 1 -- ThermalISIOue 3 I i 5 6WR I 8S FWC .6 4 3 4 BWR . I S I Fwc Umeported 6 I SWR I I I B8WR I CS W"S 2 -I I 831RI CS 1LR&a I -I I I i I- [ Colrolkon 1t 8WR I, CS wdc yeACCeinelaed Corrowor,
B__ PcC - Seveoverloading 2 2 1 1 1 Vo*raton-14bgue 7 SWR CSI _PCs - 7 - 4 3 BWJR 6s RAS Cystalonma*en 6 3 2 4 BWR RAS Coltoslon 6 3 17 8 BWR I-BWR S8 RAS HF:CONSTANSI 3 4 1 1 BWR 2 1
~1~
2 2 4 BWR I 8 RAS - 1 _2 1 L I - I I I 1 2__7~ SWR as_ 2 I 6 86 L E 11 2 BWR 6s 4 1 Ics i Toce Tr%&m*,SC 2 7 7 6 1 96 TGSCC. Transq,,, sCC BWR 88 10 BWR J6S RAS 1 3 8WR SS RAS 1 76 *1 8WR Mbralolra u4*0 4 WVatawabgues 15 3 7 t1 8WR 1 waEa fn m ,*e I ¶ I as Corrolon 2 SWR SS* RCPB 5W 8j EC=C. ICB Exer Cimde ;azaCdSC
$c I
~ I I I vvR ~O as I )~-~
RCPS I ECSCC - ExWnad CNowe WKLCMSCC 1 4 1 I_ I_ I BWR I ,a 6 2 I I 1 I I 8WiR I I CW14 SS I RCP8 I 14F:FabrcalonErro BWR 2 1 1 SWI4 I BWR 8WR RCP8 . , ~ - HF.VieUM~Error - 3 BWR I SWR BVWR Hot crac BWR 1_ 4 BWR BWR RCPB r SCC 1 4 20 2 __l 2 IA4 1 2 1 1 BWR I ss I RCP8 TGSCCO.TramgramurSCC I
-sS I- HOPS I Thomwa FaIe 2 1 -
I I I
-BWR T_US I - HOS P -- I Vibrbr-Fabgue 42
, 1 1 4--I
ýW2 , H S5 3 1 I1 I I I I1IR6NNSIR BWR SS I RCS.INSTR I TGSCC-Tr&-dgxtwsOO I 1 1 2 1 BWR SIR OnIIetract,, 1- 5 1 4 4 SWR I ssI -SM I ECSCC .Ex~nal C~onde ced c I I BWR ss FAC.-Flow A0:&ated Cwroslo 1 3 1 4 1
_SWR I V4 fI -r I I BWR -1 6s HF.CONSTANST 2 1 - 1 2 SWR HF.COHSTANST HF.COOSTANST HF.CONSTANST i5 I1 I I I I BWR I Ss HF:Fabrcalon Eacef HF.F.Ollcabon Error HF.Hurrn rwo I I F_ I I I I I I I BWR SS SIR 2 I I
-- I IGSOO- ktIgwuwISCO 1 2 1 3 1 1 1 1 I
8VWR I S.S _ 5 RGSCC - IeI2 ar-.SCC I -- l . 2 I BWRI CS SIR I MI - n~e orso Lul~ar 6 j - 1 1 I -
;3 Sev~ea ovwi~o6ang 2 2 severe ove~,ean 4 6
TGSCC. TIahsgqem~a 3, BWRI 65 SIR 50CC=- ransqgm1.iar B 6C Thermalfalique 2 3
- TrIm rnatf.e 6 3 SImmi~naIague 6 1 BWR I S Therme.1abue-2yckb 6 2 I 6
.0 8WR I SS I Vizrabcri.faligue 6 Viwrabcffavgue 2 I I I I 21 1 v~ablonIula" 3 BWR SS SIR 4 2 SIR 6. 11 SIR 6 BWR I CS STEAM 2 11 STEAM ECSCC.- ExthalaCliilodia Indixed SCCC 1 I STEAM Erosion 3 CS STEAM Efosn.n 4 I FAC. FlawAcce~naed Corrosion 12 1 FAC.- I Ac~eeiraled Corrowon FAG - Flo Acesfedi Corrosion 8WR 2 F 3 3 2 BWR I CS I BWR I CS I 10 SICC.-Slrabate kx1i~d Corrosion1 Crading 1 -6 I BWR 3 4
-TGSCC. Trsns&grteu SCC 2 1~~
SWR 2 BSIR 3 BWR Trwmalafaugu 6 I - I 8EWR BwII BWR vICaawmall" - 3 1- 2 1 I 2 1 BVVR CS I I I I I I - I
App endix B _ 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 EroslonrCorrosion IN 91-18 Arkansas Nuclear One Unit 2 PWR CS 14 6 Erosion IN 89-53 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 IN 97-84 Surry Unit 1 PWR CS 30 6 Not yet determined IN81-04 Suny Unit 2 PWR CS 18 6 Erosion/Corrosion IN 86-106 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
- ... :Diablo Canyon Unit.. ,: ýiPWR.C.: S . .i ,:',.'o-T he.mal Fatigue A,4 - 1..N,92-20";o,,'.;
- ..*..-:lsa.Un.t
. ._- ;-.-' ,Eroslon/Corrosion;:r.
-PWR' _..IN 91"18".:Q
.:ý:i:.,:'pv~Sequoyah
.. Unit I." -P.WR` -M-CS ",Uni.t,.* * :., ,'....... ..,':*,-Thermal
, ý.. Fatigue :,,
.Eroston/Corrosion.'.",- r,,:tIJN I N 92-20'.:-.:.
91-ý18:."" Wolf Creek PWR SS 0.25 1 Vibration IN 89-07 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 IN 82-09 Fort Calhoun Station PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 SCC IN 82-02 Maine Yankee PWR SS 3.5 4 sCC IN 82-02 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 . IN 82-22 Sequoyah Unit I PWR SS 16 6 Fatigue IN 95-11 Sequoyah Unit 2 PWR SS 10 6 Human Factor IN 97-19 Surry Unit 2 PWR SS 10 6 SCC IE Clrcular76-06
;.-.Paloede. .. P.WR .-.SS , -. . uman Factor,...: ",Bulletin.79-03:.
,-::...San.Oniofre Unit 2t *--:SS' ? 7XPWR ar5..,:':,7 - !Y-.;,(HUmanFactor..'.-'.Bulletin.79-3
- -*:,aHn Unit-3--2,-; PWR; .',SSý " - -- Human'Factor.'.:;
nnofre :Bulletin :79"3:.. unit Is,;,f,- .. WP014b"S . . SCC - .IN 79-19-,* .
ý iaTl unit . '- :'PWR - .*?`..SSJ I1/2 -, - SCC..... -. .iN 19 .
, ,, TMIU'u*fS LID"WR ' ' ....
Polnt Beach Unft1-I_,!**'.'i:i:.W 2R:;..;1 ,' '--"' ' " "" ."-,-" "' ", :- ;.*,IN 99-19.,,_1
Appendix B (cont.) Pipe Size Plant Type I Material Diameter Failure Mechanism Reference I _ Group Flueehns Rfrc 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 15-34 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 IN75-01 Dreseden Unit 2- BWR SS 10 6 Thermal Fatigue IN75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN75-01 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 I "BWR SS 22 6 SCC IN 83-02 Hatch Unit 1 BWR SS 22 7 6 SCC IN 83-02 Hatch Unit 1 BWR SS 22 6 SCC IN 83-02
* ....Hatch Unit I1" BWR SS ' 22 6 SCC IN 83-02
" Hatch Unit 1' WR 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 IN83-02 Montecello. BWR SS 12 6 SCC IN83-02 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
... . ro ns.e..*Un '"iI Unit I..*:1-*', B..R .. ' ree"zi-g BWR*: *'.';* :"i- ,- E'*-"-.:.i" ......*.-.,; ... *=;:.,*' Freezing" ,.*': . IN 82-24-38
~,*, I:.*.N
,j*-"Dresden
*9 94-38'.*.,.
IHighlighted plants ,were :notused in :the data ana1,sis due to missing information.¶.
Appendix C. Collapsed OPDE Database' Collapsed OPDE Raw Data as function of Pipe Size Plant Type Pipe Size Group Resulting Number of Failures (inches) CS SS _ CS+SS 0.0-1.0 154 544 698 1.0-2.0 74 154 228 2.0-4.0 78 75 153 4.0-10.0 126 112 238
> 10.0 93 126 219 Total 525 101! 1536 0.0-1.0 118 257 375 1.0-2.0 32 75 107 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 K
Collapsed OPDE Raw Data as function of Failure Mechanism Plant Type Failure Mechanism Resulting Number of Failures Plat Tp FirM hCS 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 Misc 6 14 20 Total 525 1011 1536 '..-."- "*. : i ' -,":.~..
" '" A:. .*>'-""°','
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 Mist 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 Mist 10 2843 33 Total 796 2095 2891
Appendix D - References
- 1) LydeUl, Bengt & Maithet, 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: RUiPTURE 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 12,1991.
- 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 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: 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.
- 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, 1981.
- 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).
N
._L
.*N...EW...... ............................................................................... ........ ........... .............. .N E C -UW -.2 0 ....................
CORRECTED PP7028 Piping FAC)Inspectiorf Program FAC INSPECTION PROGRAM RECORDS FOR 2005 REFUELING OUTAGE TABLE OF CONTENTS TAB Pages 1 FAC 2004-2005 Program EWC Program Scoping Memo & Level 3 Fragnet 2-5 (4 pages) 2 2005 Refueling Outage Inspection Location Worksheets! 6-19 Methods and Reasons for Component Selection (14 pages) 3 VYM 2004/007a 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), daied 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 RFb25, dated 11/1106 (6 pages) K 5 2005 RFO FAC Piping Inspections Scope Challenge Meeting Presentation, 44 -46 514/05 (3 pages) 6 ENN Engineering Standard Review and Approval Form from 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 Vt for: "Pipe 49-50 Wall Thinnirng Structural Evaluation" ENN-CS-S-008, Rev. 0. dated 9/22/05 & 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: lndex and Evaluation Worksheets 70 - 327 (258 pages) 10 Small Bore Component Inspections: Index and Evaluation Worksheets 328k- 347 (20 pages) Page 1 of 347 NEG037099
I.............................................................................................. I................................. ENN Nuclear Management Manual Non QA Admnhnistrative Procedure 1 I ENN-DC-183 Rev.1 Facsimile of Attachment 9.10 Program or Component Scoping Memorandum 2004-2005 Program Scope Memo / Vermont Yankee - Engineering Department WBS Element: FAC Inspection ProgramnProject Number:
Title:
Pipng-Flow Accelerated Corrosion (FAC) Inspection Program 2004 & 2005 Program Related Efforts Desi gn En__gineerinjg. Mechanical I Structural Owner: James Fitzpatprick
.BaOnur: Thomas O'Connor _
Procedure No, PP 7028"r, Vermont Yankee Piping Flow Accelerated Corrosion
Title:
Ln section Pr raLa Detailed Scope of Project (Explanation): Engineering activities to support ongoing Inspection Program to provide a systematic approach to insure that Flow Accelerated Corrosion (FAC) 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 FAC 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-DG-315 (which is currenbtly under development with an accelerated development date of 6/30/04). Expected Benefits (Justiflcation): VY committed to have an effective piping FAC inspection program in response to GL 89 Conasequences of Deferral: Possible hazards to plant personnel. Loss of plant availability, unscheduled repairs, and deviation from previous regulatory commitments. Duration of Program: Life of plant 2004 Key Deliverables or Milestones: Completion Estimate Complete Focused SA write up & generate appropriate corrective 6118/04-actions (coordinate activities with program standardization efforL S _L_ Completion of RFO 24 documentation, write and issue RFO 2004 7123104 Inspection Report Software OA on XP platform for OHECWORKS FAC module Version .8/13/04 1.0G U
.Issue 2005 RFO Outage inspection Scope, Including Scop-ing 911104 worksheets.
Update Piping FAQ susceptibility screening to account for piping and 813/04 drawing updates- Include effects from NMWC, power uprate, & life extension. Update piping Small Bore piping database and develop new priority 10/01104 logic for inspection scheduling, I Page I of 2 NECO37100
ENN Nuclear Management Manual, Non QA 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 CHECWORKS models using Version 1.0G 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 proqramojoqrc). Adoption of ENN-DC-315 ENN Standard FAC program 10/31104 Procedure to include all previous improvements identified Self Assessments-Ongoing Program Maintenance. Includes: procedure revisions, 12131/04 program improvements, benchmarking, attendance at industry (EPRE CHUG) meetings, evaluation of industry events (industry awareness) for effects on VY, license renewal project input, andfieetsqpport. 2005 Key Deliverables or Milestones:. Perform Pronam Self Assessment (minimum once per cycle). '41/05 Conversion of CHECHWORKS1.0G models to SFA Version 2,1x 911/05 RFO 25 support 11/15105 Completion of RPO 25 documentation, develop RFO 25 Outage 12/31105 Inspection 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 1115/06 Update SFA Predictive Models with 2005 RFO data. 4115/06 Ongoing Program Maintenance. Includes: procedure revisions, 12/31/06 program improvements, benchmarking, attendance at industry (EPRI CHUG) meetings, evaluation of industry events (industry'awareness) Jor effects on VY, and fleet support. Estimated Budget or Expenses: Armount/Hrs Captured in DE MechlStructural Base Budget 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 ------------------------------- Mechanical / Structural 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 InspeK in Program Level 3 Fragnet YEAR 2004 (2nd half) (Time Line from 6/01104 to 12/31/04) Preparer Reviewer TOTAL Est. Est. Delivery Task No. Task Description (HRS) (HRS) (HRS) Start: f Completion Estimated Estimated. Estimated. Date Complete Focused GA write up &generate appropriate corretive 04-1 actions (coordinate activlties wvth program standardization 20 10 30 611I04 6/18/04 efforts). Completion of RFO 24 documentation, vaite and issue RFO 2004 04-2 inspection Report 60 30 90 61/14/04 7/23104 Software OA on XP platform for CHEOWORKS FAC module 04-3 Version 1.0G 20 10 30 7/4104 8/13/04 Update Piping FAC susceptibility screening to account for piping 04-4 and drawing up~dates. Include effects from NMtWC, power uprate. 401 20 60 7/12104 8/13/04
& life extension.
Update piping Small bore piping database and develop new 04-5 priority logic for inspection scheduling. 40 20 60 q/6104 10/0 1/04 04-6 UpdateRFO 2002 &2004 RFOmodels CHECWORKS using Inspection Version 1.0G vith lateste data 160 80 240 8/23104 12/31/04 Issue 2005 RFO Outage tnspection Scope. Including Scoping 04-7 worksheets, 40 20 60 8/2104 9/1/04 ENN 04-8 Developrentladoption of ENN-DC-315 Standard FAC program Procedure to include ali 80 40 120 6/2004 10/31/04 previous improvements identifed Self Assessments. 04-9 Ongoing Program Maintenance. Includes: procedure revisions. 160 40 200 611/04 12/31/04 program improvements, benchmarking, attendance at industry (EPRI CHUG) meetings, evaluation of industry events (industry ________ awLareness) 2_ Jar effects on VY. LR project input, and fleet supp.rt., TOTAL (From end of RFO 24 to December 31, 2004) 620 270 890 HRS Page 1 of 2 NECO37102
2004-2005 Piping FAC lnspeý.., mn Program Level 3 Fragnet YEAR 2005 (111105 TO 12131105) Preparer Reviewer TOTAL Est. Est. Task No. Task Description (HRS) (HRS) (HRS) Start Delivery f Estimated Estimated. Estimated. Completion Date ___ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Date (minimum once per cycle), Perform Program Self Assessmert 05-1 40 20 60 3/1105 4/01t05 Conversion of CHECHWORKS 1.0G models to SFA Version 2.Ix 05-2 360 180 540 4ý 1/05 9(01/05 REQ 25 Preparation & Outage Support 05-3 160 80 240 9/1 (05 11115/0504 05-4 Completion of RFO 25 documentation, develop RFO 25 Outage inspection Report 60 30 90 11/15105 12/31/05 05-5 Ongoing Program !taintenance. Includes: procedure revisions, program improvements, benchmaddng, altendance at industry 40 20 60 1/01/05 12/31/05 (EPRI CHUG) meetings, evaluation of industry events (industry awareness for effects on VY, and fleet support.,1_ _ _ _ _ Total 990 A- Page 2 of 2 NEC037103
VY Piping FAC Inspection Program PP 7028 2005 Refueling Outage Inspection Location Worksheets ! Methods and Reasons for Component Selection By:,eve~7 4 Note; Revised for VY and'Industry Events and Operating9 SRetienoe on 311105 Piping components are selected for irrsp&ction during the 2004 refueling outage based on the following groupings and/or criterIa, LAoe Borea Pining: LA: Components 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 EPR] CHUG. LD: Components selected to calibrate the CHEGWORKS models, LE:; Componerns stibjected to off normal flow conditions. Primarily isolated lines to the condenser in which leakava is indicated from the turbine pdrformance monitoring system. (through the Systems Engineerinrg Group)_ LF: E ngineering judgment/Other L[G: Piping id~htifiied froth EMPAC Work Orders (malfun*ctioning equip., leaking valves. etc.) 'Small Bdr. FPino SA Su.tusOibO piping locations (groups of components) contained in the Small Bore Piping data base which haVe not rDoived an initial inspectfin. SB: Components Celected from measured or apparent wear found in previous inspection res'ults. sC: CdM0pohsht$ fIditlifi y indtst4& -*t:/eeien'e via the Nuclear N*etwotk or tht ujh the EPRI CHUG. SD*: Cem*on* subjo.c.J.e*. to off normal flow. conditions. Primarily isolated lines to the condenser iniW.ich leakoe f [fdI dati-d kem th6 turbine perfbormnance monitoringsystem. (through thE6Sy,,tein Erin'ed6hg. Group). SE: Engineering Judgment I Other. SG: Piping identified from EMPAC Work Orders (malfunctioning equip., leaking valves, etc.)
..Feg*,ter H~eater 8haells No feedwater heatse thell Inspections will be performed during the 2005 RFO. A* 10 of the feedwater heater shells have been replaced with FAC resistant materials.
Page I of 14 NEC037104
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 1995/1996/1998/1999/2001/2002/2004 Refueling Outage Inspections (Large Bore Piping) these components wore icentified as requiring ltture monitoring. The following components have either yet to be inspected as recommended, or the reconmended inspection is in a future outage. Inspect. Leo. Component ID Notes /Comments I Conclusions No. . S.K. , . b o 8 001 FD13EL5S 1098 Report: calculatld time to Tmin is 11.5 12 cycles baod on a 96-19 . FD13SPOS single measurement. The 2005 RFO is 6 cycles since the inspeotion. UT insppet elbow. pnddorwbstream pipe In 20.08 96-3 G 002 FDO2SP05 1996 Report: calculated time to Tmain is 9.5 cycles based ona single measurernent. The 2005 RFO is 6-cycles since the inspection. _____ ULT Inp.,t ebw aft dp0wtStrenOM p04e in 20107 96-.7 005 FDO78POI 19016 Report: caicuftedd tirf¶8 to Tmri n i S9 cycloes based on a Single netasuirement, The 2605 FFO is 6 cycles sincethe inspectiOn, 96-39 0O5 FDOZSPO2US 1 K6O.prt:'uidnto Tti is" 0lSVdcyles "ion- based a !fe mea~surement. The 2005 RFO is 6 cycles since the inspection. ____________ UW 4otstta p
.0
.4p(Io 9e0-08 4$0$ 005 FQOELO-G 1.9vS Iopai Oalcilated time' tomi fisffl 7.-5'& 6.leycles base~d on a 9q8-07 FDO7EL07 slngle.mresuremern-t. The 2O0O5 -AFO is 5 cycles since the int ctio-n.
Given no .gignitcant.wear found in adjaceht compOnents (RSL =14.3 cycles otn FDOTSPO7) defer ina*ection until RFO26.+ UT" fi**0'e~t FO<J+-SP.O4 single UT inspection. The 2,.5.:RFO i 4 dycles sirce th-npct6n. 99-16 Oll 011 DOa.FSPO. 19mr Re:port:
, ud"u t tn IS6. aIJs. bat,.&.:.i-l0i
. ............. fi ..
FD1 4SP03 204., GIven that the only lOw aF.0 s wep at th grpeoiJ#.re h.atefs iocated under the.elbO.WLit inspct elbiw F.014&& _ _-_ _ ... r D. $y0 i .n.t.h,- D.S.. . - 99-32 017 F004TE0 I(pipe cap) 19i Fe port: calculated time to Tmnin is 6,2 &6.8 cycles based oh a 99-33 CND-Noz32-A single measurement. The 2005 RFO is 4 cycles sInce the inspection. UT inspect elbJow and.,d...Wpstram pip* In 2005 9945 019 FDO6TEO"I (pipe cap) 1999 Fleport: calculated time to Trin is 9,.6 &8.5 cycles based on a 99-36 CND-Noz32-C single measurement. The 2005 RFO Ls 4 cycles since the ihspelMion. ____________Ut- inspect Oaoi04.4 aul OWnstr am01w poip ini)0' 02-08 016- F 18IEL01 2002 rfecovmenridbn to inspect th*e*ebcw in .2007 based on a+siigle 02-09 FD18SP02US measurement. gte-inspect elbow and downstream pipe in 2Ui0(3 cytes from 9002,. p__ 04-03 -001 FDO1TEO5 2004 recommendation to inspect tee in 2008 based on the default wear rateof 0,005 inohtoycle, Re-inspect upstream elbow and tee In T__ DN02008.
't04-06 002 FDO2RDO1 2004 recommendation to re-inspect in 2011 based on the default wear rate of 0.005 inch/cycle. Re-inspect reducer with downstream
.... Ielbow and tee In 2007.
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(identifled) from previous Inspection Results -continued Inspect. too. Component ID Notes /Comments / Conclusions No. SK. .,
'0408 01 FD0* OI2004 recorhmendation to inspect Iei based on the default wear rate of 0.005 inch/cycle. Actual point tc point measurements from 1999 to2004 indicate no wear. Given EPU operation, re-inspect with
'__.pV*yetarn pebpw and redocer in 2007.
04-09 001 F03SS P.. 24reon'mendaf on to inhpedt pipe section in 20 1 based on a single inspection and the defauft wear rate of 0.005 inch/cycle. Re-inspect in 2911. 04-10 001 FDO7SP02DS 2004 recommendation to inspect pipe section in 2008 based on a slrn'g ins petion. Re-Inspect with downs.keam elbow In 2.08. 04-13 001 FD14SL03 2004 reccrhmendýfkWh to inpect flow 13 pup piece to DS alve In _208 is based on a sin.le UT inspection. Rie-Inspect In 200,. 04-23 001 M.D9TtO1 to 2004 recommendaftion to inspect plpe section in 2010 'due to localied MOSgEOS
.0TE8 weg.r directly under 2 lines..*OInqpq. I22I10.
- 04-23 001 MSD9EL05 2004cmme mr Uon to inspect pte section in 2010-base on a single Inspection. Re-ipspiect in 20*1d.
Tu~rbin'e ross-araund Pipino: Previous Intemal Visual UT & Repair i*story: ILine Mkat. Year I ia1Whg V it I=V , Ititetf T Thl~stis --VT, Re airs Perfoirmed=F __
. APoafer.s iWO if W
~~~~~................ AFOtO9 PIF02O nRoa2i RFC22 [RFO23 sieg I E.,ano;.F',
FISO -7__*L*J:**2** clsS -,.1000 82001 P2002 S0 04
.1 rz *:
- QE'
~tB~ai 3--
V v __ V vV V V v
$"CGi tgi V V V V V 3W-D.8 ~ 16 - V WAVT V -
- I YA . . ...........
'* 8 setion~s:r epjcb Iwfrh G E .SNUAR4.-E,elbOws .onthe &C lihe 0r~nl (3f5Espedl'ati f~*on D-5 OA '7 6.1 psekrvowon A -'&D)Ines a re 650.A-67E (Tn om =0, 6-P, ir!ch).
*3o" A,6,0 trepfa6&d wit A691 0L22 (2-1/4Cr), Fittings A234 W P22. (Tnomn. = 0.625 inch) 3W'S remains GE 650A242D, fittings and GE D50OA67D carb~on steel (Thorn = 0.50 inch).
NOTE: Reference Dwg, No. 5920-6841 Sh- I of 2'needs to be updated with correct information. This will b~e performed di~riK9 tho EPU do~slgn change effort, I-The HP turb~ine ro~tor was repl.ýce~d in 2.004. Internal visual inspection of all four 36"diameter lines was performed. An Internal vi-sual Inspection of the WC"' line (firsl inspectiorn since the 1993 replacement ) and the 30' D flhe was performed. 2005 RFO based on increased flows and the possbility of different flow regimes in both the 36 & 30 !inch piping, perform a visual inspectiont. LP turbine work in 20015 FIFO may provide opportunity for access to the 30 °lines. Ag a .mrinimnum inspect (2) 36 inch lines and the carbon steel 30" B line, J Pagep of 14 NECO37106
VY Piping FAG Inspection Program PP 7023 - 2004 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LB: Large Bore Components Ranked High for Susceptibility from CHECWORKS EvalUation The current CHEOWORKS 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 dala has been entered into the GHECWORKS 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 stilt appear to over-predict actual wear. Nothing new or unanticipated was observed in either 2002 or 2004. Feede,,ater Sstem. Listed below are components which meet the following criteria: a) rnegative tane to Tmin from the predictive CHECWORKS runs which include tnspection data up to the 1999 RFD. b) no inspections have been performed on these components or the corresponding components in a parallel train since [he 1999 RFO. 6Oort-nent '-Looction Location Notes Ft~07605 Od B P Iev. 2-41 C p o n;~v~e train were im~potd POW1EOi 006 I.8: Heater Bay El-ovs 228 Gonioonehts on dther ttaln were -intp:etedIn 1998, FD07ELI 1 & 248 Results indicate minimal Wear. After updating the CHI-IBOWO.Ks medvl with pewer dAta, assess need __________________for aqdffitJ.onaI jqqa 0tns in 7.~RO FFD0ZEL12 006 T.B Heater Bay Ulev. 248 Feedwrer heater replacement occurred in 2004 RFQ, Informal v.isual inspactions of internals and cut pipe profie in"dicated a stable red oxide and no distinguisnhable
.FD.TEO. ... 012 LB Heater By .Elevs 228 lnterr=i*lat cenipoheri-ts FD08EL06 &FDQ8SP08 W0r FbI8EL07 & 248 Inspeootd in 1998. Results irtdicate minimal wear'. Afti
'/
- up,.tIng CHE9 WOR:K*s model with newer data, asbsts need for inspecting componerits on tie train r~oS~Ol~012 .B3 Htt~er Say 91v Z46 Fe I t1?hetr *plaoem'n1 occurred in tX4FkQ S """Infor.a1 viul inspet*ions of internals ahn-cqot pip`e proflep Indi-*ted a stale red, oxide.andcno distfruif hable
. .. .. wear. pattrn4 FO5L 1'3. RX Steam Tunnel El. 266 lInte&nab,,4su oftelb6Wprfornd rn 19`96 d~dif4igbd valve WOptleement, no indiration of wall toss atihftitmie.
Corresponding component on line 1G% FDW-14 Was inspected in RF024. After updating CHlEOWORKS model with newer data, assess need for inspecting
*this com ponent in 2007 RFQ.
Page 4 of 14 NEC037107
VY Piping FAC Inspection Program PP 7028 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LB: Large Bore Components Ranked High for Susceptibility from CHECWORKS Evaluation - continued Condensate System "b ( Only one component waslidentified as having a negative time to Tmrin. This was CD30TEQ2DS, 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 system and relative to the upstream side of the same tee. Other tees on the same header have been previously inspected and show no significant wear. The CHECWORKS model includes UT data up to the 1999 RFO. The inspections on this syelem performed in 2001 indicate minial wear. Components CD3QTE02 and CD30SP04 were inspectibdc in 2004. This data along with the 2001 inspection data will'be input to CHEOWORKS to better cafibr-Ate the model, MoiutLresSenarator Drains & Heater Dr.in Sstem, NO components idehtified as having negative times to Tmin. No components were selected for inspection in 2001, 62002, or 2004 based on high susceptibility. However future operation under HWC will change dissolved oxygen in syst.*m Aseparate evaluation haMs been performed and components were selected for ihspection in 200Ž. See t Section LD below. Extraction Steam Systemn Thlree components on this system with negative time to code min, wall: The piping is Chrome-Moly. ES4ATEO1 & ES4AIT.02, 30inch diameter tees inside the condenser have negtive prediction (-3426Sfrs.) for time to .mii' wAIj-L(.e rneqhi6e tines to train may be conservative based on the modelin§ Ahnlques used, Reflnehent of tfb nodelbdf*ttis sgt-isl*h pr*o*gss. Thle nega.tive titn6 t.ltýih itpost likely a funocin- of tatk of inspection.data Vsi- ai W 'rly. .Due tn.exteihal laglng on this piping and the-locat!ion inside the con.dbnfser, no:conrpfle.nts are selecte."frtana; UTi-idpetion in 2004 based Oti high suscepflbiiity. HoWever, an op.rttunity to pedpo~rm an Mtrtna~lvia'daliltSp'eii of all tb4 EIracLion-Steam lirnes Inside the condenser dlring planed LP turbine work in te 2005:0b mriy:pr'teiu itsl4f. *6e Section LF below. Note the short section of straight pipe on line 12"-ES-1A at the connection to the 36 inch Across atound is. assupmid to be.Ai6O Or. B carbon steel is not modeled InC4IECWORK',. This compbnentwas inspected ih 2004 by external UT and an internal visual insgpeotiob from th& 36" cross around line.- Page 5 of 14 NEG037108
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 Events/Experience. Review of FAC related Large Bore Operating Experience (OE) and/or pipino failures reported since April 2003 Date ,Plant- Type Description & Recommended Actions at VY 8/9/2004 viihama 3 - OE193681OE18895: Rupture of Condensate line downstream of restriction orif ice. PWR PWR system highly susceptible to single phase FAC due to low DO. Similar region of system as 1086 Surry event (5 fatalities). Based on info gathered by INPO/CHUG/FACnet the location was omitted from previous inspections due to clerical error, once discovered rnanagement missed opportunity to inspect and deferred inspection until 9/04. Too late. Lesson: biake sure all highly susceptible locations get, inspected. PWR Condensate/feecMvater piping is much more susceptible to single phase FAC than SWR with 02 injectish. Given that, previous inspection history, and condensate CHrCWORKS modelitg; inspect piplpo Os of all flow orifices in the higher temperature condensate system -iathave teot b.een previously inspected in RFO25. Inspect.C03Xr=EQ1 I C0041)..11 / D0903S02 in hr.2g (re-peat -nspeoetion from t.Sr , Also1 inspectCD*if*OI /Ct$-ELO4/ 10/17/03 Duane Arrfold'- OEI17300: Through wall leak In 4" dia todutor chrome-mol Heaterr Drain Syýtem BWA bypass tine to the condenrser. The linevwas a temporary installation due to delayed FWD heater installation. The cause of the leak. appears to be droplet impingement erosion due to use Of a bypass control vlvi. TH-equivalent fkles at'VY are the Heater Drain bypass lines. to. the condepsardow rei r 6 -r hibh
. h .aevl 01 cotrl ValVes. These flne have9STL.".attached sa .monitor 6dkag... into th c .d.ser
(, (Ti ttem:). S*me"i*.phriops. havet hr.en k .**:tn .o .l . C.slfdtr for pirem~ent. PWR..system .Low dissolved . x.e. E s.. . .'
-qu.ivatents Is Condenate (Thm.'inerai;.zoer System which is. I*w ter.'p. ai*" screerW .,.prr.NAC4*O2L pI, dir trsyte chitif rhalw0..tefoemr*a I& $os furne alctin ar a tfiojal h Thi OM .
U0 __(I____
* . A. ft., ,-ite-s. A 4 t ht t 6" M, !") 't. r
( cause attributed to steam let impingerrment from wet steam. Equivalent tine at VY is common 4 inch feedwater heater vent line for No.4 FOW heaters. This line is included in the SSB database since it connects to (2) 2-1/2",lines. Inspection prority be .etermined swill . in th. sma.l b.re rank.. an.drioritizaion. 1-lope Creok -
.1/1/3 0 aExtraion BWR supply line to Steam Seaal Evaporator. Location of wear is downstrea of pr.essure saefty valves. Apparent Cause of leak &wear is dut to liquiddroplet impingemetfl due to high flows from failure of pressure safety relief valveM.No equivalent configuration at Ml.
1/24104. i LaSalle - BWR OE7149 1 OE1-8381: Tough-wall holes in extraction steam piping inside cnden*er. Location of holes at inlet nozzles to No.2 FDW heaters located in the neck 01 the condensers (i lowest stage). All 12 nozzle are CS. with A335-Pl11 upstream piping. VY has only the No.s FDW heaters in the neck of the condenser The No. 1 FOrW heaters were replaced with Chromo-moly shells. ES piping is A335-P1 1 or safequivalent which is FAG resistant. No further actions are anticipated from.This OE.
*fPage rofa,4 NEG037 109
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Sefection LC: Large Bore Components identifled by Industry Events/Experience - continued Date Plant -- Type Description & Recommended Actions at VY 2/17/04 Peach Bottom 2 OE18637: On line leak in 10 inch main steam drain line header to the condenser. BWR. Hole was located directly below the connection of 1"'mhain steam load drain. The header was replaced with 1-1/4 Chrome material approx. 5 years before the leak. Also, ROs in steam drains were modified. The cause was attributed to steahi 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 LCVs vs. a continuous flow through a restfiction orifice, This line is now part of the AST ALT boundary. Inspections of the entire bottom of this header were performed during ARF024 with recommen~dations for ___repeat uiedtions 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. Proble ms with inspection of flashing tees in propram, Only 14 out of 153 susceptible kicatikns have LUT data at Palo Verde 1,2,3. There are no flashing tees D.S. of LOVs on the heater drain system at VY. The only flashing tvee, at VY are located on the FWD pump miin flow lines at the condens'r. !nso*t'i0n of all .ine _______ 'P M A"POW-5 an-d. 6"F.W6 is soheduled for RF025. O124iO4 Palisades- PWR GEl ýA4S4 Well thiinning in carbT--n steel Extraction Steam' piping. Increa~sed localizted wear downstream of Bleeder trip valve. Equivalent piping at VY' is Extractio 1Steam: piping dbwwnstreatn of the revdese current valves. E9 piping at VY
.iS.A$1*-Pi I wbjhe* iss;FAt r tant. Nd:ufter ati~dis ?oquifed fol(tli O.
9/18/04 Caltawaba 2 - QE1ýftn PS:Wl hnigfudfu area~s on FOW piping. TWiO areas,are PWR not considered spbcifii to Catawba I)Area w*h*t4 rahn feedwaftor byp.*.s r" g valves roo.ntjrsfeedwater valves.. PWR the feodwater systemheader and 2) doWnstream chemnistry-has.16w ol the main*tb D;.C. therefor'e ft.Ater reg m.ore: susceptible to wall toss que to single .phase :FAG than BWR feedwater piping. At V'(area 1) dosesnot eist (bypa~s lin.sd-dump to the iobn".*&sr) 2) lnsp ections h1avee-'ben perfom.ed upstragm apd downstream of.both maine.6d 1rep. valves. l tI.it of SWR Valve, Apparent cause was pavit"ilon eerosion due to fhtofling. invalve dur.ig KPC,
&"Ctg.iunp. At VY, th-equi*,aeht V-lVes are VioM34A &A34R. The d gre of caVitation-present is dophndent of the systeim design and may vary from pl*tit to pla.nt. Previous' UT inspections were performed on valve bodies and downstreain reducers in early 90s. No significant wear was found. Consider inspectl0n of downstream piping In RF026 if additional OE warrants It.
2/610 Ca... lvert Cliffs,l'- O-E20127: Through-wall leak in 6 inch steam vent header for MSR rain tank. VY PWR does;not. have sanie confg [u raion. No Moisture Separator Re-heaters 2/17105 Clinton BWR OE2R246: Catastrophic failure of turbine extraction steam line bellows inside condenser. Found through-wall holes ES piping DSof bellows due to VAC. Apparent cause was attributed to the steam jet fr.m the holes induoing vibration of the expansion joint that led to hih cycle fatigue failure. At VY extraction steam piping inside the condenser is A335-P1 1 or equivalent which is FAG resistant. No further actions are anticipated from this OE. 6/9/01 Grand Gulf - Pin Hole Leak in 4 inch carbon steel elbow in PHR amin 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-Pari 14 Shtl /1 and VYI-RHR Part 15 Sht.1 /1 show elbows downstream of restricon orifices- Previous VY Inspections downstream of orifices on HPCl/and CS systems found no problems. Keep OE listed for future consideration. Page 7 of 14 NECO37110,
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LO: Large Bore Components identified by Industry EventslExperience. cpontnued
-A, Date Plant - Type Descrption & R*6com mended Actions -at VY 9/24102 TP2 - PWR Pin hole leak on 26 1/" cross-under piping (HP to MSR) in vicinity of dog bonos at expansion joint under location of weld overlay localized wear undedarourid a previous weld overlay repair. VY has solid piping (no expansion joints). Visual Inspections of 30" B CAR carbon stel will be perormed In 2?05.
1/15102 Surry 1-PWR Leak in 8 inch Corndenser drain header for 3 14 pt. FOW Healer vents. Also CHUG thinning in Gland Steam Piping inside the condenser and thoI2" Condenser Drain Meeting header from MS Drain trhp 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 boundary. Inspections of selected components on this line Were performbd during RF024 with recommendations for repeat inspections in 2010 (Section LB above). Given this line is part of the ALT Boundary Inspect approx. 2 it. long seetlon at condenser wall during 91702t {Q07) or RFO27f(2008). . LD: Large Bore Components Selected to Calibrate CHECWORKS The CHECWORKS models have been upgraded to include the 96, 98, &99 RFO inspection data. The 2001 and 2002 inspectiohndata has been loaded however wear rate anaiyses have not been completed at this time. Con~densaite: In 2.001 co.hpdnerits o6n the higher temperature end of the Condensate System. were Inspected to calibrate the CNEOWOR** The inspection data indicate minimal wear and should reinforce the ass'essm.et of *ow wear M.*'mels,. in the Con:densatey'.ysm. Additional comporýn!ts selectedfor inspection in 2004 in Section LB above will I50 used to cAlibrate -the CNECWORKS mod'eL K Hgeter. Dtaint ... M.oirea Separator Drains:
- Pribr **l 12002.RFO there was limited inspection data for the Heater Drain system. The current CHECWORKS rn.*l4("* i *tb..s'.ndore Pass 2) indicate low wear rates, During 2002 a number of new Inspections were p-tsimd o!.n th1 cirb6n steelkpiping upstream-of the level controlo.valves (LCV) to obtain a bel61ine:pr~iorto operation 6'.hydoen water chemistry. fiping down stream of the LOVs is FrAC resistant material except torhlet 1b N6.5 Feedwater heaters. No additional components on the Heater Drain system will be inspected in 2005.
Feedwater: , No inspections on line 18"-FOW-12 have been inspected: Inspect FD12ELO6 and FD12SPOBUS 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. Inslpect MS1 DEL07 and f4S1 DSP13US in 2005. (Note this also addresses a ficense renewal consideration for monitoring of Main Steam Piping). Page 8 of 14 NEG037111
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LE: Large orfe Components subjected to off normal Hlow conditions Identlfled by turbine performnanie monitoring system (Systems Engineering Group). The Systerhs Engineering Production Variance Reports for 2003 listed the "S' and "C' fpadwater pump min flow valves as leaking into the condenser. There are sections on carbon steel piping at the connection to the bondenser on al three lines. As a minimum inspect the "13" and "C" lines in 2005. there have been concerns with cavitation at condensate mnirlflow 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
=onnecting piping wavs flooded and an internal visual inspection could'not be performed. UT Inspect the upstream an d4ownstrtam piping during RF025. The valve is operated during outages and startup at relatively low temperatures for FAC to occur. The piping is un-insulated and close to the floor. No infsulation removal or scafolding will be r.quired.
Since startup from 2004 (RF024), no other leaking valves or steam traps have been identifled (to date) using the Tuitfin& Pertfermance Monitoring (TPM) system. However, if.new data indicates leaking valves then, additions to the outage scooe may be required. LF: Engineering Judgment / Other Nihna AWME Section X1 Class. I Category B-J welds are to be inspected by the FAC program per Cod6 Case N'560 in ff6uof.a.$.ctflon XI volumetric weld inspection. ,The VY 1$! Rrogram Interval 4 schedule for irinpedi6n of the WOIdsl is as fdllws:, RFTUh Outage Section Xl Description FAC Program Components Is. Pro.gram Weld a." I upsBstreý#am .pipe to tee =A" Feedwater on Sk'ewh 010 FW19-F30 teato reducer Fl) i 9TEO1 Iritiv14 FW1g-F4 redpcer to pipe FD1gRODI.
.tPr"o01, .FW21-Fi tee to pipe FDlI9*0P4 Outage 1. 5:D21SPO0 Fall 2011 (R0O29) FW 15-3A up-tream pipe to tee "B"Feedwater on Sketch 016 interval 4 FW20-3A tee to reducer FD18TE01
,Period 3,, FW20-FI reducer to pipe FD20RD01 -. Outage 6, FW20-F1B horizontal pipe to pipe FD20St501 FW18-F4 e e. FD1OSP4 Continued Page 9 of 14 NECO37112
VY Piping FAC Inspection Program' PP 7028 - 2005 Refueling Outage
\.Inspection Location Worksheets I Methods and Reasons for Component Selection LF: Engineering Judgment/ Other -continued Extended Power Uprate (EPU)
Feedwater sLstem: EPU evaluation for Feediwater System: The primary focus of work to date (for PUSAR and RAls ) was on veNocity. changes given only.slight increases in temps and no chemistry changes. With all 3 FDW pumps running the 16 inch diameter lines to the 24 inch FDW header have approx. [1.2(2/3) = 0.80120% reduction in velocity. Vel6cities inthe remainder of the system increase approx. 20%. The highest velo0ities are at the 10 inch reducers upstream and downstream of the FDW REG valves. The expander and downstream piping have multiple inspection datlawith FDO7RDOS/FDQT7SP03 last inspected in 2001 and FD08RDO3/FDOSSP02 last inspected in 1999. Both of thesja segments shduld be re- inspected after some time of operation at EPU flows. Assuming EPU starting early in 2006, inspect compo'nents FP00003 & F008$P02 in 200D to obtain an up to date pro-EI'U mreasureih&t. Inspeot FD07RD03/ PD07SP03 In 2007 for a post EPU measurement. 'condensate .Systefm Given the 8/04 Mihama event: consider additional component in the condensate system for inspection: downstream of ftlw orifices & venturies: FE-102-4 and downstream pipe on 24'C-8 venturi type (TS condensate pump room overhead) Gtven lo opfe-ating ternper~tmrs and upstream of oxygen injection point, scope oLut and evaluate for inspectloln -In RP026.In 2007 FE-52-1A to FE-52.1 E on Condensate Pemei'atzer System ( Restriction Orifices). Given low operaotig temWierntures and upstream of oxyoen injection point, scope out and evaluate for FE-I O27and denvnsttoa pipe on 14'.C-21 venturi type TB Heater Bay El 237.6 Given low ope.rating teshperatures and usedfor start-up, sc*op out.AhndevOOiVa.6f or inspectiob in RFO26 IJ 2*47 FE-102-2B on.21YC-31, t*c*ttd in the TB FPR Above FW puMp IB (ventUri type) No previous inspection data. rnspeot FE and downstream piping in 1t025 FE-1 02-2C on 20"C-32, located in the T1B PPR above FDW pump 1C (venturi type) Previously inspected in 2001 All Extraction Steam piping is A335-PI 1, a 1-1/4 chrome material, except for a short carbon steel stub piece in line 12"-ES-IA at the connection to the 36' A cross around line. An internal visual inspection of this stub piece was performed with the cross around inspection in RF024. Also an UT inspection of ESI ASPOl was performed in
- RPO24, Extraction Steam piping in the condenser has external lagging which requires.significant effort for removal when performing external UT inspections (plus there are significant staging costs). The piping is A335-P1 1. However an
-pportunity to perform an internal visual inspection of all the Extraction Steam lines inside the condenser during planed LP turbine work in the 2005 RFO may present itself-Page 10 of 14
- NEG037113
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I 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 were performed for the followngykeywords: trap, leak, valve, replace, repair, erosion, corrosion, steam, FAC, wear, hole, drain, and inspect. No previLusly unidentified components or piping were identified as-rquiring monitoring during the Fall 2005 RFO. 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 05-2ý32 IER 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 inspected in 1990. The line typically has no flow. Re-evaluate using the Thermal Performance Monitoring System Data and consider inspeotion RFO26. of downstream piping in Through wadl le-ak in the steam seal'header suppy line 1SSH4 discovered on 9/24/04 (CR-VTY-2004>02985). A temporary leak enclosure was instaIfed and a planned permanent repair is scheduled- for RFO25. The leaks are on the bottom of un-insulated piping upstream of the gland seal. Field inspection of the leak location shows that the piping at the leak slbping down to *the gland seal, not sloping up to the seal a shown on the design drawings. UT data on the top of the piping P6ier the leak shows full wall thickness. At this tirine, the exact mechanism which ciased the leak is not known. Additional inspections to determine the extent of condition on the 3 other gland seal Mteam supply lines ate required lhnspectthe 90 dleree elbow and approx. 2 ft. of downstream piping on lines 1SSH3S ISSIH4, 1SSHS, and 1SRH" durihng.*FiFO.*Ž. Also based on industry OE and simiiar piping geomeiry, inspect 2 of the EPE lines (1SPE3 ~and rFQ 25.
.1i'.Prduring *
/
Page 11 of 14 NEC037114
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection Small Bore Piping
,2 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 condenser 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 time. No wear was found in pirevious 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 of the No. 4 heater'vent piping can be deferred. The existing small bore date base and the piping susceptibility analysis is under revision, No additional components from Revision I of the d6ta base will be inspected. SB:Compoheýt*tseiecteld from measured or apparent wear found in previous inspection results. Small Bore Point No. 20. 2-1/2'r MD-6 @ connection to condenser A at Nozzle 33 (Inspection No, 96-SB01 Oiehtified a low reading.at wetld on stub to condenser). Upstream valves are normally closed- TPM system does not indicate any abnorminal flow. thspeot this piping in RFO 26 A through wallt leak in the turbine bypass valve qhest 1" sea le k-off line form the No, I bypass vales occuried in M0O.. (VY Event Report 2003-04 A temporary leak enclosure watslJlstled (T.M,20G3tOi2) to contain the leak). VV.0.03-0"34 was Writt'n to inspectlrepar.lreplace/line. A looaliz lik6-foýlike (carbon steel) replacomhbnt of the leak location W9s performecd in RFO 64. Additional inspec¢tiens on this Uoe ?deorfifiiZ 10oa.liebd Wall kicss and tne additf6rihl like-for-like redpalr was performed. Engineering Request ER 04:0963 was writteh to coiinpietely replace -t9 pifs i 6r1 With h*riome-rnmo piping. (Dresden has already done this). The ,rOeptacaient(ER 04,0964) is cutrretly slthbduted for RF.O V2. if this acivity g.ts '"de.*ooped'"theft, additional inspections will be reirWired to i6sre' the p0ioiitg is aeiij te for co'tin ued pPg12tioof1 Page 12 of 1.4 NEG037115
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection SmnalI Bore Piping SC: Components identified by industry eventslexperience via the Nuclear Network or through the EPRI CHUG. Dal.e.... Plant - Type Description & Recommended Actions at VY 1117/P2003 Limerick 1, OEl7818: Through wall leak in 1 inch drain line'back.to condenser off ES piping BWR at the connection to The large bore line. Normally no flow in line due to NjC. valve. Piping downstream of valves to condenser on all 3 lines was scheduled for replacement. Location US of valve was thought not to be susceptible. ES piping at VY is FAC resistant A335-P1I1 with no drains back to tihL condenser. Lesson from this event is any carbon steel line in a Wet steam
-systemis susceptible &should be monitored. Also lull line replacement insures all susceptile.pipiP9 isereplaced.
1116}04 Clinton - BWR GEI 754: POtehtiWl terid for adverse equipment condition downstream of orifices. (Ref. Previous experience a'Clinton with CRD.pump mrin flow ROs) Inspect CRD pump min fkworifh'es also piping !)S of RO-64-2 in fl"O2S _n__ 1.006/04 V.C. Summer- 0E1iF78: Comp-let failure ola 1 inc'h ES lihe at the ocaijoni of a pfvio-usly PWR installed Fetmanite clamp repair. Previous leak at weld installed in MAY'2004. See presentatfon at January 2065 CHUG meeting. (Thay did hot do UT on fthe ppe. to as.sur, struottural intqe9d,,f,.;Riq to instalIing thie clamp.) 3/1/05 McGuire 2- 'Thotigh-wafl aJkin a 2 inch carb*n ste'l vent- ine on the'MSR healing steam PWR vent line. Cawus. .y FAG when tashinqo urred upstream of Rd (d6gibn
.n,,).tNo.MSRS or Rqfy/jhnt looli6n at.VY.
4/29/99 Darlington 1 - S... . ine at*..arapddý .. aýthta.ed conneCtion. Equiylt to PHWR HHS sy.st at VY. (INPO:Event 931-99042*-1) Thre.adedconnections typicalý Hon natG gidl of HS..iSpiping. Lower eanorgy/cosequehce 6f l.dk. Include ind6 HHS piping. 6 FAC Sueptibtllty-Reviemw,. and in thiC.Small Bore Oatdba'se. 6/14/99 Datridgtorl 2- L!a oh steam WaP discharge"p6..tIh ied cohn-etion.E-uivettb HHS PHWR sytem at Vy- (INP, E..yen.08P. .00614-1)$ame as abve . . Bottom (From 1/14/02 CHUG. Meet.ing)k.on 1 mt $ .;IJ..l.fot h'Off Gahr s Re-9t/101 3Peatch
-BWR cO'mbinir.#i .leheterd*Ji.a.in!)iirt*to c.derfl'er . r.,tr*.adct6ftinlrev9iew 6tAO"G sml tor gpttato ýki0 ribndasquneoffir
-qud 111U0 Hatcli/2 -BW RiCondanser in d-kh ondue16 hoedah nel h uni-ot (eie of*1'1/2 in'h 4slop tdrainslaine inside the onditnso. lines In e1ach unit were out1: and 6.**0d simrilar enVYsp at %rn ounit iid - 1'*2` o6E and nse Columbia (0E1214ý.'5. imrick &
DredOn4. So slop drain lies inside condenser ware walked down during RF024. Some external eCoshlo on piing and supports was found. 11 5/02 Catawba 2 - Leak in HP turbine pocket shell drain 1 inch tia. OEM showed pipe as P-1lne CHUG Mtgn PWR However, A-10 Gr. n was installod. Inspections were be peruormid on thiseline ____/02 Dresden 2 2004 to base line con.ition plor to HIP turbine rotor replexmenstt. Thinin 1/15/02 Dresden 2 Thihning found in Bypa"ss 8,-of valve I4ne to the 7raistage x0 faction stigam CHUGP Mtgs BWR line, Line is 2 80, GE 4A39B. Lowest dSoah. reading wais 0.070P'-fund using Phosphor Plate radio~raphy. Une was replaced with*A335 P-il1. Samre line as 2003 VY.through wall leak. Partial CS replacement was performed in RF024. Piping is scheduled to be replaced'with A .335-PtI in RF025 (ER 04-0965). Page 13 of 14 NEG037116
VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection Small Bore Piping SD:Corrlponents subjected to off normal flow conditions, as indicated frotirthe turbine performance monitoring system (Systems Engineering Group). No small bore lines have been identiqied by Systems Engineering on or before 3/1/05. Se. SE: Engineering judgment Look at piping DS of orifices based on BWR OE Condensate: Given the 8/04 Mihama event: consider additional component in the condensate system for inspection downltream of flow orifices &venturies. IFE-102-6 and downstream pipe on 21?2"C-43 venturi type (-I- heater bay elev. 2,30+- Given low operatihg temperatures and upstream of oxygen injection point, soope out and evaluate for In spetion [ih 516 in 2007> SG: Piping Identified from EMPAC Work Orders (malfunctioning equip., leaking valves, etc,) See LO above. The EMPAC aisearch performed in LO above is applicable to both Large and Small oompdi'iets. 1/2_ K
-I Page 14 of 14 NEC037117
MEMORANDUM Vermont Yankee Design Engineering To S.D.Goodwin Dote May5,_2005A From James Fitzpatrick File # VYM 2004/007a Subject Piping FAC Inspection Scope for the 2005 Refueling Outage (Revision a.) REFERENCES (a) PP 7028 Piping Flow Accelerated Corrosion Inspection Program, LPG 1, 12/6/2001. (b) V.Yý Piping F.A.G. inspection Program - 1996 Retueling Outage Inspection Report, March 23,1999. (c) V.Y. Piping F.A.C. inspection Program - 1998 Refueling Outage InspeotIon Report, April 2,1999. (d) V.Y. Piping F.A.G. Inspection Program \1999 Refueling Outage Inspection Report, February 11, 2000. (e) V.Y. Piping F.A.0. Inspection Program - 2001 Refueling Outage Inspection Report, August 11,2001. (f) V.Y. Riping F.A.C. Inspection Program - 2002 Refueling Outage Inspection Report, January 20,2003. (g) V.Y. Piping F.A.C. Inspection Program - 2004 Refueling Outage Inspection Report, February 15, 2005 (h) DISCUSSION , Attached please find the Plping 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 judgment. The planned 2005 RFO inspection scope consists of 37 large bore components at 16 locations, internal. inspection of three legs of the turbine cross around piping, and 5 sections of small bore piping. Also, any industry or plant events that occur in the interim "may necessitate ah increase in the planned scope. I will be available to support planning and inspections as necessary. If you have any questions or need additional information please contact me, (Revision 1 identifies Small Bore Inspections due to Industry OE).
- (Revision la adds component Nos, to SSH & SPE piping & corrects Tinor typosin Attachment
*m-s . Fitzpatrick DEen Engineeriing Mechanical/Structural. Group ATTACHMENT: 2005 RFO FAC Inspection Scope 3/11/05 (3 Pgs) Revised 515/05 CO - Liukens Code Programs Supervisor D.Klng (iS)
T.M.Oconnor (Design Engineering) Nell Fales (Systems Engineering), NEC037118
N ATTACHMENT t,.-.,JYM 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 Inspections 2005-01 FD_4EL03 008 .B. Htr. Bay Elev. 267, 1999 1999 recommendation for repeat inspection. 2005-02 F..FD4SP03US 008 " ' 1999 _2005-03 FD04RD01 017 lB. Htr, Bay Elev. 245. 1999 Inspect per 1999 calculated wear rate. 2005-04 FD04TE01 017 .F 'C U' 1999 2c005-05 Cond Noz 32A 017 " " 1999 2005 FDS5R_[DO1 018 T.B. Htr. Bay Elev. 245. 1993 TPM system indicated- leakage by normally 2005-07 FDOS TE01 018 " - " = 1993 closed valve. 2005-08 Cond Noz 328 018 1993 2005-09 FD06RD01 019 T.B. Htr. Bay Elev. 245. 1999 Inspect per 1999 calculated wear rate. Also, 2005-10 FD06TE01 019 "F " "F 1999 TPM system indicated leakage by normally 2005-11 Cond Noz 32C 019 .. .. . 1999 closed valve. 2006-12 FDQ8RDO3 i01 T.B. FPR Elev. 231 1999 EPU flows increase 2005-13 FD08SP02 011 Oi l4 1999 2005-14 FD12EL06 007 T T.B. H-*r. Bay Elev. 264. NO Cheoworks Model Calibration: Asbestos 2005-15 FD12SPOOUS 007 . .. . NO removal required. 2005-16 CD3QFE01 037 T.B. FPR Elev. 241 1989 FE-102-2A (Mihama Event) 2005-17 CD30EL11 037 above "A" FUW pump 1989 2005-18 0CD030SP1 2, 037 ..... !1989 NEC037119 .!1
ATTACHMENT tV.. IYM 2004/007a Point Component iD Location Location Previous Reason I Comments I Notes No. Sketch Inspections 2005-19 CD31 FE0 038 T.B. FPR EIev. 241 NO FE-i 02-2B (Mihama Event)- 2005-20 0031 ELO1 4 038 above "B" FDW pump NO Asbestos removal required. I 2005-21 CD31SP04 038_ NO 2005-22 CD21RD02 040 T.B. Htr. Ba1y EIev. 230. NO Inspect piping upstream and downstream of 2005-23 CD21RDOI 040 NO FCV-102-4 (piping is not insulated).
'2005-24 1SSH3EL05 Turbine deck at packing NO LP Turbine Steam Seal supply lines due to 2005-25 I SSH3SP06U$ 3 Mrt. ?ay Flev. 254. through wall leak at elbow on line I SSH4, 2005-26 ISSH4ELO1 " Turbine deck at packing NO 2005-27 1SSH4SP02US -4 Htr, Bay Elev. 254. *See markup of Dwg.5920-1239 2005-28 ISSHSELO1 Turbine deck at packing NO 2005-29 1SSH5SP02US S 5 Htr.. Bay Elev. 254.
2005-30 1SSH6EL06 Turbine deck at packing NO 2005-31 1SSH6SPO0US
- 6 Htr. B*ay Elev. 254.
2005-32 2SPE3ELO1 . _,__ Turbine deck at packing NO LP Turbine SteamPacking Exhaust at packing 3 2005-33 2SPE3SPOI'US 3 Htr. Bay Elev, 254, and 5 due to through wall leak at elbow cn line 2005-34 2SPE5EL01 " Turbine deck at packing NO tSSH4. 2005-35 2SPESSP01 US t 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 M S 1D SP13US 080 254 to 260 NO ...... ....... __........ ...........
- LARGE BORE UT NOTES:
- 1. Coordinate minimum extent of insulaion to be removed with J.Fitzpatrick or T.M. O'Connor iron DE-IVS.
- 2. A Nho" in the previOus inspection o00Lumn indIcates asbestos abatement may be required.
Page 2 of 3 NECO37120
ATTACHMENT to VYM 20041007a LARGE BORE PIPING; tnternal Visual Inspections (with supplemental UT as required Inspection Point No. Description 2005-38 36" CAR A ( 38 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 diameter Line B Turbine Cross Around u per ast side of heater bay) SMALL BORE PIPING Smal! Bore S.D. System Description Location Drawings Reason /Comments Inspection Data Number Base No.-_ _ _ _ _ 05-SB01 119 Condensate 1" piping DS of Rt-0 64-2 Heaer Bay Sht. 1 n.B. OE17654 nG191t57 idustry 5920- FSI - 17 05-GB02 128 CRD 1" Piping D.S. of R.0.-3-24A RX. SW Elev. 232,5 G191170/G3191212 industry OE17654 P38-IA (G191215 05-$B03 129 CRD l"T PipipD.S, of R.O.-3-2PA Rx. SW Elev. 232.5 G191.170(G191212 Industry 0E17654 P38-IA 1,G191215 05-SB04 130 CR0 1"Piping D.S. of R.0.-3-24B.. Rx. SW EIev. 232.5 G191170/G191212 Industry OEt7s54 P38-1B /G191215 1" Piping D,S. of RQ.-3-25B Rx. SW evl.232.5 G191170/0191212 [ndustry 0E17654 I 05-S05 131 CRD)
....... P38-1B fG191215 Page 3 of 3 K
NE0037121
(COLUMN LDE F) MATCH L0ES St 4 HFJo. REVISION 1, t1/24/91 18' QI.A OUTLET VERMONT YANKEE PIPING EROSION-HIOZLE HeAt* E-A DCe v CORROSION INSPECTION PROGRAM cnt F:EEOWATE=R LIWE 15'-FOW-lt-TURBIN3 BtUILDINC'+IEATER BAy REFERENCES, 01919157f0191182.G92183,5928-,FS-125 COMPONENT LOCATION SKETCH No,088 " I Appendix A PP 7028 Original Page 13 of 102 NEC037122
0 Appendix A P? 7028 Oxiginal Page,- 2of IO2 ' NECO37123 : I .
3/4 3oo r-cj g Zc'oC-oZ VERMONT YANKEE PIPING EROStON- * -4 CORROSION INSPECTION PROGRAM TiUR*nBE B&OING-FEED PUMP ROOM/HIEATER BAY FEEDWATER LINS 4'-FDW-5 REFERENCES G 191 157,G I19 132,G191 103 5950-FS-24,5.920-F S-125 COMPQONENT LOCATION SKETCH No.018 Appendix A PP7028 Or"simal Pate 23 of 102 NEC037124
o,.. FDW FA 6EL2 9
- s > s zI OMEA J*ATER BAYs CO RO IO INP~ PRO RA M TUROE BtA.tNG-FEED PUMP ROOMMEATER fAY FEraDWATER LINE 4' -DOW%
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.--- COMPONENT LOCATION SKETCH No,O(9 !
Appendix A PP 7028 Origimnil Pag 24 od 102
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rZZ6 ~ t\$ PIPING EROSION-VERMONT YANKEE VERMONT YANKEE PlPING EROSION-CORROSION INSPECTION PROGRAM FEEDWATER LNE I1'-fDW-8 TURBNE BUILD.NG-FEED PUMP ROOM REFERENCE$. G191i 57,G 197012,0191 18:,592O-F5-14 COMPONENT LOCATION SKETCH Nafl01 I Appendix A PP 7028 Ohoiinma Page16 of 102 NEC037126
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*ATER E-1-JA FDI2sPIO CORROSION INSPECTION PROGRAM FD12SLOS
-C" EL 251'-4&REF Po 120.0O9 FEEDWATER LINE 18' FDW-12 si~ TURBNE BUD1DNG-HEATER SAY COMPONENT LOCATION SKCETCH No.=07 RFERENCEEC G19i1157,GG19182,GIYg1 B3,59204Fs-125 Appcndtx A PP 702.8 Original Pag*c 12 of 102* NEG037127
Appeddix A PP 7028 Original Page 42 of 102 NEC037128
*a, FLANGED SP*CFL 3ICE 16'X2Zj REDUCER I
FEEDWATER PUMP VERMONT YANKEE P1PING ERO9ON-CORROSION iýSPECTION PROGRAM CONDC)NSAT LINE 20t -C-31 TURBINE 6"DING-RE)WATER PUMP ROOM st'
REFERENCES:
G191 157,G 191188,0 191 1o87,,.2-FS-1* 6 COMPONENT LOCATION SKETCH No. 0:38 Appendix A PP 7028 Original Pare 43 of 102 NEC037129 -I
K*__ C1 B ,COMPoNNT LOCATION SKETCH No.040 ~~~RWERENCES, 2t1*CJ!:8, 9Hg5"(F-2 Appendix A PP 7028 Ordgirwl Page 45 of 102
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VERMONT YANKEE V 4-SCOPE MANAGEMENT REVIEW FORUM Date, iI/Ifl.... Tracking Number:- ------ (Assigned by Work Scope Control Coordinator) Work Order Number: .f4z-00$g*S2*0 Location of Work to be Performed: ADDITION DBLETINA* CH-kNGET3 Description Justificalion for Request Mq1 S1V.tXlb LkdŽOE t Review Process Additional Cost: Duration and Schedhling Impact,. Assigned Dept./M~a-nloums to Complete',-_- Source of Manpower/Other Scope Impacted: Dose, Chemistry, Safety Implication: Engineering Impact'-Man-Hours/Engineering Dept.. .... Optional Ways to Address: ........ Approval Process Please provide a brief jusfification Sc~ope Re~view CommitOtee Rcoaommeanda tionlPlanning Priority. __ ___________ __ Priority "C" WO Responsiblt Dept Ajproval General Manager, ((0 Plant Operations:_ .isapprove _....... Date: EMPAC Change Made forE t Piit~___ SCC Date Log Updated: Copies to Work Control, Outage Schedulin t2.. *2.., VYPPF 7102.01 PP 7102 Rev. 2 Page I of 1 NECO37136
Prepared By: James Fitzpatrick Date: 11/1/05 RFO 25 FAG 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-05-0190 CR-VTY-04-2985 CA3 Backn-ound: CR-VTY-2004-02925 documents a steam/water leak on the turbine steam seal piping, line ISSH4 to the No,4 packing. TM 2004-031 installed a temporary teak enclosure on this fine. inspections on Turbine Steam Seal Piping were included in the scope of the FAC program for RFO 25 per CA3 of CR-VTY-2004-02925. The purpose of these inspections is to dete'rmlne the extent of condition on the remaining steam seail 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 lagging 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). Discussio~n 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 on 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
Dlate: 9128/05 E nntergy Replacement, of N4 Steam Supply Piping Work Order 04-4S84-06 TM 2004-031 ER 05-0190 The steam seal supply line to TB-I-IA, N14 packing developed a leak from what appears to be _the result of pipe erosion on one of the pipe radiuses. Team Inc. was contacted to develop on-line repair options and determined that the mosC appropriate long term repair would be to install a pre-fabricated clamping device. The clamp was fabricated as recommended and successfully installed per the above referenced Temporary Modification (TM 2004-03 1). 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 and installed. To facilitate this 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 removeinotaU piping and deck plates. LRI' rInelm Sndteam Seal PipQ_ RepD~ejjnswip During RF 25 a significant amount of work will be performed on the LP turbines which are located in the immediate area of the degraded N4 steam seal supply line. The LP turbines will be completely diimantled to facilitate the installation of the new 8 tb 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. NECO37138
Prepared By; G.Benedict Date: 9125105 The following representsthe specific issues'that will be present during the implementation of tile N4 steam seal line replacement and the L? turbine inspection: Personnel Safety:
> Fall and drop hazards will be created by both work crews in proximity to both work ar6as. Open holes will exist on the turbine deck appearance lagging deck plates and in the area between the LP inner casings and exhaust hoods. Although, personnel protection barriers and 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 progresses and although prsonmel 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 aotivity.
> The crew working on the steam seal piping will continually be interrupted due to overhead hazards from materials being removed and returned to the LP turbine centerline. Once again due to-the pace of the UP turbine inspection and the fact that the steam seal piping replacement crew will be in and out of the work area which is not visible from the turbine floor only increases the potenti al to inadvertently transfer a load over the piping replacement crew.
Equipment Safety and Quality:
> The removal and installation of the steam sealpiping 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 %sunps,exposed shaft journals, and bearing babbitt surfaces increases the risk for accidental danlageb 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 remove/install 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 installation. 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 NEG037139
a " Prepared kBY- o.Benedict
,will create a delay in the txansfer of tooling and materials betweeh LP "A" and
> Asbestos concern: 'There is a potential that the stea-m seal ine being repaired contains asbestos insulation. Any asbestos insulation issues could shutdown work
,on the turbine decki
> Maintenance resources: Maintenance crews assigned to the steam seal line repair have 7 shifts available to perform this repair- If there are any delays in perthrming the repair (e.g. coordination issues or emergent issues during the work), the 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. addition al 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 phace. According to Jim Savoy (Team Inc. DistrictManager) many commerdial industrial facilities that have utilized clbmps similar to the one installed on the N4 steam seal supply line have operated for extendeý periods much greater than the requested I &months. The steam seal supply is approximately 2 - 5 lbs. of pressure with a maximum temperature of-255 degrees I. This is considered very low in comparison to many of the applications that Tearrf. Inc. has installed similar long terti clamps on. If the clampis left installed for an additional operating cycle there is a risk that the clamp will teak once the plant is placed back on-iihe. Although considered a low probability, the risk is due to the thermal cycling.,f dissimilar materials that are utilized in the clamping and sealing process. If a leak were to occur Temn Inc.
ýwould re-inject the clamp with sealant which has been successfully performed at other locations.
NEGO37140
VERMONT YANKEE SCOPE MANAGEMENT REVfEW FORM
.:1. 11_ - Trckn Nu. r:....._____________
Date: //3o Tracking Numbetr: (Assigned by Work Scope Control Coordinator) York' Order Number: Ot 6'xtC6 Reference Document T-M ZCO'* - O 3 (P., MM, T 0 -Mr28,.etc.) Initiator: k b /o o dt , Approved By: . ..... . _ ___ Dept-M. Locationt of Work to be Performed:,?a ~r ADDITION C] DELETION C4AUAYGF Description _1 Review Process Additional Cot Duration and Scheduling Impact: A~ssigned DWItJMan-HourS Co Compltel: -_________ __________ Sou*rce of Manpower/Other Scope Impacted: Dose, Chemistry. Safety Impicaion: __ Engineering Impact Man-Hourngineng Dpt...... Optional Ways to Addres: Approval Process Please provide a btt tictllion Scope Review Committee Recommendation/Planning Priority:, Priority "C" W(O*-* nsib Dept Approval . Plant Mana ., Approve Disapprove Daze o______ EMPAC ha"orEventCo e &Pri rity ............ / SCC Date Log Updated: -------- Copies to Work Control, Outage Scheduling. .,_ ; __; VYPPF 7l102.0 PP 7102 Rev. 1 Page I of 1 LPC#I5 NEC037141
RFO- 2 5 Piping FAC Inspections Outage Scope Challenge Meeting 5/4/05 Short or cryptic summary of what the proiect involves and why we needjto comnlete the project in RFO 25 (e.g. requlatory requirement, risk to generation, orograrnrequirem.ent, appropriate
,the asset.)
management of In response to USNRC Generic letter 89-08, inspections of piping components susceptible to damage from Flow Accelerated Corrosion (FAC) 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 RFQ25, VY will transition to a new Entergy procedure "Flow Accelerated Corrosion Program", ENN-DC-31 5. Description of the scope of the project, what it encompasses, options that have been considered (identify minimal required vs. discretionary - could be deferred scope.) Other outage scope that interfaoes'iwith or__can be included in this project; Im~pacts 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 Fall 2005 RFO is defined in Design Engineering-M/S 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: i 5 components recommended for repeat inspections based on prior UT data
% 2 components for CHEOWORKS model calibration
% 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 toassess changes in flows from HP turbine modifications installed in RFO 24. Internal Visual inspection of the only remaining carbon steel 30 inch diameter line 30'-B. Pre-outage. scope and long lead.time parts/contracts that have been identified. None Page I of 3 NEC037142
- RIFO-25 Piping FAC Inspections
/7/
-* Outage Scope Challenge Meeting 514105 initiatives, creative opportunities, uniqiue problems associated with the project.
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 on BWRs, Design Engineering - M/S has minimized the number of Inspections performed each RFQ. VY has traditionally trended well below industry average number of components inspected each RFO. This is primarily due the original design of the pJant 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. identify additional organizational support required, and specifically, management support 9cessarv.! 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 ISI program, Grid marking per new ENN Standard ENN-EP-S-005 Primary DE-M/S interface is the ISI Level Ill and/or ISI Program Engineer for coordination in review and approval of inspection data. Interface with craft & other plant groups is normally through established links in the IS 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 ISI 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.). Pg 2 o Page 2 of 3 NEC037143
/ N ou yRFO-2 5 Piping FAC Inspections Outage Scope Challenge Meeting 5/4/05 Identify any preparation issues necessary to meet upcoming outage milfestones.
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" B 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.alln*ecessary outage and pre-outaae WO's for the project _rocjram scope are generated, Work Orders to for support activities and inspections (04-4983-000 series) w/ It4e,*,, -jentJf~v ifany opportunities to perform any part of this scopecould be .cmpieted ore-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 CRD pumps. These may be inspected during operation. However, this is a high noise area. ( IU,,,,"o) Page 3 of 3 NEGO37144
Engineering Standard Review & Approval Form Engineering Standard Change Classification Revised U Cancel I. U TEditorial I -u Tomporary TCN* Engineering Standard Title Doc. No. Rev No, TCN No. Flow Accelerated Corrosion Component Scanning and ENN-EP-S-005 0 I'A Grddinc g Standard Engineering Programs Jeffery Goldstein Ian Mew Site Conducting Reviews ANO r=OEH U GO :33S LI WFS ] I I 3 I JAF I t PNPS I fJ V YJXoYQL .. Revieow T'YPe Yes N eewrN ' tueDate Technical Raeviw 0 (" izarc .-- (See Note below for DesIgn Change $Sandards) James G Fitzpatric ,.-F Independent Design Verification (See Note below for Design Change Standards) 1 OCFRS$159/Prooess Applicability Review (attach sceening and evaluation documents) 0 C James C. Fitzpatc. (See Note bejow for Desi n Change Standards) " A 0, Nole: Re*,Was for -esignChangeStandrds ata Docun-entad wihin t.. ire , applicableER. " . r,-lum -tJ- -
- An ER Number Is rquirfd lorDesign Change Soande ds, oult. N.
Crioss Discipline Reviews L 0Reviewer Name I Signature N/A Site EnqgineerinStandard Champion Scott D. Goodwin A-- ' Editorial Change /TON Approval IName. O inaturs: Date:
\ ~cometsertn Comments Made Below" I M Comments Attached
_Commenets/TON. 9lmae: This standard replaces VY specific 'Componenl Gr[dding Guidelines' previously contained in Appendix A oh VY NDE procedure NE-6053 NE-8053 has bean superseded by ENN-NDE-9-05 All VY comments were resolved during devetopment of [his standard. b ) .2 K NEC037145
U NEC037146 V
Engineering Standard Review & Approval Form Nd 16ý S Engineering Standard Change classification f N Rev Enpineering Standard Title Cancel Editorial o. ec.0. Temporry Rev No. TON NO. l Pipe Wall Thinning Structural Evaluation ENN-..S.O)k 0 Functionat Discipline Engineering Statdard Owner Enqineerilandard Pre ISe Civil/Structural R.,Penny H. Y. Chang C [onducting R avie .-- N.w . Re-viewType 'Yes"_ N~o Reviewer NaLneSij gture Date (See Notebelow forDesignChange Standard) -. James C, Fitzpatrickklf' Iettach Screening ndVevaluation touments) [I 0 James Fiizpalik ,,t ( Note below for Desin Change Standards&) I James......... Noth60e: ngy fOrMYw
]snCangeSta~n d rQLDs'aro Douee wJhamtes E. Nuntbett appticable ER. ER Numer An ER Number Is reqUtied for D~es*gn ChankeeStandard rt. .. _
Cross. Discipline Reviews;0 (Dapart-entName) R eviewer Name I Signature Date NIA V Site Engineering Standard Champion Scott 0. Good*wtn ri - Editorial Change ) TCN Approval SName: ! Si nature: .jlDate: Comments S**ection Comments Made Below +5 Comments Attached TCN Change Below TGN Change Attached - TCN EffectivetExpi ration Date Comments0CN Change: All VY comments resolved during development of this standard. ) NEC037147
Page I of I Fitzpatrick, Jim
-..",Nom: Fitzpatrick, Jim
.,nt: Tuesday, September 27, 2005 11:45 AM To: VTYEngineering-Mechanical Structural; VTY,_EFINDL
Subject:
FW: Communication of Approvefd Engineering Standard FYI This is a new fleetstandard for evaluation of thinned wall piping components which will replace ENN-DC-1 33. ENN-DC-133 will be superseded. VY Department Procedure DP 0012, "Structural Evaluation of Thinned Wail Piping Components wilt be revised or superseded as required 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 "-hrough wall leaks in ASME Sebtion XI Class 3 Moderate Energy Piping Systems". WPO has the responsibility to revise the references to ENN-DC-133 in these procedures. Qu atifica tionistfrairnirq : , At present there is no ENN QUAL CARD for use of this Engineering Standard, Calculations performed using standard are documented per ENN-DC-1 26. Based on the scope of this standard, only 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 of Changes from ENN-DC-1 33 as ariplioable to VY:
, 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 the Safety Factor (SF) from 1.2 to t .1.
, The methods used to calculate the code required thickness for pressure and moment loads are consistent with DPOO72, but presented in a different format.
- No significant changes to application of ASME Code Case N-513 for though wall leaks
- Added attachment forguidance in calcuiation of component wear rates.
, Excet spreadsheet templates are available to facilitate calculations From: Ettlinger, Alan Sent: Monday, September 26, 2005 9:33 AN To, Casella, Richard; Fitzpatrick, Jim; to, Kai; Pace, Raymond Cc: Unsal, Ahmet 2
Subject:
Communication of Approved Engineering Standard Inaccordance with EN-DC-146, 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-$-Q08, revision 0 Pipe Wall Thinning Structural Evaluation This standard supersedeskENN-DC-133. The standard can be accessed in IDEAS on the' Citrixserver. The standard becomes effective, and will be posted on September 28, 2005. Ifyou have any questions, please give me a call. 10/22/2005 NECO37148
UNITED STATES OF AMERICA NUCLEARREGULATORY COMMISSION Before the Atomic Safety and LicensingBoard In the Matter of )
)
Entergy Nuclear Vermont Yankee,, LLC ) Docket No. 50-27 lI'LR and: Entergy Nuelear Operations, Inc. ) ASLBP No. 06-849-03-LR
)
,(Vermont Yankee Nuclear Power Station) ) CERTIFICATE OF SERVICE I, Christina Nielsen, hereby:certifyrthat copies of NEWENGLAND COALITION,, INC.'S OPPOSITION TO NRC-.STAFF'&SMOTIONIN LIMINE TO STRIKE TESTIMONY AND EXHIBITS FILED BY NEWENGLAND COALITION, INC. in the above-captioned proceeding were served on theý.personr listed below,-by U.S. Mail, first class, postage prepaid; and, where indicated by an e-mail address -below, by electronic mail, on the 2 0 th of June, 2008.
- Alministrative Judge Office of the Secretary Alex S. Karlin, Esq., Chair Attn: Rulemaking and Adjudications Staff Atomic Safety andLicensing 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: hearingdocketknrc. gov E-mail: ask2@nrc.gov SarahH6ofmann,: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: whrcvillep~embargmail.com E-mail: sarah.hofmann(state.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: OCAAmail@nrc.gov Office of the General Counsel Mail Stop 0-15 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; mcb1@nrc.gov; Mail Stop T-3 F23 susanmuttal(rnrc.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: aroismah@nationallegalscholars.com
DaVid R.'Lewis, Esq. Marcia Carpentier, Esq. ýMatias F. TraviesoDiaz Lauren.Bregman Pillsbury Winthrop Shaw Pittman LLP Atomic Safety:and Licensing Board Panel 2300 N Street7NW Mail-Stop T-3 F23 Washington, DC ý20037-1,128 U.S. Nuclear Regulatory Commission E-mail: david.1ewiS@pillsburylaw.com Washington,. DC_ 20555-0001 matias.tradvies6-diazipillsburvlawv.c6m E-mail:* mxc7@nrc.gov "Lauren.,Bregmanxgnrc.gov Diane"Curran' Harmon, Cur-ran, Sp'ielb'erg & Eiseribergý 'L.LýP. Peter C. L. Roth, Esq. 1726 M Street N.W., Suite 600 Office of the Attorney General Washington, D.C. 20036 33 Capitol Street E-mail: dcurran(,harmoncurran.com (4 Concord, NH 03301 E-mail: .Peter.roth@doj.nh.gov Matthew Brock Assistant Attonmey General ,
.EnvironimentaI Protection. Division Office ofthe Attorney General One Ashburton Place, 18 "'Floor Boston, MA ,02108 E-mail: Matthew.Brockastate.ma.us lw¢ by:
Christina Nielsen, Administrative Assistant SHEMS DUNKIEL KASSEL & SAUNDERS PLLC}}