ML081830764

New England Coalition, Inc'S Motion to File Corrections to Exhibits and to Withdraw Certain Testimony of Ulrich Witte

ML081830764
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	06/27/2008
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-107
Download: ML081830764 (190)

Text

,. LA-S qt- o1 SHEMS DUNKIEL KASSEL & SAUNDERS P LLC RONAt-D A. SHEMS* GEOFFREY H. HAND KAREN L. TYLER BRIAN S. DUNKIEL** REBECCA E. BOUCHER ASSOCIATE ATTORNEYS JOHN B. KASSEL EILEEN I. ELLIOTT MARK A. SAUNDERS DOCKETED OF COUNSEL USNRC ANDREW N. RAUBVOGEL June 27, 2008 (2:10pm)

OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF June 27, 2008 Office of the Secretary Attn: Rulemaking and Adjudications Staff Mail Stop O-16C 1 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 Motion to File Corrections to Exhibits and to Withdraw Certain Testimony of Ulrich Witte. This filing attaches an expert witness report, NEC-UW_03, which discusses the following documents that Entergy has designated proprietary, all of which NEC has previously filed in this proceeding:

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

2. EPRI: Recommendations for FAC Tasks;

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

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

The first two documents are EPRI guidance documenis for flow-accelerated corrosion c-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 I 208 www.sdkslaw .com in t he Stateolu. bi

• Also admitted Asoadmitted in the Gistr ct 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:

Sarah Hoffman 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

UNITED STATES NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:

Alex S. Karlin, Chairman Dr. Richard E. Wardwell Dr. William H. Reed In the Matter of

-' )

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

)

(Vermont Yankee Nuclear Power Station) )

NEW ENGLAND COALITION, INC's MOTION TO FILE CORRECTIONS TO EXHIBITS AND TO WITHDRAW CERTAIN TESTIMONY OF ULRICH WITTE Pursuant to 10 CFR § 2.323, New England Coalition, Inc. ("NEC") hereby moves to file corrections to Ulrich Witte's report, Exhibit NEC-UW_03, and corrected versions of Exhibits NEC-UW_ 5 and NEC-UW_20. NEC also moves to withdraw portions of Mr. Witte's report, Exhibit NEC-UW_03, and of Mr. Witte's direct and rebuttal testimony that concern Entergy's alleged reduction of the number of FAC inspection data points between the 2005 refueling outage and the 2006 refueling outage.

I. Motion to File Corrections to Exhibit NEC-UW 03 and Corrected Versions of Exhibits NEC-UW 15 and NEC-UW_20 In the process of responding to Motions in Limine to exclude from the record Mr.

Witte's report, Exhibit NEC-UW_03, filed April 28, 2008, Mr. Witte identified and corrected a number of citation errors in this report. These errors involved the

transposition of exhibit numbers and other clerical mistakes. Mr. Witte also determined that one of his Exhibits, NEC-UW 15, is incomplete; and a second, NEC-UW_20, was printed from a corrupted file.' Mr. Witte completed a corrected version of his report, Exhibit NEC-UW_03, on June 19, 2008. NEC filed both this corrected report and corrected versions of Mr. Witte's Exhibits NEC-UW_1 5 and NEC-UW_20 on June 19, 2008, as Attachment A to NEC's Opposition to Entergy's Motion in Limine. The corrected report and exhibits are attached hereto as Attachment A.

This motion is timely filed within ten days of the date Mr. Witte completed corrections to his report. 10 CFR § 2.323(a). Mr. Witte's corrections do not change the substance of his report or testimony. The substitution of the corrected report and exhibits therefore is not prejudicial to the other parties:

II. Motion to Withdraw Certain Testimony of Ulrich Witte NEC moves to withdraw portions of the Prefiled Direct Testimony of Ulrich Witte Regarding NEC Contention 4, of Mr. Witte's report, Exhibit NEC-UW_03, and of the Prefiled Rebuttal Testimony of Ulrich Witte Regarding New England Coalition, Inc.'s Contentions 2A, 2B and 4 that discuss Entergy's alleged reduction of the number of FAC inspection data points between the 2005 refueling outage and the 2006 refueling outage. The specific discussion NEC moves to withdraw is indicated on the copies of Mr. Witte's testimony and report attached hereto as Attachments B-D.

In the process of responding to Motions in Limine to exclude his report, Exhibit NEC-UW_03, Mr. Witte determined that his discussion of the alleged reduction in FAC inspection data points was based on a corrupted version of the document filed as Exhibit U 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 version of this Exhibit is printed from the PDF file Entergy produced to NEC.

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NEC-UW 20. Mr. Witte converted this document to a text-searchable format from a PDF-format file. The conversion altered some of the text of the document, including the number of 2005 inspection data points. Page NEC037118 of the converted document states that the 2005 RFO inspection scope consisted of "0137 large bore components."

The PDF-format copy of this document that Entergy produced to NEC states that 37 components were inspected.

III. Consultation NEC has consulted or attempted to consult with all parties concerning these motions. The NRC Staff is not opposed. Entergy could not take a position without reviewing NEC's filing. The State of Vermont is not opposed to the filing of these motions, but reserves the right to comment on their substance. The States of Massachusetts and New Hampshire did not take a position.

June 27, 2008 New England Coalition, Inc.

by:

Andrew Raubvoge Karen Tyler SHEMS DUNKIEL KASSEL & SAUNDERS PLLC For the firm Attorneys for NEC 3

ATTACHMENT A EVALUATION OF VERMONT YANKEE NUCLEAR POWER STATION LICENSE EXTENSION: PROPOSED AGING MANAGEMENT PROGRAM FOR FLOW ACCELERATED CORROSION NEC-UW_03 I. Introduction CORRECTED I submit the following comments in support of the New England Coalition, Inc.'s REDACTED

("NEC") Contention 4. My comments concern the Applicant's aging management program, specifically addressing the fidelity of the Flow-Accelerated Corrosion ("FAC")

Program (NEC Contention 4).

NEC asserts that the application for License Renewal submitted by Entergy for Vermont Yankee does not include an adequate plan to monitor and manage aging of plant

\equipment due to flow-accelerated corrosion ("FAC") during extended plant operation.

The Applicant has represented that its FAC management program during the period of extended operation will be the same as its program under the current operating license, and consistent with industry guidance, including EPRI NSAC 202L R.3. The use of the CHECWORKS model is a central element in the Program implementation.

In the Applicant's motion for summary disposition, the Applicant proffered a response that credits the its current program for FAC management at the facility, and

'simply extends the current program for the 'renewal period, making the following statement: "furthermore, the FAC program that will be implemented 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 th6 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. Pr6gram weaknesses and failures have been identified by others and form the basis of condition reports, the categorization as unsatisfactoryin a Quality Assurance Audit dJated November 11, 20041, and noted as "yellow" in a cornerstohe 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, 1 spoke by phone with NRC resident inspector Beth Sienel, and she confirmed that, even now, Entergy has not completed verification of the upgrade of the CHECWORKS model to EPU design conditions. This concern regarding deficiencies in implementation of the program brings

'Exhibit NEC-UW 9, Audit No.: QA-8-2004-VY-1, "Engineering Programs", page 2, fN EC038514)ý 2 Exhibit NEC-UW_7, Cornerstone Rollup, Program: Flow Accelerated Corrosion, Quarter: Yd, dated 10/03/2006, page NEC038424, Open Action Items, (includes All CR-CAs, ER post action items and LO-qAs, 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.

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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 Actiofi 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,

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in particular given that they appear to violate regulatory commitments regarding the Flow Accelerated Corrosion Program.

10 CFR Part 50 Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," provides that a condition that is deficient is requiredto ýbe 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

,I, L I 0CFR 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 A 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."

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for years 5 led the Japanese Mihama Plant FAC pipe rupture in 2004, causing five 6j 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 r

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 SJ 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 A.C /

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-askessments.

Corrective actions from approximately five Condition Reports ("CR") remained open for Exhibit UW 20, Page 6 of 14 ofVY FAC Inspection Program PP7028, 2005 refueling outage at NEC,7109. . Deleted: 7 6 keepco Orderedto Sh/t Down Mihama Reactor. The Japan Times, September 28, 2004, availableat http://search.iapantimes.co. j/memberimember.htmlnn2004O928a6.him.

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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 2006', the condition report apparently was never provided to NEC. The condition report aggregated approximately six corrective actions to the program that had been ignored and the current status was then open and which is presently unknown to NEC.

In addition, the most recent FAC inspection was performed under superseded procedures and the results therefore are of potentially no programmatic value8 . Procedure ENN-DC-315, was revised and 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 were in fact still being implemented in February 2008, when Staff inquired on this subject.

'Exhibit NEC-UW 07 Cornerstone Rollup, Program: Flow Accelerated Corrosion, Program Infrastructure Cornerstone, Quarter: 3 ,d, dated 10/03/2006, page NEC034,19 _'Corrective ActionPlan to completeopen _ _ - - Deleted: I LO-CA tasks developed 10/02/2006, (CR-2006-02699)"). See also pp. NEC038422. NEC038424.

NEC038426-28--see also footnote 3.

E tNEC-_VYPiping FAg Inspection Progr PP 7028- 2007 Refueling_ utage Inspection __- Deleted: UW_20 Location Worksheets/ Methods and Reasons for Component Selection," April 3, 2006, at ], NECO17888.

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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, Formatted: Highlfght

10) that were required to be managed for FAC as far back as 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 3ra quarter 2006. The scoping document supporting selection of grid points collected essentially all the sins of the past, including, for example, stale predictive inspectiondata from the out-of-date version of CHECWORKS, and placed heavy reliance on engineering judgment. As provided under the 2005 scoping documenti 1, F tDeleted:

ii SDeleted:

I IIII  !. . . . .. . .....

-: Deleted: -

F..

ormatted.- Highlrght "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 6

the rationale for selection of grid points relied on (I) length of time since the lapsed inspections had ceased to examine a particular inspection point, (2) CHECWORKS User Groups, (CHUG) suspects found at other plants, (3) exclusion of components that were intended to be replaced based upon another regime or degraded condition.

Had data from previous FAC inspections routinely been entered into CHECWORKS, the selection of grid points and ranking would have provided a better historical perspective on where to inspect in successive outages, including the most recent outage. With the exception of VY's strength in reactively replacing piping or components with FAC-resistant material during repairs or maintenance, the program itself was not effective as a predictive modeling tool. Simply stated, once something ruptured or was found to be outside its design margin, it was replaced in a reactive management approach.

Proactive management of the program to predictfailureshas been inadequate in the FAC Program, as referenced above.

Even the most recent inspection completed for RFO 26 appears to have been structured around procedures that were superseded, scoping requirements to establish a new baseline of pipe geometry and as-found wall thickness were based on stale data, and the upper-tiered governing procedure that was used had not been revised since 2001 and 2

was therefore void.'

showed an trend of increased frequency of reinspection. See NEC037106. Page 4 of 14 provides for negative margin, or no inspections for Feedwater System. Conclusions called for "assessing the need" for inspections in 2007 outage. See page NEC037107. The condensation system showed one component with negative time to Tmin. The Extraction Steam System indicated three components with negative time to code minwall. PageNEC07_18.-- ---------- -------------------------------------------..- Deleted:7 12Exhibit NEC-UW-1 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.

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The current program-level procedure had been in existence since March 2006.

Scoping was performed in May of 2006 under the void procedure, and updating of

-CHECWORKS was not done until 3rd quarter 2006.13 Grid points, scope selection, and small bore piping susceptibility do not appear to have been ranked under NSAC 202L guidance or in an orderly trending of data by CHECWORKS based upon repeated passes with new grid points and new rankings selected. Data input and passes by CHECWORKS 4

were not accomplished on an outage-by-outage basis.'

With only 63 points examined in RFO 2615, the baseline for the p*ower up-rate conditions appears not to have been established. I found it troubling that RFO 26 results were provided to the Advisory Committee on Reactor Safeguards ("ACRS") on June 5, 2007, but apparently were not disclosed to NEC.

VY is the first plant modified to achieve Constant Pressure Power Up-rate to 120%

power and only one other plant out of the fleet of 104 was licensed to 120% increase in power in one step. Given the uniqueness of the design of VY's power up-rate, CHECWORKS has little industry benchmarking data, and is of marginal use.

The history of the one other up-rated power plant, Clinton Power Station, suggests the possibility of future problems at Vermont Yankee. The NRC inspected Clinton Power Station, including a review of the FAC program, after its up-rate in January 2003 and found the program to comply with its licensing basis, including NSAC 202L and the use I3 Exhibit NEC:UW ,07at EC38424 .................................................... Deied:

'4 Exhibit NEC- VY Piping FAC _nspectionProgran PP 7028- 2_05. FAG inspection Program

,_W-2 - { Deleted: Uw-20 Records for 2005 Refelintt Outage atN_ IC371 12 -NEC037120.- - -- -- -'- De7eted.7

'5 Exhibit NEC-UW- 11, Official Transcript of Proceedings ACRST-3397, Advisory Committee on Reactor , Deleted: 9, Safeguards Subcommittee on Plant License Renewal, June 5, 2007, at page 43! Entergy's Mr. Dreyfuss Deleted: 017896 stated: "...we did increase the number of FAC inspections by 50 percent from what we typically do in outages.. We did 63 inspections overall." It is also noted that the average number of points examined by the domestic industry is 82-under a well managed program, without significant changes to the model-such as a power uprate.

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of C14ECWORKS. Program inputs wei-e 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'6. It is relevant that this failure occurred approximately 16 years after Clinton received its operating license in 1987-while apparently complying with its CLB and the 7

EPRI guidance.1 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' 8 . Pleasant Prairie, a fossil plant with similar conditions, endured a catastrophic FAC failure at 13 years, causing.two fatalities'], and a Japanese plant failed without warning, killing five people, simply because of a failure to inspect one component section due to an administrative oversight, repeatedly missed by program owners. 20 The oversight was never noticed during quality control or quality assurance reviewvs, or spoited by the system engineers responsible for FAC at the plant.

6 1 Exhibit NEC 7fNEC0.17894..

t.7at .... . ......... .. .......... Deleted: UW-20

'7 ExhibitNECUW-04; Exhibit NEC UW-O,5 at XL.M_7. .----------.-.-- -- Deleted: O

's Exhibit NEC-UW_22 U.S. NRC NUREG 0933; Issue 139: thinning of Carbon Steel Piping in LWRs (Rev. 1) at 1-4.

19Exhibit NEC UW-2 1, Milwaukee Sentinel, March 9, 1995.

/

20Exhibit NECUW-20 at NEC037109............................................. Deleted: at 9, NECO17896 9

These plants were notspecifically 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.

Il1. Licensing basis for management of flow-accelerated corrosion at VY and review of the program implementation I reviewed the FAC program in four parts: Part A, examining the current licensing basis; Part B, the implementation of the licensing basis; Part C, the Licensee's own record of problems with implementation; Part D, my independent observations based on the record provided to NEC, and the requirements for implementing an effective program under NRC-endorsed guidance, with which the Licensee has stated that it has complied.

A. The current licensing Basis and the proposed licensing basis for the flow accelerated corrosion program:

My review to establish the current licensing basis and the current status of application for license renewal includes the following documents:

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

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

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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 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 thinnilng (TAC No. MB 1530) dated July 27, 2001. NVY 0 1-74; 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 I'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 (LROO1576);

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.

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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 Vermont Yankee Nuclear Power Flow-accelerated corrosion, dated February 28, 2000; xxiii. CR -VTY-2005-02239; xxiv. Cornerstone Rollup update last dated 10/23/2006; 12

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

1. The current licensing basis goal is to preclude negative design margin or pipe rupture due to Flow-Accelerated Corrosion and is centered 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 (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:

1. 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_l 5, 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,20jncludes a failure rate for BWR plants. The .- - - Deleted: s probabilistic risk assessment for BWR plant FAC failures is reported as.*l0E-5 (higher than reactor accident threshold Deleted: and 30 PRA for Design Basis Accidents).

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4. Detection of aging effects

5. Trending

6. Acceptance criteria

7. Corrective actions

8. Confirmation processes

9. Administrative processes

10. Operating experience25

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

,4.

_________________________________27 The record indicates that the' Vernmont Yankee Nuclear Power Station ("VYNPS") FAC program only partially implemented its licensing basis requirements to achieve a successful FAC program and that Entergy was aware of the problematic state of the program for many years.28 25Exhibit NEC-UW 06 at 152-157; Exhibit NEC-UW 08 at 2.

26 Exhibit NEC-UW 15 at-20 Th-is Exhibit proiydesinidustry-wide data-on FACfailures._Thehigh rate of - - Deleted: 18 failure in BWR plants underscores the need for precision in implementing an FAC program. Deleted: 30 27Exhibit NEC- at 3- . Deleted: UW

____Deleted: UW SExhibits NEC-!H-__ at EC0i7893-912-, Exhibit NEC-UW-09 at NEC038514, NEC038515.

NEC038529, NEC038531-038533;Exhibit NEC-UW 07 at NEC038422. Deleted:; Exhibit NEC-UW_16 at4-1 eleted: UW-05_

D*

14

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

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

6. Relevant data apparently was not entered into the CHECWORKS model until the third quarter of 2006. 3' The October 23, 2006 rollup thus confirms that the model was not kept current during a seven-year period and suggests that susceptible locations may not have been inspected during this time period. This lengthy lapse significantly weakened the trending capability of the software, both during the lapse period and presently. It is also evident that EPU data was still being modeled and validated in 2008.32 K

29 Exhibit NEC-UW-08 at 1,4-. .. ... ...

Deleted: 11;Exhibit NEC-UW-]2 30 Exhibit NEC-UW-09_at 2, NEC03853 1-NEC038555. "CR-VTY-2004-03062" and "CR-VTY-2004- - .(Deleted: 9 03061." ,' (Deleted: letter 31Exhibit NEC-UW-07at NEC03.8424 ("CHECWORKS models and wear data analysis updated with all "N {Formatted: Highlight

'(Formatted: Highlight previous inspections in P*dquarter 2006.").

32 Exhibit NEC-UW 14, Email from Beth Sienel to Jonathan Rowley. Feburarv 20. 2008- " Deleted:

o I

_ Deleted: "

33- - -- -

-"- -" Formatted: 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 340.

3 Exhibit NEC-UW-0,at 5-6: _NEC-UW-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 beyond acceptable code limits, were also predicted. The hours negative to the next inspection were substantial-predicting potential code violation or failure could have occurred 3000+ hours previously to October 23, 2006. It is surprising that the Licensee apparently did not write condition reports for this condition. I do not believe that NEC received any notice of Condition Reports relevant to this significant indication by CHECWORKS predicting substantial wall thinning beyond code limits to occur with negative margin of this magnitude. This issue is particularly troubling given that the equipment failure event is unpredictable, and catastrophic when wall thinning is beyond acceptable limits. Despite CHECWORKS' prediction of wall thinning, the plant continued to operate., I have not seen any inspection or audit discussion of this situation.

It does, however, appear on the RFO 24 Inspection Plan, 37 oddly with the same number of hours of negative time to Tmin, even with the plan including wear data observed of 30%

38 increase at Quad Cities and Dresden after the up-rate.

36Exhibit NEC-MI-4.2

-at.NEC017893. See also NEC-UW-20 at NEC037108. ...... Deleted: UW__

37Exhibit NEC-JH_43 at NECO020 189.

. ... ... .. . .... .... ..... ........... . .. . . . .. . . . . .. . .. .. . .. . .. .. .. . . . ..( De lete d : 5 SId. at -C020197 ............................................. ------- - - Deleted: 41 17 -

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

the report notes the need for program management to ensureuppdate of susceptible piping LDeleted:"

0 to be identified and modifications to be incorporated,4 In addition, the report notes that cross-discipline review required .by procedure had not been performed.

11. The 2006 cornerstone report shows a number of indicators as yellow, with lists of 42 open CR corrective actions, and a new CR written in August 30, 2006. 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.'n 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

" Exhibit NEC-UW-,2 .at *.{NE.CO38.514).4).............. .. ,- ".Deleted: I1 40Exhibit NEC-UW-.L? at 5 (NEC038517). . ............... .... ........ Deleted: I1

- - - - _d--

-- -(Deleted: Exhibit NEC-UW-1I1 42 Exhibit NEC-UW-0QZ at.NE.C 0384 19, NEC9038422. ............ - Deleted: 9 43Exhibit NEC-UW-0.7 at.NEC.0384424.- Deleted: 9 14Exhibit NEC-UW-l0,at .---------------------------------------------------- Deleted: 3

'I 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 plant modifications and inspection results as not updated since May 15,200014

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. _.4 I17. Entergy pparently riedu/cg the number/fFAC inspection dta points be een the utge nd */O0!refel 200 reu* outage, in violatio of its commi ent to increase, nspection data p hts by 50%.7h, 2005 refueling J tagge i~nspec n called for 4' Exhibit NEC-JH_44 at 17.

46 Id. at 18.

7 I at 19.

ld.

Ild. at 27-29.

'9 Exhibit NEC-UW-0_7 atNE-CO38428. .........---..................... . . .-... Deleted: 9 19

137 large-bo inspection points. e 2006 re lfing outage inspect'es.presetd othe ACRS oJune 5, 2007, cover only 63 po ts.o

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

5I0 ExhibitNEC-UW-11 at 4. ....... ....... Deleted: 4 5, Exhibit NEC-UW-IENN-DC-3I 5) at 1:;Exhibit NEC-UW_ E.9PP_2_8).

--Deleted: 5 Deleted: 20 5 Exhibit NEC-ii,-,422 at NEC017888...

Deleted: UW 5 Exhibit NEC-UW-06 at§ XLM 17. .Deleted: 05 54 Exhibit NEC- JH-38_ata 4-5 ................. ------- -.- Deleted: UW-06 20

19. No indication is provided that plant isometrics were updated as required as of 10722/04.55 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

\N 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, as at VYNPS following the 120% power up-rate.

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

5 Exhibit NEC-JH 44 at 19.

[:*i _ I.............. Deleted:

.... . . . D l t d "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.").

f 21

I do not agree that a prolonged period of data collection is not necessary to use CHECWORKS effectively at VYNPS after the 120% power up-rate because the predictive algorithms built into CHECWORKS are based on FAC data from many plants.

VYNPS is unique in its approach of Constant Pressure Power Up-rate to 120%. Clinton is the only other plant to accomplish a one-step up-rate to 120% power and is a very different plant fiom VY. To my knowledge, out of 104 operating plants only six have increased operating power by niore than 15%.s" Of this group, at least three - Clinton, Dresden, and Quad Cities - appear to have FAC-related issues. 59 The argument that CHECWORKS incorporates relev~ant 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 .ofdata collection is further evidenced by the fact that the CHECWORKS model was not updated with plant-specificchanges 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 had passedsince 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

ýExhibit N`EC-UW_I 8, Union of Concerned Scientists, "Power Uprate History," July 12, 2007.

59 Exhibit NEC-UW 20 at NEC037109, NECO37116: JH 42 at NECO17894. NECO17897. NECO17898; JIH 4 3 at N EC02 0 196 ,- . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... ....-

• 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.

'0  ?,W,- T nu no - ---- :-,--

23

NEC-UW_15 CORRECTED PENNSTATE Department of Mechanical and Nuclear Engineering (814) 865-2519 Collcge of Engineering Fax: (814) 863-4848 The Pennsylvaniia State University 137 Rcbcr 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 by the NRC experts group. I did talk to Rob Tenoning on the best way of normalizing our data such that we would be consistent with the break frequency plots. The key findings from the students work is that the data, when plotted in the same manner as the break frequency spectrum plots from the NRC experts work, shows a much flatter behavior at the larger pipe sizes indicating a more similar probability level for failure as compared to a more significant decrease in the failure probability as given-by the NRC break frequency spectrum.

I am complying all the independent sets of data in a spread sheet and will attempt a further screening. Once complete, I will send you a copy of the data. I wanted you to have these report now with all the data so you could make an independent assessment.

Please let me know if you need anything else.

Very truly yours, L.E. Hochreiter Professor of Nuclear and Mechanical Engineering College of Engineering An Equal Opportunity University

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

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-of-coolant accident (LOCA) situations. Furthermore, the regulation requires that a spectrum of break sizes and locations be analyzed to determine the most severe case and to ensure the plant design can meet the acceptance criteria under such conditions.

Currently the regulation states that breaks of pipes in the reactor coolant pressure boundary up to, and including, a break equivalent in size to the double-ended rupture of the largest pipe in the reactor coolant system must be considered. While this restricts the design, it maintains a large safety margin ensuring the plant-is covered under all LOCA situations. However, an impetus for change has resulted from materials research, analysis, and experience that indicate that the catastrophic rupture of a limiting size pipe at a nuclear power plant is a very low probability event.

If approved, the proposed change would divide the break spectrum into two categories based upon the likelihood of a break. Breaks of higher likelihood, breaks smaller than 10 inches, would need to meet the current requirements set forth in 10 CFR 50.46. Breaks of a lower likelihood, those larger than 10 inches, would only need to meet the requirements of maintaining a coolable geometry and having the capability for long term cooling.

The purpose of this project was to collect data on instances of pipe failures including cracks, leaks, and ruptures. For each instance of failure the plant type, pipe diameter, type of pipe, failure mechanism, and type of failure was recorded. The data was then collapsed based on plant type (PWR or BWR), type of pipe (carbon or stainless steel), pipe size, and failure mechanism.

Then, normalized failure frequencies were calculated as a function of both pipe size and failure mechanism per reactor year. Plots of the frequency distributions were generated on a semi-log scale, and the frequency distributions as a function of pipe size were compared to the NRC predicted failure frequencies.

For this project our group collected two, independent sets of data. The first set was provided by the OECD Pipe Failure Data Exchange Project (OPDE), with a total of 2891 data points. The second set consists of 67 data points collected by our group from various sources. The two sets of data were not combined due to the lack of information accompanying the data presented in the OPDE database, such as plant name or exact failure size. This made it impossible to identify overlapping coverage and combine the information. Rather, within this report we have analyzed each data set individually in order to make an overall comparison of the trends observed for each data set and the NRC predictions..

The results from both the OPDE and the independent sets of data detailed in this report do not support the NRC's assertion that larger sized pipes do not break frequently enough to be used as design criteria. The overall trends of both sets of data show that the frequency of failures does not decrease as sharply with increasing pipe size as the NRC predicts.

2

Table of Contents 1.0 Detailed Introduction to the Problem ............................................................................ 6 2.0 D ata Collected ............................................................................................................. 8 2.1 OECDPipe FailureData Exchange Project.......................... 8 2.2 Independently CollectedData ........... ;................................................................. 9 3.0 Collapsing and Analyzing the Collected Data ................................................................... 12 4.0 Results and com parisons ........................................................................................................ 15 4.1 FailureFrequencyas afunction ofPipe Size ...................... I................................ 15 4.2 FailureFrequencyas afunction ofFailureMechanism ....................... 25 5.0 Conclusions ............ . ................. ........... S.................. 31 6.0 R eferences .............................................................. ............................................................... 33 Appendix A - OPDE-Light Databiase 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 f6r 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 PWRs 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 Fi 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) 5Figure 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 (I/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 accidents state that pipe breaks in the reactor coolant pressure boundary up to and including a break equivalent in size to the double-ended rupture of the largest pipe in the reactor coolant system must be considered. In the case of such an event the NRC has set forth the following criteria that must be met for a design to be considered acceptable [37]:

2

a. Peak cladding temperature must not exceed 22000 F.

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

c. Maximum hydrogen generation. The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react.

d. A coolable geometry of 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 fr'equency 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 upoh 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 steýl and carbon steel pipes were considered. Then, normalized failure frequency distributions were developed and compared to NRC predictions.

The predicted NRC failure frequencies were taken from Table 3 on page 14 of 10 CFR 50.46, LOCA Frequency Development [38]. This table is replicated below.

Table 1-1. NRC Total Preliminary BWR and PWR Frequencies.

Effective Current Day Estimates (per cal. yr)

Break Size Type (inches) 5% Median Mean 95%

1/2 3.OE-05 2.2E-04 4.7E-04 1.7E-03 1 7/8 2.2E-06 4,3E-05 1.3E-04 5.OE-04 3 1/4 2.7E-07 5.7E-06 2.4E-05 9.4E-05 7 6.6E-08 1.4E-06 6.OE-06 2.3E-05 i8 1.5E-08 L.IE-07 2.2E-06 6.3E-06 41 3.5E-11 8.5E-10 2.3E-06 8.6E-09 112 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 I.6E-07 4.9E-06 1.6E-05 6.2E-05 7 WR1,IE-08 6.3E-07 2.3E-06 8.8E-06

]S 5.7E-10 7.5E-09 3.9E-08 ,.SE-07 41 4.2E-11 1.4E-09 2.3E-08 7.OE-08 7

J 2.0 Data Collected For this project our group collected two, independent sets of data. The first set was provided by the OECD Pipe Failure Data Exchange Project (OPDE)', with a total of 2891 data points. The second set consists of 67 data points collected by our group from various sources listed as references in this report. The two sets of data were not combined due to the lack of information accompanying the data presented in the OPDE database, such as plant name and exact failure size, which made identifying overlapping coverage impossible. Rather, within this report each data set was individually analyzed in order to make an overall comparison of the trends observed for each data set and the NRC predictions.

OECD Pipe FailureData Exchange Project[3]

OECD Pipe Failure Data Exchange Project (OPDE) 'vas 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, Jafran, 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 I 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 "theactual OPDE database is restricted to organizations providing input data.

However, a "OPDE-Light" version of the database will be made available later this year to non-member organizations contracted by a project member to perform work or which pipe failure data is needed. This version will not include proprietary data, such as the exact pipe diameter, where failure occurred, and preclude any plant identities or dates.

Our group was fortunate enough to get a copy of this "light" version of the database for BWR and PWR pipe failures reported as of February 24, 2005. A total of 2891 failures, (1536 for PWR plants and 1355 for BWR plants) were provided in this database, and considered for this project.

The database listed the plant type, reactor system, apparent cause of failure, pipe size group, number of total failures for each cause and pipe size group, and then a break down of the type of failure within the category. An excerpt from the OPDE-Light database has been provided for clarification in Table 2-1 on the following page. The database, in its entirety, has been included in Appendix A of this report.

8

However, there are a few problems with this database related to the purpose of this project. First, since the database did not provide the type of pipe (carbon or stainless) for each failure, a reasonable prediction of what type of pipe was involved in the failure based on the 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 Collected Data[5-36]

For the purpose of this project our group'collected separate information on instances of piping failures and their causes. The information was collected primarily from Nuclear Regulatory Commission (NRC) bulletins, information notices, event reports, and generic letters. Our group was able to compile a total of 67 instances of piping failures. This database is provided in Appendix B. While our database is much smaller than the one compiled by the OECD Pipe Failure Exchange Project, it provides an independent check of the trends observed by that database.

A list of references is provided at the end of this report, and some of the actual references, printed from the NRC website, have been included in Appendix D.

9

,_Table 2-1. Excerpt from "OPDE-Light" Database I I PLANT PIPE SYSTEM APPARENT CAUSE PIPE SIZE TOTAL NO. Crack- Crack- Deoation Large Leak PH Rupture Severance Small Wall TYPE TYPE GROUP GROUP OF RECORDS Full Part Leak Leak Leak thinning BWR SS RAS Severe overloading 2 3 1 2 BWR SS RCPB external damage 3 I 1 BWR SS RCPB Severe Overloading 4 I I BWR SS SIR Severe overloading 6 I "_l BWR CS STEAM Water Hammer 6 I t BWR -SS RCPB ' iF:WeIding Error 3 7 1 - 4 BWR SS RAS TGSCC - Transgranulaz SCC 2 7 1 1 1 4 DWR SS SIR IGSCC - lntergranular SCC 4 4 1 " 2 I BWR SS RAS IGSCC -lntergranular SCC 4 56 - 1 32 . ,_. 9 13 BWR SS SIR 0 1 1 BWR SS RCPB TGSCC - Transgranular SCC 1I 1 -

F B WR S5 SIR IGSCC -lntergranular SCC 2 3 1 1 BWR SS RCPB Overpressurization 4 2 1 B3WR CS AUXC Vibration-Fatigue 5 I _

Table 2-2. Description of Plant Systems and Type of Pipin. , -

Plant Group . Representative Plant System Names Type of Piping AUXC Service Water Systems, Raw Water Cooling Systems Carbon CS Containment Spray System Stainless EHC Electro-Hydraulic Control System Carbon EPS Emergency Diesel Generator System Stainless FPS Fire Protection System Carbon FWC Feedwater & Condensate Systems Stainless IA-SA Instrument Air & Service Air Systems Carbon PCS Power Conversion Systems (incl. Steam Extraction Carbon Lines, Heater Drain Lines, etc.)

RAS ' Reactor Auxiliary Systems (incl., CVCS, RWCU, Stainless CCWS, CRD)

RCPB Reactor Coolant Pressure Bounidary Stainless SG Steam Generator Systems (e.g., S/G Blowdown System) Carbon SIR Safety Injection & Recirculation Systems Stainless, STEAM ..Main Steam (from nuclear boiler/steam generator up to Carbon turbine steam admission) 10

Table 2-3. Definition of OPDE Pipe Size Grou s.

Pipe Size Corresponding Corresponding Diameters Pipe (mm) Diameters Pipe(inches)

Group I DN < 15 DN < 0.6 2 15 < DN < 25 0.6 < DN < 1.0 3 25<DN<50 1.0 <DN<2.0 4 50<DN< 100 2.0<DN <4.0 5 100<DN<250 4.0 < DN < 10.0 6 DN > 250 DN> 10.0 Table 2-4. OPDE Pipe Failure Definitions.

Type Description Crack - Part Part through-wall crack (>- 10% of wall thickness)

Crack - Full Through-wall but no active leakage; leakage may be detected given a plant mode change involving cooldown and depressurization.

Wall Thinning Internal pipe wall thinning due to flow accelerated corrosion - FAC Small Leak Leak rate within Technical Specification limits Pinhole Leak Differs from "small leak" only in terms of the geometry of the throughwall defect and 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 Severance ___ mechanical fatigue - limited to small-diameter piping, typically Large flow rate and major, sudden loss of structural integrity. Invariably caused Rupture by influences of a degradation mechanism (e.g., FAC) in combination with a

_severe overload condition (e.g., water hammer)

3.0 Collapsing and Anallzing-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) I 1+2 0.0-1.0 3 1.0-2.0 4 2.0-4.0 5 4.0-10.0 A>ion Note: This grouping of piping diameters includes one less bin than used by the OPDE database.

Combination of the data from groups 1 and 2 of the OPDE database allowed the bin sizes to correspond more readily with those used by the NRC for listing predicted failure frequencies, taken from page 14 of 10 CFR 50.46, LOCA Frequency Development. The categories used for the NRC predicted failure frequencies are given in Table 3-2. [38]

Table 3-2. Definition of NRC LOCA Groups.

LOCA Effective Break Category Size (inches) 1 1/2 2 17/8 3 3 1/4 4 7 5 18 6 41 It can be seen that for LOCA categories 1 though 5 the effective break sizes fall within the ranges listed for the pipe size groups, after pipe size groups I 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. Stress Corrosion Cracking

9. Water Hammer

10. Miscellaneous

a. Brittle Fracture

b. Cavitation

c. External Damage

d. Fretting

e. Freezing

f. Hot Cracking

g. Hydrogen Embrittlement

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

The number of failures in each bin was normalized by dividing by the total number of failures.

This gives the fraction of failures for each bin size. For example, when looking at carbon steel pipes in BWRs the number of failures in each pipe group size, regardless of failure mechanism, was divided by the total number of pipe failures (carbon + stainless) in BWRs. Similarly, the number of pipe failures in each failure mechanism bin, regardless of pipe size, was divided by the total number of pipe failures in BWRs.

Then, after normalizing the data, the fractional size in each bin was divided by 3390 calendar years of operation. This gives a failure frequency in lI/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.

14

4.0 Results and Comnarisons 4.1 Pipe Failuresas afunction ofPipe Size from OPDEData This section of the report examines the results of pipe failures as a function of pipe size.

Normalized failure frequencies for carbon steel, stainless steel, and composite (carbon and stainless)pipes are presented individuallyfor PWRs and BWRs. The NRC has developed their own failure frequencies for PWR and BWR plants as function of pipe size, but does not have separate frequencies for carbon and stainless steel pipes.

Table 4.1-1 lists the normalized failure frequencies for both PWR and BWR plants, regardless of pipe type, calculated from the OPDE database data and the NRC mean predictions [38].

Table 4.1-1. OPDE Calculated, and NRC Predicted, Normalized Failure Freq encies (1/cal- rs).

Plant Pipe Size Groups OPDE Results NRC Predictions

-XType (inches) 0.0-1.0 1.3E-04 6.3E-03 1.0-2.0 4AE-05 2.3E-04 PWR 2.0-4.0 2.9E-05 1.6E-05 4.0-10.0 4.6E-05 2.3E-06

> 10.0 4.2E-05 3.91-08 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 5.61-05 2.4E-05 4.0- 10.0 6.2E-05 6.0E-06

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

1.00E-02

-- OPDE PWR ResuUt I.0OE-03 4-- NRC PWR Prediction

-*OPDE BWR Results

-* _*- I" - NRCEWR Prediction u: 1.00E-05 1.00E-06 - ,, ,

0 1.00E-08 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 100 Pipe Size (Inches)

Figure 4.1-1. Normalized pipe failure frequencies as a function of pipe group size for both carbon and stainless steel pipe failures in both BWR and PWR plants.

There were three issues in the data analysis that were initially thought to factor into the difference in results between the analyzed OPDE database and the NRC predictions. The first assumption was that all types of cracks, leaks, ruptures, or other issues were considered to be a complete failure in the pipe. In actuality this is not true since inspections or other indicators may catch a crack or leak before a complete failure occurs. As a result, a separate analysis considering only the pipe ruptures listed in the OPDE database was conducted. However, the calculated frequency distribution considering only ruptures did not change significantly, in either trend or magnitude, from the results obtained when considering all issues to be a failure. The, results of this rupture only analysis are shown below in Figure 4.1-2.

16

/

1.OE-04 U. 1.0E-O5 0"*o-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 PNWR 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 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 inature 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 predidtion. It can be seen that even when the range of validity is taken into consideration, a large portion of the distribution still falls outside the boundaries for both PWRs and BWRs.

1.00E+00

.OPE l.OOE-01 Results

, - I-NRC Mean X NRC th Percentile 1-X.0

.OOE-02X E *I NR C M ed ian -

• * " *NRC 5th Percentile

-4 2 1.ODE-03

" 1.00E-04 -

• LL 1.00E-05 "--

.1.00E-06 -

i* .00E-07 X 0

Z 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (Inches)

Figure 4.1-3. Normalized Failure Frequency Distribution for PWRs.

18

• . , NRC 5th Percentile Z 1.E-03 x UZ i 1.00E-04

. 1.00E-05 A.' 1.00E-06 .. ....

S/1.00E-07 0

1.00E-08 1.00E-09 1.0E-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 flWRs.

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 OPDIE database for PWRs and BWRs respectively. All the data contained in these tables was normalized based, on the total number of failures for the given plant type (1355 for BWR and 1536 for PWR).

Table 4.1-3. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05 Both Carbon Stieel and Stainless BnSteelPe SCarbon Steel Pipes Only Stainless Steel Pipes Only Pipe Size (inches) Number Normalized Failure Normalized Failure Number Normalized Failure of Failures Frequency of Failures Frequency of Failures Frequency (l/cal-yrs) (l/cal-yrs) (1/cal-yrs) 0.0-1.0 698 1.31-04 154 3.0E-05 544 L.OE-04 1.0-2.0 228 4.4E-05 74 1.4E-05 154 3.0E-05 2.0-4.0 153 2.9E-05 78 L.5E-05 75 1.4E-05 4.0-10.0 238 44.6E-05 126 2.4E-05 112 2.2E-05

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

Table 4.1-4. Summary of BWR Pipe Failures from the OPDE Database as of 2-24-05 Both Carbon Steel and Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only Pipe Size Steel Pipes Car onIte s___p __l Stainless Steel _Pipes _Only (inches) Number Normalized Failure Number of Normalized Failure Number Noinalized Failure of Failures Frequency Failures Frequency of Failures Frequency (Ikcal-yrs) (1/cal-yrs) (l/cal-yrs) 0.0-1.0 375 8.2E-05 118 2.6E-05 257 5.6E-05 1.0-2.0 107 LIE-05 32 7.0E-06 75 1.6E-05 2.0-4.0 259 2.6E-05 32 7.0E-06 1 227 4.9E-05 4.0-10.0' 284 2.9E-05 50 1.1E-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 sta~inless steel pipes are more frequent than carbon steel pipes only for smaller pipe sizes in PWRs. Figure 4.1-6 shows that stainless steel pipe failures are much more frequent than carbon steel pipe failures at all pipe sizes in BWRs.

As previously mentioned, the data for these two figures (4.3-5 and 4.1-6) was normalized using the methodology explained in the Data.Analysis Section, using the total number of failures (carbon + stainless) foreach 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,,_

-9

1.ODE-02

ý111ý1 0 Carbon Steel

-+-Stainless Steel NRC PVVR Prediction 1.00E-04 LZ .0E-05

+/-I.1ODE-06 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (inches)

Figure 4.1-5. Normalized pipe failure frequencies asa function of pipe size for PWRs.

1.00E-02 I -OE-0--4-- Carbon Steel 1.OOE-03

• 1.00E-04 ii 1.OOE-05 1.00GE-07 1.00E-08 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe SIe (Inches)

Figure 4.1-6. Normalized pipe failure frequencies as a function of pipe size for BWRs.

21

1.OE-02 Fi ,VV I - . M .aiu I1.02E-04 LL I.OE-05 1.OE-076 1.OE 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe Size (!nches)

Figure 4.1-7. Normalized pipe failure frequencies as a function of pipe size for PWRs using the Modified Analysis Method.

1.OE-02 1,0E , 'l-tnes See

• * .OE-05 9 .oE-O6 1.02-07 I1.0E-08 O.D-1.0 1.0-2.0 2.0-4.0 4.D-10.0 > MDO Pipe Size (inches)

Figure 4.1-8. Normalized pipe failure frequencies as a function of pipe size for BWVRs using the Modified Analysis Method.

Table 4.1-5. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method.

Both Carbon Steel aed Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only Pipe (ipeSize SizeSteel PipesI Failure Normalized Normalized Failure Normalized Failure (inches) Number Nubr Frequency ofFiurbesr rqec Frequency of Failures F cof Failures Frequency of Failures (1/cal-yrs) (1/ca_-yrs) (_/calyrs) 0.0-1,.0 698 1.3E-04 154 8.7E-05 544 1.6E-04 1.0-2.0 228 4.4E-05 74 4.2E-05 154 4.5E-05 2.0-4.0 153 2.9E-05 78 4.4E-05 75 2.2E-05 4.0-10.0 238 4.6E-05 126 7.1E-05 112 3.3E-05

> 10.0 219 4.2E-05 93 5.2E-05 126 3.7E-05 Total 1536 7- 525 --- 1011 1 ---

Table 4.1-6. Summary of PWR Pipe Failures from OPDE Database as of 2-24-05, using the Modified Analysis Method.

Both Carbon Steel and Stainless Carbon Steel Pipes Only Stainless Steel Pipes Only Steel Pipes Pipe Size (inches) Number Normalized Feuny Failure Number Normalized Feuny Failure Number Normalized FrqeyFailure Frequency of Failures Frequency of Failures Frequency of Failures (I/cal-yrs) (1/cal-yrs) (l/cal-yrs) 0.0-1.0 698 1.3E-04 154 3.4E-05 544 7.OE-05 1.0-2.0 228 4.4E-05 74 9.3E-06 154 2.0E-05 2.0-4.0 153 2.9E-05 78 9.3E-06 75 6.2E-05 4.0-10.0 238 4.6E-O5 126 1.51-05 112 6.4E-05

> 10.0 219 4.2E-05 93 1.1E-05 126 7.91-05 Total 1536 -- I 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 thi's 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 Daitabase Calculated, Normalized lailure Fre uencies (l/eal-y rs).

Plant Pipe Size OPDE Data NRC Independent Type (inches) Prediction Database 0.0-1.0 1.3E-04 6.3 E-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 2,31E-06 2.2E-05

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

22

1.E.02 II I --

I.E-03 WE. 1.E-04 o I.E-06 LE-07 I.E-O8 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.

- 23

-OPDE

-- resjults 1.E-M I.E-04 o.I.E-05 -.-

1.E.07 I.E-08 1.E-09 I.E-lo 0.0-1.0 1.0-2.0 2.0-4.0 4.0-10.0 > 10.0 Pipe SIze (Vnches)

Figure 4.2-2. Normalized pipe failure frequency as a function of Pipe Group Size for BWRs.

Overall, the two independent data sets show contradicting trends wheh compared to the NRC normalized frequencies. Instead of the double-ended guillotine break being analyzed for every plant for the largest pipe in that plant, the NRC is trying to make the maximum break size which needs to be analyzed ten inches. The reasoning for this is due to low frequency of breaks in pipes of larger diameter than ten inches. This data above shows that the frequency from raw data does not agree with the current NRC predictions by expert elicitation. There is a high frequency of occurrence in pipe sizes greater than ten inches according to the independent data found.

24

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 brokep apart by steel type and plant type. The data was normalized for each type of steel based on the number of reactor years and the total amount of failures (carbon +stainless) for each plant.

Table 4.3-1. Failure Fre uencies of Pipes for each Failure Mechanism.

Plant Carbon Steel Stainless Steel Total Failure Type Failure Frequency Failure Frequency Frequency PWR Corrosion 2.04E-05 5.38E-06 2.57E-05 PWR FAC 2.29E-05 2.32E-05 4.61 E-05 PWR MIC 8.26E-06 1.92E-07 8.45E-06 PWR Erosion 1.84E-05 2.30E-06 2.07E-05 PWR Fatigue 1.77E-05 9.62E-05 1.14E-04 PWR Human Factors 6.91E-06 2.42E-05 3.1 IE-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+00 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 1.31E-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 1.851-05 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 5.01 E-06 25

ILjLar~O1ona btainiess ziteeli U 8.OE-05 i 6.OE-05 o

20.0 5

• I Corrosico 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 0 Stainless Steel I Carbon and Stailess Steels 1.200E-04 1.OOOE-04 c' 6.OOOE-05 LI-4-OD.E005 -O 4.OOOE-05 2.000E-05 COroslon FAC MIC Ersions Fatiue Human Mechanical SCC Water Mise Factors Factors Hammer Failure Mechanism Figure 4.3-2. BIWR Failure Frequency for Carbon and Stainless Steel Pipes as a Function

( of Failure Mechanism 26

0 '.OOE-05 6.000.E-05 4.000E-05

,000E-05

.O IDD,00E-05 0.0OOE-05 O.DOOE+ O - ,,rOI,* g-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 PWR plants are dominated by fatigue failures and BWR plants are dominated by stress corrosion cracking failures. However, in general the most frequent failure mechanisms for both plants are corrosion, fatigue, mechanical factors, and stress corrosion cracking: These four failure 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 corrosion because the pipe failure method for stress corrosion cracking is different than the other corrosion types.

Though mechanical failure frequency was not the-highest, mechanical failures were chosen because they appear to be independent of pipe type and plant type. Human factors wereignored 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

C.

0*

I..

LA.

2 3 1 4 5 6

- Pipe Size Bin Figure 4.34. Pipe Failure by Corrosion as a Function of Pipe Size (PWVR & BWR) 2 3 4 5 $

Pipe Size Bin Figure 4.3-5. Pipe Failure by Fatigue as a Function of Pipe Size (PWR & BWR) 28

C 1.OOE+00

-- Carbon Steel

-Stainless Steel I .OOE-03.

Carbon and Stainless Steel Cr S1.OOE-04 1.OOE-D5

/.UU0E I 2 3 5 6 Pipe Size Bin Figure 4.3-6. Pipe Failui-e by Mechanical Failures as a Function of Pipe Size (PWR &

BWR) 1.OOE400 I .DOE-01 -- *-StainlessSteel

-4CrbonSteelI Carbon and Stainfess Steelf 1.OOE-02 0

0 z

1.OOE-04I 0.

I-'I-- 4 0'

IA. I -----

1.OOE-06

-N 1.00E-07 I '2 3 4 5 6 Pipe Size Bin Figure 4.3-7. Pipe Failure by Stress Corrosion Cracking as a Function of Pipe Size (PWVR

& 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 OPDE Data

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

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

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

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

5.2 Pipe Failuresas afunction of Pipe Size from Independent Data

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

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

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

5.3 Pipe Failuresas afunction ofFailureMechanism

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

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

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

31

3. Although the OPDE data does not show water hammer to be a significant failure mechanism, it should be noted that the OPDE database listed 450 separate water hammer events where structural pipe integrity was challenged but not failed. Had this data points been included as probable failures, water fiammer 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)Proiect, OECD/NEA (2005).

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

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

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

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

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

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

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

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

12) Marsh, Ledyard B., Information Notice 99-19: RUPTURE OF THE SHELL SIDE OF A 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 i1,1997.

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 12,11991.

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 74-1OA: 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.

35

F r - r iPLANTTYPEi P*IPETYPE SYSTEM GROUP APPARENT CAUSE GROUzl RREUP .

, OIAL P OPRECORDS C~.iI Crack-FLA CrackPaA I Delo rIatIpba~ILiLa n L ,eeo Leak ek I PI -Le ,

IRukge I $wow" I "I Leak IWa! irnr" 5

-PR CS AUXC 6 1 20 6

2O 2

2 F'WR I 1 s

6 2 2 1 0-I.oea&*caty hnauced Canaoaa 4 I1 I

0 12 3

1 2

17 7

3 3

FPS

1 _________________

i 2

I I-HF.CGNSTANST-1F.CONSTANST H1FCONSTANST Pam.,i FWc FWC I-I

-"V I :

PCs I

!I

PCs I i -

PWR I CS- I 'Oba .. eý PWs , .... -*--* °*V"=='

PWR I CS 611118 Flackso Ci8sc~w1-uao

_CO4TOr.H CwQuo

.CSCC. E ~le" Cwds bIne 4

.CSICC. Ek1ema, Crnde hr C=C - E,1 N-61. klx Excess~eVibmiof FA. FPo b*eieled Conros i

HF.CONSTIINST HFCONSTANST HF.CONSTN$NS" HF:R-OOSTANS" HFFsbrlcab8* En HF.Hunmeffr 2 1 1 I

i I I 2 1 Q

_ I__ I___ 1 6 1 _ 1 1" 2 12 4 --~1~

2

• PWR I , IRCPE "SS 1 3 I 4 1 POwSCC 5 I

I -- - wtn~tu 2 1 1 1 - I I

6s

I- ý 3 I PR 4 I

ý-l Erro -F.~ I-I 4 3 2

f I

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1541

T T r~Tr1 PtANTTYPEIPIPETYPE I SYSTEMGROUP APPARENT CAUSE GROUpI OFRECROSj Ca*-Fl I C-ackPal 0I1 mImoml Lame LUk I 'Leak I P/-Leak I RUA.e I S-ewý.I S-in Leak W=-

Con'o1g Cc~frosgn CýrOn, Coaosion AUXC-- 1 AUXC I AUXC I 3 AUXC 2 AUXC 2 AUXC AUXC AUXC AUXC AUXC OWR SWR 8WR 8WR ECs BWR ECS S FPSna

,Cs

• C EHO EHO EXC EHO FPS, FPS I

PFPS I I

I 22 2 1 I FWC - FAC- Fowceersd Coaosmo 2 10 1_ 8 1 4 FWC-4 46 53 6

2 3

7 3

- 2 1 21 -

I r

K

6 3

I__

BWR

BWR I

BWR Vs RCPB HOFSIf sconf EFIor 2 , I 6WR SS RCPB HF:Fabcabn Err 3 1 SWR 55 RCPB HF:FaUkaln r 6Erro BWR S8 RCP8 HF:REP RA'ANT. 2 1 B*W-R -6S RCP8 .IHF.WM wro I 1 '

rwR 68S RcpO .H1F.Wa "'o" 2 2

-wR 6 R 8 HF:5 Err E 3 . .

BWR SS RCPB HF.We wror. 5 i BWI4 ss RCps HF.W *rw' 6 8 8 BWR S8 RCIs HoWI'a¢ 4 1 BVWR S8 RCr'5 u3sCC. kuw ,** SCC 1 4 2 SWR 55 Rd'S IGSCC-W In tia/urSC 2 3 2 BWR 8 RC*S ,ISCC-hIn*i u CC 3 2 2 SBWR SS RCPB IBSCC - kIuS SCC 4 0 2 5 .2 7 6BWR SS , RCPS IGSCC-* mnarSCC 6 t0 7 1 2 BWR* " 5 . RCPB IGSCC*~rseSCCd 6 203 3 174 I 32 8WR SS RCP8 OSSIIIZdon 4 2 1 OW14 SS RCPB 5.v3eiO,~ n, 4 I BWR SS RCPB S-CC-Sir a leaIrldCodrouodondi 6 1 - .

MWR SS RCP8 T5C-Ti anA. SCc I I BWR GS RCP8 T"SC-TI a4CC 2 I 1 BWR SS RCPB TGSCC.-I m * .~n "uarCC 3 1 BWR S5 RCPB Thea"lFat 2 2 8WR SS RCP8 TrwrnaWF6aA 3 BWR 58 RCPB MusIn-f 1 3 6WR SS RCPS vlIbrz.F.bi 2 42 2 1 4 2 CWR SS RCPB viab-stn-I 3 4 BWR 58 RCPD Vtan6a4a9-1 4 1 BWR 58 RCS.INSTR ECSCC. External C inde SG; 2 I1

'W= 6S RC.%4NSTR ECsCC- Extern*al Cide l incaA SICC 3 I 1 BWR &S RC"SYR HF.e:d ew 2 2 6BWR Ss RC8.4NSTR . ir0CC-SInlwv scc 4 2

• SWR - SS -5 RCS4NSIR "8CC-T CC 1 2 BW" -SS RC8.I4NSTR TGSC- Tri ~JS"SCC 2 1 BWR w SIR 0 I ,

6WR 6S SFR Bnale Inactse 5 4 4 SWR SS SIR Corroon 3 I 8WR S8 SIR Co*ouon-Iraline 1 5BW 88 SIR 60CSC- Extaflla 018614einduced 6CC 1 BWR a5 SIR ECS 1E.%.

w Ih* k"*,k1 5CC 56 I B6V6 S8 SIR Frosn 2 2 1 BWR 'S SIR E*sm 6, 1 BWR SS SIR FAC- FbwAcceSI*ted Corroslwo 2 4 BWR SS SIR F61. FCDACCQ*&eMW4aiiomw w 3 4

-BWR 6S SIR ýAC. Foo Actiatld Conosl, 4 2I 8WR 65 SIR FSIgue I I 6WB 5s SIR Fanm 2

_wR 68 aSI Fu t"

BWR 68 SIR F0 6 I 5WR S SIR HF.CONSTANST 2 2

-BW1 I I-_______I~j-1

BWIH -ss SIR VjSCCG.V"armmU(5 5 1 64 2 51 6 5 5WK 63 SIRC. C 6 22 is 4 9W-R -=S IA =Pý . Ca hb-4xd~woý 5 11 rW-R -SS 515 R wFJ"izsUofl a BWR 55 - R - .ýitst 2 2 - 2 BWR 6-3 -S4R ~ S"a o.&.lo~iaw 2 - 21 1 6515 55s 5-IR Swe-feouo* 4 1 EWR SS -SIR Sawa ovecl"W9 6 1 BWRA 55 SIR TGSCC.Tlu7l SCC - 1 BWR 63 SIR T05CC.! 5CC 6 1 1 6515 ss SIR Tharmwabya 2 3 3 6515 SS SrIR Tht-nwtabo 6 3 BINS CS SIREAMm E otog 4. 11 OWR CS SAC ThvAiaNs"CCaVOI"f 2 16 1 12 OWR CS -SIR FAC. SaA&t4C ~ c 17'6 6515 CS i SIRA FW0C4I6~.Oc ViraO. bR 2 8WR CS SIRA lA o. so-fl IAc5uj~o~ 7 r - t7 BWS CSS STIRO Fb~aow~cleta roTms 6 2I -1 6511 CS SIRM 182510~ag 2 3 2 6515 CS STEAM HCSASY2 1 1 6515 CS STEAM Er;ownSIT 3 _ 1 1

Appendix 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 Erosion/Corrosion 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-B4 Surry Unit 1 PWR CS 30 6 Not yet determined IN 81-04 s~urryUnit 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

....Dablo Canyon Unit,

.PWR i .... S, . Thermal Fatigue .- , ,':N92-20

.. , .SeguoyahU.nit ..  ; ;PWR'- r.-CS- .-, - ... . Thermal Eatigue.  : ;IN 92-20.;-:*.

...-. ,..,,Surry UnIt .  :.- JR J,; ,: , - . Erosion/Corrosion"?* ."' T.IN 91.1B-.

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 ISS 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 6S 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 1 PWR SS 16 6 Fatigue IN 95-11 Sequoyah Unit 2 PWR SS 10 6 Human Factor IN 97-19 Sury Unit 2 PWR SS 10 6 SCC IE Circular76-05

• '.,::,;.* ,,*P loVeid6-,*:> * :""P.W.':'.-.;'W*' &X R ;:,*..ý.:i!,S. *,;tS 'W '_.,Vr*'* .  ;.:**

. ..*: '. Hum an aco ,'..:, %,iBulletin.-79-03:ý-..

San Onofre'Unit 2..... JPWR - " y-;..,-- Human'Factor-.*';'.-.'- ,Bulletin79 *,,*.San Onofrd.Unit 3-,'.I-'?- i-PWR.. -r 5..3-r..  ;. Human'Factor-,f':, *&Bulletin 79-03,

......il... I unt ....... ......L i : .tIN 9.1

.* .,'-.MI unit . PV,,* O c-:S

,,R. .  :-. .,SCC.O.'z?  ; ... IN 79-19:'.;

~~tTMI unit-,.12 z - MWR~~S~ ~~ S5 SC. 91

. -~i. . .. ... _ *,,.,uit., .,...... ,-. . : - ,. S CC;.. . .: IN 79-19A -'

- unit2 . E M IR, ..... - S*, 21-.,;1.-',9

..., . .: . . . , . ...-. ;7--.,.

iB..,

RWR, .. 0. 1N 88 I

~joltBeach 4nt

-~PWRý,*i~I 9-9

Appendix B (cont.)

Plant" Type Material Diameter Pipe Size I_____ Group FalrMetais Rfrec 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 - IN82-22 Cooper Station BWR SS 0.25 1 Vibration IN 89-07 Pilgrim BWR SS 1 2 Corrosion IN 85-34 Browns Ferry 3 BWR SS 4 4 SCC IN84-41 Browns Ferry 3 BWR SS 4 4 SCC IN 84-41 Nine Mile Point Unit 1 BWR SS 6 5 SCC Bulletin 76-04 Dresecen Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Dreseden Unit 2 BWR SS 10 6 Thermal Fatigue IN 75-01 Hatch Unit 1 BWR SS 22 6 SCC IN 83-02 Hatch Unit 1_ BWR SS 22 6 SCC IN 83-02 Hatch Unit I BWR SS 22 6 SCC IN83-02 Hatch Unit I BWR SS 22 6 SCC iN 83-02 Hatch Unit 1 BWR SS 22 6 SCC IN 83-02 Hatch Unit I BWR SS 20 6 SCC IN 83-02 Hatch Unit I BWR SS 24 6 SCC IN 83-02 Montecello BWR SS 22 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02 Montecello BWR SS 12 6 SCC IN 83-02

.-;,Dresden.Unt.l,, . BWR. { ' :*'re-ig; " ....

IHighlighted p.lants were nodt itwed in the.'datA ana1ysis di'brisig-inomtoý--',;,":Z'">-',

ný

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 PWR 2.0-4.0 78 75 153 4.0-10.0 126 112 238

> 10.0 93 126 219 Total 525 1011 1536 0.0-1.0 118 257 375 1.0-2.0 32 75 107 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 2.0-4.0 110 302 412 4.0-10.0 176. 346 522

> 10.0 132 417 549 Total 796 2095 2891

Collapsed OPDE Raw Data as function of Failure Mechanism Plant Type Failure Mechanism Resulting Number of Failures Plant____

Type _ai __eMecanis CS SS CS+SS Corrosion 106 28 134 FAC 119 121 240 MIC 43 1 44 Erosion 96 12 o08 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 Corrosion 29, 32 61 FAC 58 63 121 MIC 6 1 7 Erosion 40 9 49 Fatigue 71 225 296 BWR Human Factors 24 85 109 Mechanical Failures 18 25 43 SCC 19 624 643 Water Hammer 2 1 3 Misc 4 19 23 Total 271 1084 1355 C'

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

>I

r Appendix D - 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, You-ng Hwan, PIPING FAILURE ANALYSIS FOR THE KOREAN NUCLEAR PIPING INCLUDING THE EFFECT OF IN-SERVICE N INSPECTION, KAERI and KINS, 2004.

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

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

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

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

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

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

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

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

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

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

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

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

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) Ross i, 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 PIPINGAT DRESDEN-2, 12/17/74.'

30) Davis, John G.,Jnformation 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).

...................................... ............... .. ........ I .................................................. ....................................................... N................................

.N E C-U W. 20.. 0 ..................

CORRECTED PP7028 Piping FACJnspectiorf 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 page$s) 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 I a), dated 5/5/05. (18 pages) 4 VYPPF 7102.01 VY Scope Management Review Form for deletion of FAC 38-43 Large Bore Inspection Nos. 2005-24 through 2005-35 from RF025, dated 11/1106 (6 pages) 5 2005 RFO FAC Piping Inspections Scope Challenge Meeting Presentation, 44 -46 5/4/05 (3 pages) 6 ENN Engineering Standard Review and Approval Form 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 VY for:. "Pipe 49-50 Wall Thinning 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)

$ EN-DC-147 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 (RFO25 - Fall 2005) (19 pages) 9 Large Bore Component Inspections: Index and Evaluation Worksheets 70 - 327 (258 pages) 10 Small Bore Component Inspections: Index and Evaluation Worksheets 328 - 347 (20 pages)

Page 1 of 347 NEC037099

ENN Nuclear Management Manual Non QA Administrative Procedure ENN-DC-183 Rev.1 Facsimile of Attachment 9.10

\ ) I Program or Component Scoping Memorandum 2004-2005 Program Scope Memo Vermont Yankee - Engineering Department WaS Element: FAC Inspection Program Project Number: 1

Title:

Piping Flow Accelerated Corrosion (FAG) Inspection Program 2004 &

2005 Program Related Efforts Qrtqme.M DssiAn_ Enginee rn*- Mechanical ( Structural Owner: James Fitzpatri ck Backup: Thomas O'Connor Procedure No. PP 7028**, Vermont Yankee Piping Flow Accelerated Corrosion

Title:

nspcton Program Detailed Scope of Project (Exolanation): Engineering activities to support ongoing Inspection Program to provide a systematic approach to insure that Flow-Accelerated Corrosion (FAG) does not lead to degradation of plant piping systems. Currently** Program Procedure PP.7028 controls engineering and inspection activities to predict, detect, monitor, and evaluate pipe wall thinning due to FAC. Activities include modeling of plant piping using the EPRI CHECWORKS code to predict susceptibility to FAQ damage, selection of components for inspection, UT inspections of piping components, evaluation of data, trending, monitoring of industry events and best practices, participation in irndustry groups, and recommending future repairs and /or replacements prior to component failure.

• • Expected to adopt a new ENN Standard Program Procedure ENN-DC-315 (which is currently under development with an accelerated development date of 6/30/04).

Ex-pected Benefits (Justification): VY committed to have an effective piping FAC inspection program in response to GL 89-08_

Conselquences 2of 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 6/18/04 actions (coordinate activities with program standardization efforts).

Completion of RFO 24 documentation, write and issue RFO 2004 7/23104 Inspection Report...........

SoftWare QA on XP platform for CHECWORKS FAC module Version 8/13/04 1.0G Issue 2005 RFO Outage Inspection Scope, Including Scoping 911104 worksheets.

Update Piping FAC susceptibility screening to account for piping and 8113/04 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.

Page I of 2 NEC037100

ENN Nuclear Management Manual Non QA Administrative Procedure ENN-DC-I83 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 overgde pro~amoqJc.....................

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, 12/31/04 program improvements, benchmarking, attendance at industry (EPRf CHUG) meetings, evaluation of industry events (industry awareness) for effects-on VY, license renewal project input, and fleet suppor..

2005 Key Dellverables or Milestones-Perform Proram Self Assessment (minimum once per cycle). .4/1105 Conversion of CHECHWORKSI.OG models to SFA Version 2,lx 9/1/05 RFO 25 support `11.15105 Completion of RFO 25 documentation, develop RFO 25 Outage 12/31105 Inspection Report Ongoing Program Maintenance. Includes; procedure revisions. 12/31/05 program improvements, benchmarking, attendance at industry (EPRI CHUG) meetings, evalualion of industry events (industry awareness) for effects on VY, and fleet support.

2006 Key De-liverables or Milestones:

Issue 2005 Outage Inspection Report 1/15/06 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)'

for effects on VY. and Mleet support.

Estimated Budget or Expenses: AmountiHrs Captured in DE MechJlStructural Base Budget N/A Others Impacted By Project: Estimated Hours System Engineering 40 Engineering Support - K Reactor Engineering

.Design Engineering Fluid Systems Engineering 40 Electrical / I&C Engineering Mechanical / Structural' Design Tevel 3 Fragnet: (Attached)

Performance Indicators for FAC Program are contained in the Program Health Report (Attached)

Page 2 of 2 NEC037 101

2004-2005 Piping FAC Inspek >n Program Level 3 Fragnet YEAR 2004 12"d half) (Time Line from 6101104 to 12/31104)

- Preparer Reviewer TOTAL Est. Est. Delivery Task No. Task Description (HRS} (HRS) (HRS) Start f Completion Estimated Estimated, Estimated. Date Complete Focused SA write up,.& generate appropriate corroctive ,.

04-1 actions (coordinate a*cvities with program standardization 20 10 30 611/04 6/18104 efforts).

Completion of RFO 24 documentation, arite and issue RFC 2004 04-2 Inspection Report 60 30 90 6W14/04 7/23/04 FAC module Sottware QA on XP platform for CHEOWORKS 04-3 Version 1.0G .20 10 30 71/404 81t3/04 Update Piping FAG susceptibility screening to accour t for piping 04-4 and drawing updates. Include eliects from NMWC, power upuate, 40 20 60 7/12/04 8/13104

&lie extension.

UTpsate piping Small bore piping database and deveýop new 04-5 pTiority logic for inspection scheduling. 40 20 60 916/04 10/01104 04-8 Update CHEOWORKS modeFs using Version 1.0G with latest 2002 RFO &2004 RFO Inspection data t60 80 240 8123/04 12/31/04 lssue2ý005 RFO Outage Inspection Scope. Including Scoping 04-7 worksheets. 40 20 60 8/2104 911/04 04-8 Developmentladoption of ENN-DG-315 ENN Standsrd FAC program Procedure to include all 80 40 120 6/2104 10/31/04 previous impfovements identfied Self Assessments.

04-9 Ongoing Program Maintenance. In*ludes, procedure revisions, 160 40 200 611/04 12/131f04 program improvements, benchmaTking, attendarnce at industry (EPRI CHUG) meeUngs, evaluation of industy events (industry

_________awareness) for effects on VY, LR proTact input, and fleet su*port.

TOTAL (From end of RFO 24 to December 31, 2004) 620 270 890 HRS-Page 1 of 2 NEC037102

2004-2005 Piping FAC Inspe,...,.an Program Level 3 Fragnet YEAR.2005- (111/05 TO 12/31/05).

Task No. Task Description Preparer Reviewer TOTAL -est, E-t.

(RS) (HRS) TRSE (er Start Delivery I Estimated Estimated. Estimated. Completion I Date Perform Program Self Assessment (minimum oncmper cycle).

05-1 .40 . 20 60 311/05 4/01/05 Conversion of CHECHWORKS 1.00 models to SFA Version 2.1x 05-2 360( 180 540 4/1/05 9/01/05 RFO 25 Preparation &Outage Support 05-3 160 s0 240 9/1/05 11115/0504 05-4 Completion of RFD 25 documentatIon, develop RFO 25 Outage . .. 90..1.1..0..12/31/05

-- Inspection Report 60 30 go 11/15/05 12/31/05 05-5 Ongoing Program Maintenance. I cludes: procedure revisions. -

program improvements, benchmadding, attendance at itdusiry 40 20 60 1/01/05 12/31/05 (EPRI CHUG) meetings, evaluation of industry events (industry gawareness) for effects on VY, and fleet support, I Total Hr 990

)

Page 2 of?

t NEC037103

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection By: ....... Revie/fed Note; ReIsed for ,vYand Industtry Events an d Operating Ee.rienoe on 311/05 Piping components are selected for inspe'ction during the 2004 refueling outage based on the following groupings and/or criteria, Lamge Bore Piping.

LA: Components selected from measured or apparent wear found in previous inspection results.

LB: Components ranked high for susceptibility from current CHECWORKS evaluation.

1-G" 'Components identified by industry events/experience via the Nuclear Network or through the EPRI CHUG.

LD: Components selected to calibrate the CHECWORKS models.

LE;. Components s)ubjected to off normal flow conditions. Primarily isolated lines to the condenser in which leaka*, is indidated from the turbine pdrformance monitbring system. (through the Systems Engineenirig Group)-

LF: Engineering judgment I Other LG., Piping identified fromt EMPAC Work Orders (malftrnotioning equip., leaking valves. etc.)

Small. Idro PIin.n NAý- u -se*tp!ib piping Ioetiona (groups of component s) contained in the Small Bore Piping data base which haV* n6t redieved an initial inspectin.

SB. Cortpon&bts seleooed from measured or apparent wear found in previous inspection results.

SC: Con***p'hfht..t0ai  ! &tibdyiI',dtistf.-y ,Ila;eri~nce via the Nuclear Netwotk or thisgth the EPRI CHUG'.

SD:

leakae is In'*d**"icate ted to C*ona*idrt.ts sllm lda otf 'normal flow, condions. Primarily isolated lines to The conde.nsor, in which n th* turbin~e p~erforairce monitoring-system. (through the6Sy~tein&. Ef~i(et~ri~iih.

Group).

SE: Engineering Judgment ) Other.

SG: Piping identified from EMPAC Work Orders (malfunctioning equip., leaking valves, etc.)

Poad*wter Heater Shells Nto feedwaltr heater shell Inspections will beperformed during the 2005 RFO. AlI 10 of the feedwater heater shells have been replaced with FAG resistant materials.

Page1 of 14 NEC037104

..... I'"

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LA: Laege 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 were identified as requiring future monitoring. The following components have either yet to be inspected as recommended, or the recommended inspection is in a future outage. C Inspect. Loc. Component ID [Notes /Cornments / Conclusions No. SK.

915It 001 1996 Report: calculater tme to T1i is 11.6 & 12 cycles based on a 96-19 FW1SSPOS single measurement. The 2005 RFO is 6 cycles since the inspection.

LIT inspect elbow and dowbstream Dine In 2006 6:365 002 FDO2SP05 1996 Reaport: calculated time to Tmin is 9.5 cycles based on a single measurement. The 2005 RFO is 6.cycles since the inspection.

9647 005 1996. 10prt: edilulated rheto Train is926 cycleý based on a si-gle mnesuIremeht Tho 2005 RFO is S cYcles since; the inspection, 96-39 o5. FDOZS7POUS 1ie0:f6er:'*ca'uatftftie to Tvi*i is 10.5"yccles based on a sin-gle measurement. the 2005 RFO is 6 cy6l*s since-the inspection.

tF6'8 Nepotf: ai.utdd.timeto 1575 & 6.7cyles b

'im on a 9"g07 FDOYELO7 s$riglbemeasuremornt. The 205 f 5 cycles since the irSction.

isFO i]ven-ini.~fi.*cat...pr foun~d .in aldjaceht components (R-L z1 4.3 cyoles Oin FD07SP07) d6far ins4,ion until RFO26, UT io~f.e,:t gg-32 017 FDOL4 ' i$)

-l§"pof: calcuIated time'to Tirai s 7.2 & 1.5 cy1les based on a F9"i-bN 04 single UT iMpetitn. The 2005 REQ is 4 dycles since th& inspeuobn.

99-15 011 FDO&TPO5 1g 9 flapor:icald t~et tTrain"6&1c ba

.6les ion ale se M.

0&-2. . .~ FDJI 48P0 ~ S~ ~Given that.

~mesue24b& lo teonely

-lo'-........ low.rna n d.wsra dbwr stteat i.* n20 pMaeent2tsra.Ti*~e~

a'0D tht 2T004oRFO work insle"d teNlae e nt 16f bdeh Nd.1:..... water tears locateod undernthe elbo l Iw FbiwP1 tspdti&

99036 ND-Nza2.- sr.,1 masrem~ ent Th 20pe t p Ois 4 cyctrles osintethei insp*in 90-32 017 F004TEOI (pipe cap) 1999 eprt: calculated time to Tminn is 6.2 & 6.8 ycles based oh a 9933 r CND-Nor32-A single measu0remeinyt. The 2005 R- E is 4 cycles since the inspection, UT .inse.ow eanl.w andOwntQ e p e In 2005 9945 019 FOOSTEOI (pipe cap) 1999 Report: calculated time to Tmki is MG &8&5 cycles based oni a 99<iGs CND-Noz3Z--C s4ngle measurement. The 2005 FIFO is4 cycles sInce the ihspattion.

...-...... pipE t1$ 'P 1)*

UT inspectM t3inh 0n':04e do, *05.rtra ioZO'6 02-08 016. FMMW OLO 2002 recom~merirlfiln to 1ntpect the elOw in 07O based on a:4airfgle 02,09 P01 8SPC2US measurement, fe-inspyect elbow aniddo~wnstreaým pipe In 2667'(3

______ ____________ cvptes fronm gQ02).

003 001 FDOITEO5 2004 recommendation to inspect tee in 208bae ~ on the default Swear rate of 0.005 inch/cycle. fle-Inspect upstream elbow and tee in

'04-08' 002 FD02RDOI 2004 recommendation to re-inspect int 2011 based on the default wear rate of 0.006 inch/cycle. Re-Ispect reducer with downstream

...... ------- ____ elbpw and tWe In 2007.I Page 2 of 14 NEC037105

( . N

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

0 S 1 FD02-E12 on the default wear rate of 0.005 inch/cycle. Actual point to point measurements from 1999 to 2004 indicate n.o wear. Given EPU operation, re-Inspect with u _meam .elbOw and reducer In 2007.

04-09 001 FOO3S r1 20b4reco mmehdgion to irspedi pipe section in 2-011 based on a single inspection and the default wear rate of 0.005 inch/cycle. Re-

......... inspect in 2011.

04-10 001 FDO7SP02DS 2004 recommendation to inispect pipe section In 2008 btase on a

._slnrgie insg*eption. IAe-Inspect wKh downsrfeam elbow .n 2Q0.8 04-13 001 FB145z03 2094 rbcd6&mbndafidn to intpect Row 18 pup piece to DS *voe In'

_2 208is based on a single UT inspection. Re-ins ect In 2000, 04-23 001 MSDiTtOI to 2004 r commenditikon to ijnjpl pipe section in 2010 due to Iocalied

• MOgTE08

_._. we.r directlitu.nr 2 linop..Re.,..n.ct In 2010.

04-23 001 M809.L05 2004 raoomiri4tion to irn.*o*t p*1e section in 2010 base on a single

........... Inse on e-s.$0 'a in 2016.,

Previous Internal Visual UT & Repair History:

Line Mat. 'tsar Ia00t641 vis4g =V, Irite Inb Thblnihs --VT, Ro virs Perfarmeo 4

' ]Repaoed Ij.RPO.G .T- I nroiT~~l6*W Rwca P.2o 021 RFC1022 RF.023 5a0p

- ~ I ~ Ir &i'0ý.

8;j tIPA S--1 190§ 4_4_01 U~j

$.- ..B 149 ` IV V vv V V,

___._.,$:* "3 *10Q17-~ *. .'.. V f vV

• .............. v v __V v

'W_ t,

_-8 Qir1ina -}TfTUTI V VYflST V V

.I..*  :".*- , ......... -, Y _-..

1t"*sv dl pipe sections replaced with GE .tO.A2.I elbows on 'teB & lines are originat MS 9eli.tfon 0SA7D, eltows on A 61 fines are D50A6YE (Tnom =0,6:25 irich).

30" AB,.C repfacd with A691 0L22 (2-1/40r), Fittings A234 WP22. (Tnorn. = 0.625 inch) 30" B remains GE B6OA242D, fittings and GE DSOAS7D carbon steel (Tnom 0.50 inch).

NOTE: Reference Dwg. No, 5920-6841 Sh. I of 2 needs to be-updated with correct information. This will be performed duri6g the EPU dsign change effort.

The HP turbine rotor was replitced in 2.004. Internal v1sual inspection of all four 36"diameter lines was perlormed. An Internal visual inspection of the 30"C line, (firsl inspection sincethe 193 replacement ) and the 30" D lne wls performed.

2005 RFO based on increased flows and the possibility of different flow regimes in both the 36 &30 inch piping, perform a visual inspection. LP turbine work, in 2005 RFO may provide opportunity for access to the 30" lines. As a

,nminimum inspect (2) 36 inch lines and the carbon steel 30" B line.

Page 3 of 14 NEC037106

VY Piping FAC Inspection Program PP 7028 - 2004 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection LS: Large Bore Components Ranked High for Susceptibility from CHEOWORKS Evaluation The current CHECWORKS wear rate calculations contain inspection data up to the 1999 RFO and wear rate predictions are current to the 2001 RFO. The .200T and 2002 RFO inspection daja has been entered into the GHECWORKS database. However, updated wear rate calculations are not corpQite, and won't be in time to support the schedule date fo( issuing the inspection scope for the 2005 outage. based on a review of the 2001 and 2002 nr- inspection data for components on.the Feedwater, Condensate, and Heater Drain Systems, the CHECWORKS models still appear to over-gredict actual wear, Nothing new or unanticipated was observed in either 2002 or 2004.

Listed below are components which meet the following criteria:

a) negative tiWthto Tmin frorh the predictive CHECWORKS runs which inctude Inspection data up to the 1999 RFO.

b) no inspections have been performed on these components or the corresponding components In a parallel train since the 1909 RFO.

cOmpn.nent LocAtibn Location

• Notes 6.5... ' FPR Elev. -41 o riot . train were inspactad n

r: 0I "01006 f.I: Heate'r Bay E[Ovs 228 Corrioneri s on dther tealn were En1998.

Ittd FQo7EL1 I & 248 Results indipate minimal Wear. After updating the CHBCW..U-Ks m.d~l with newer dzta, assess need

- ------ -__________ 110r0,0011t0nau1 iFlspw-ions. in 2007RO FDI01EL12 00.6 T.B Heater BayElev. 2468 F.ee0tr heater replacement occurred in 2004 RFO.

Inforhmal AsuaJl inspdctions of internals and cut pipe profillelndifated W .r p.atrtaw, a stable red oxide and no distinghuislabla 0.F1T-E3.I 0o2 TR.X E 286 Seater Bay.Tlevs M. cfpelhehe s FD0oEL06 & F199 Du er FMSELO!" & 248 lrispectid in 10*F. Af1stlts ietrite minimal wORKS. A.t U withng newbr dat* Ks.seods neth foewer datrtg as__ n.ed fqr itn 0 inspoling comicponenets ot t9PO

.InfK .ri . spba s of intena~s cqt pinkie I di,,t a st1i~e rock oxide.andnoo jsthabisabt,

... ... .. ....... wear.p.* rný

• J=D*:LO8 073' RX St ý f uhnel El. 266 WMnVteon*:i'Sa. ofelb.W006*l~ d~r io 19"966iCi~giftp -

vaiveiýJepl, n-ment, no intioation of wall fu;sS affhdt.tifri.

Corresponding component on line 16"- FDW-14 vias inspected in RFO24, After updating CHEMWORks model wit~h newer data, assess need for inspectin~g this oomponejlt in 20W73170, '

Page 4 of 14 NEGO37107

VY Piping FACInspeotion Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets/ Methods and Reason s for Component Selection LB: Large Bore Components Ranked High for Susceptibility from CHEOWORKS Evaiuation - continued Condensate System Only one component was identified as having a negative time to Train. This was CD30TE02DS, the downstream side of a 24e24x20 tee on the condensate. header in the teed 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 satne tee. Other tees on the same header have been previously inspected ahd show no significant wear, The CHEOWORKS model includes UT data up to the 1999 RFO. The inspectidns on this system performed in 2001 indicate min mal wear. Components CD3DTEQ2 and CD3OSP04 were inspectrcf in 2004. This data along with the 2001 inspection data will be input to CHEOWORKS to better cafibrate the model.

Moisture SeoaratoT Drains & Heater Drain Systen, N6 componehts idehtif ld as h.ving negative times to Tmin. No components wete selected for inspection in 2001, 2002. or 2004 based on high susceptibility. However future operation under HWC will change dissolved oxygen it syStln'i. A separate evaluatiton has been performed and components were selected for inspection in 2002. See Svotion LO below.

Extractidn Steam System Tltree so*wponents on this system with negative time to code rain, wall: The piping is Chrome-Moly. ES4ATE01 &

E4ATý', 30inch diameter tees inside the condenser have negotlae predictfon (-3426&rs.) feo tUrns to m16 WAIl. The train may be conservative baWed oh the modelingltchn[ques used, Rofinemeht of th-e nixil.} debf-tis sy~tamis ini progess. mI~e regative tf i n lot .st likely auntidn-of -tank of inspecion data Ysj- *ao.*.W,-'.

• Diitc~~tiha I~2g on thi ping and telcbatiatnido h condbn.5er, noi:corniperrets aresleei6166tna r UITir~ie:httdn of in 2004 all t~b~EtraEtion .ý based on Insde Iifea 1les high suscep6tiility.

the condenserHoaiev1r, an pit.prtdnity dttring planed to work LP tbrtirie peri.ori ab 2006:Ab InternalvisdalHiii'i.fb in Me m.ay'idhtt itself. S.e Section LF belw.

Note the short section of straight pipe or line 12"-ES-1A at the connection to the 36 inch A cross arouhd'is.asswmuied to be.Alo6 Gr. B carbon steel is not modeled In CHECWORKS. This compbnentwas inspected iti 2004 by eletftirh.

UT arid a&i internal visual inspeitioh from the 36; cWrossaround line.-

Page 5 of 14 NEC037108

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Component Selection LC: Large Bore Components Identified by Industry Events/Experience.

Review of FAC related Large Bore Operating Experience (OE) and/or piping failures reported since April 2003 Date Plant - Tye Description & Recommended Actions at VY 8/912004 Mihama 3 - OE19368OE108895: Rupture of Condensate line downstream of restriction odiks.

PWR PWR system highly susceptible to single phase FAC due to low DO. Similar region of system as I986 Surry event (5 fatalities). Based on info gathered by INPO/CHUG/FACnet the locatkmn was omitted from previous inspections due to clerical error, once discovered managemrent missed opportunity to inspect and deferred inspection until 9104. Too late. Lesson: make sure all highly susceptible locations get inspecfed. PWR Condensate/feerwater piping is much more suscdptiblo to single phase FAC than BWR with 02 injectish. Given that, previous inspec!0n history, and condensate CHMCWORKS modelng; in*j.ct plpIno OS of all flow orifices in the higher temperature condensate system ihat have hot b.n previously inspected in RFQ25. Inspect CD30FE01 I CDOMI I/ 11 Gl0S0p2 in Pi' (r6.pe6M lns.e'ptwon from 1.#9). AFso, inspect ciW01 I

__________ Cfl0$PQ4In R170S (n~wi.isW6oIAt 10/17/03 Duane Arnold OE01.300: Through Ywall leak In4"di~iftetr ohrmom-mol9 H,9atqr.Dmin-Sysýtem BWR bypats tine to the condenser. The lihevwas a tfmsreary insi~llWWen die-to delayed FWD heatfr installatioin The cauLe of the leak appears td be dr~opleimpingpmunt erosion'due to uwe Of a bypass control l Thl&..quiy.eaqu.valent lde~s.at W ard-the Hea14r Drain bypss lines-to.the condenser -*.dcwistr6arm i1.:1 h*h .t aol..httol1 va.l.s. These line have.kTi.*..attached 'to Mon ittor lIakj.., in.to.* h"nm ':er re rf~oibnQny i PM indfas Ie06Mj tiet ma.oa~d~~4e 9/403 Suh Texas O.... 738Rig&itra erfudondsh .- ii iOitr~t Project - FVWR Polishingj Pi,pe isc'arbon teel l0W. w-taiPfir@4i`e(90 to1 AMF), ne utral Fyte pH IAnd velocity Of 1J2,..2- Ftsc Totuom'us flow pfaichribl~ brmyb lmpinueriment PWR system L ow. dissolvd oxyg. Equi.anttem-a.VY is Condensate Onrnineralixzer S~ystem which is tow tenp.and are;r:per N*AC4O02L 11/7/3 ~~lWbod 2- 00117,4!4 WAi0Wth6011i'4it~y ow t m, 'DMu*,hYg A-1~iq

. *,M~¶ni4 '

_____ asnotpu srt.pti~hl to~PCese'..d*Di) t~er **tipriiuo .-NO. ouf~lW'**-t.t*.N f . prthe n Pll .ku 's. M.e ri . " .  :.s . . §*

duertO lhl phast FAG t~n bWTAeloWaer-plp!66g- aty~l$&

pufflp disgirnrge no1Aes-.ýrid` dWhMf~fttMPpký'Mog mufijpleP rh~ ion - No 10/31/03 Clinton -.BWR OEe 7412IOEI847t3 Thtrtwh- I.in leaks" 2N B h4etVariHeser (lager bore lines assumed given ddrcription of backing ringa in piping). Ap5parert cause attributed to steam jet impingement from wet sleatm. Equivalent tine at VY is common 4 inch feedwater heater vent line for No.4 FDW heaters. This line is ineluded in the SSB database sinio it connecis to (2) 2-112Ilies. nPspection priority will be determined in the small bore rankin! and..pioritizaticn.

1/91/03 Hope Creek - OE17700: Pinhole leak Aid WalFthinnirig inF"in caroft steel.ExtractionWStath BWR supply line to Steam Seal Evaporator. Location of wear is dbwnst.eamr of pr.ssure safety valves. ApparentCause of leak & wear is due to liquid dropl*.*f UipingeirMht due to high flows from failure of pressure safety relief valves, No equivalent

.... configuraton at \N.

'1/24/04 LaSalle 1 - BWR OE17199/OE18381: Tough-wall holes in extraction steam piping inside condenser.(

Location of holes at inlet nozzles to No.2 FDW heaters located in the neck of the condensers (2d lowest stage), All 12 nozzle are 0.S. with A335-Pl I upstream piping. VY has only the No. 5 FDW heaters in the neck of the condenser. The No.

5 FDW heaters were replaced with Chromo-moly shells. ES piping is A335-Pl 1 or

"______ _______equivalent which is FAG reejlant. No further actions are anticipated from This OE.

Page 6of 14 NEC037109

K VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets f Methods and Reasons for Component Selection LC: Large Bore Components Identified by Industry Events/Experlence - continued Date Plant -- Type Description & Recommended Actions at VY 2/17/04 Peach Bottom 2 OEl 8637: On line leak in 10 inch main steam dfainline header to the condenser.

BWR Hole was located directly below the connection of 1' main steam load drain. The header was replaced with 1-1/4 Chrome material approx. 5 years before the leek.

Also, ROs in steam drains were modified, The cause was attributed to steam Impingement. Additional information to follow after next RFO. The only large bore drain collector at VY is the 8 inch diameter low point drain header, line 8"MSD-9.

Flow is through steam traps and LCVs Vs. a continuous flow through a restriction orifice. This line is now part of the AST ALT boundary. Inspections of the entire bottom of this header werb performed during FFO24 with recommenidations for repeat ins-edtitins in 2010.

8/6V4 Pid V~erae rOE203e : Through wall leak found on a 1d inch flash ng tee cap on the LP PWR f fedwater heater drains. Probibms with inspection of flashing tees in pmoram. Only 14 out of 153 susoeptible locations have UT data at Palo Verde 1,2,3. There are no flashing teeos DS. of LOVs on the heater drain system at VY. The only flashing tre&

at VY ar6 located on the FWD pump min flow lines at the condenser. ;ig**pfion of aa.I.1ne, WT--*W.4,0"FDW and. 6"FPDW-, is scheduled for RPFQ25.

1424/04 Palisades- PWR O02 9M4: Wall thinning in edrbtn" el Ext* in Tm piping. lancreadd localized wear downstream of Bleeder trip valve.. Equivalent piping at VY is Extractio Steam: pipjng-downstreafn cif the revirse current valves. E9 piping at VY

,fA-P 1 b~h lACt teslels4nt No~iuftieractiorIls reeuired for t1hi' Q" 918104 Cata4i~aba 2 - 0EIO05SO Wall thinning fon'd -four diff-tent ara p OW. piping. Tv.id:dtira5 are PWR not consider'ed specific to Cataw4b' I)Ar.a Wh*I mhain fee.dwatfr byl,.4.s r g valves, rent.rs the faedwnter hc'41er an. 2) d*onýtearn ol 1hie mait t e r rag valves PWR feedwater system hemfistry-haslow D.CO. therefeie rdsr ptible towall loss. due to single phase FAC than BWR.feedWater piping. At VY aýrA 1) do~~~snot exist (bypas lines -dumpto the oonaehsr.-) 2) lnspectlions have-teein pe ustr~em qile apd dMW)Sttream of both mi Odrp avs dJ~ino jfl l1$p2ar ~edtd main. fOWP~d$ N~;afolei- 1" ofW 11/3/04 Duane Arnold Of01Wtfl: Wa.thiruNir g downstreaml of Torus*161 Cooin4Tst etrnHede Isoltio BWR valve.. Apparernt causae was Cav"tllon-vetibn duO to-t o.ing. in valvW duImHPC,. I

&"I3010 tabing. At VY, the6-uiralefntv'alJes are VO-4MA &8,M.. T-hd'dQ: of oavlt~li.on present Is depdeht Of the sy~sein design and may vary forom - it to plant. Previous UT inspections were performed o.n vave bocdies and dcwiýh4teb/n reducers in early 90s. No significant wear was found. Consider inspeattlio of downstream piping in RF026 if additional OE warrants It.

2/6105 Calvert Cliffs 1 - OE20127: Through-wall leak in 6 inch steam vent header for MSR rain lank, VY PWR does not. have sarne confgurepiion. NO Molptur. $eparatpr Re-hoaters 2/1.7/05 Clinton -BWR 0E20. 4.S; QaCtastrophic failure of turbine extraction steam line bellows inside condenser. Found through-wall holes ES piping DSof bellows due to FAC. (

Apparent cause was attributed to the steam jet frorm the holes induoing vibration of the expansion joint that led to high cycle fatigue failure. At VY extraction steam pip*ng inside the condenser is A335.PI 1 or equivalent which is FAC r~sistant. No further actions are anticipated from this OE.

5/9/01 Grand Gulf - Pin Hole Leak in 4 inch carbon steel elbow in RHR min flow line. System has low BWR use at VY (<2% of time). ( Perry also found thinning at elbow per C.Burton at CHUG meeting.) A review of VY drawings VYI-RHR-Part 14 Sht,1/1 and VYI-RHR Part 15 Sht.1/I show elbows downstream of restriction orifices. Previous VY Inspections downstream of orifices on HPCl/and CS systems foundno problems. Keep OE listed for future consideration.

Page 7 of 14 NE*CO37110

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets I Methods and Reasons for Comnponent Selection LC: Large Bore Components Identified by Industry EventslExperionce - c ontinued Date Plant - Tye Description ,&Recommended Actions -at VY 9/24/02 IP2 - PWR Pin hole leak on 26 1/2" cross-under piping (HP to MSR) in vicnity of dog bonds at expansion joint under location of weld overlay localized wear under/around a V1gual previous; weld overlay repair. VY has solid piping (no expansion joints). 205.

Inspections of 3W" 9 CAR carbon stel iin, will be performed In 1i/15/02 Surry 1 -PWR Leak in 8 inch Condenser drain header for 3 QI4 pt. FDW Heater venfs. Also CHUG thinning in Gland Steam Piping inside the condenser and IheI2" Condensbr Drain Meeting header from MS Drain trhp lines. The only large bore drain collector at VY is the B inch diameter tow point drain header, line "M9SD-S. This fine is now part of the AST ALT boundary. Inspections of selected components on this line Were pertoemred during R FO24 with recommendations for repeat inbpeotions in 2010 (Section LB above). Given this line is part of the ALT Boundary Intspect. apprfx. 2 ft; torig sveet1n at condenser wall dureiig flO2O (2007) or RFO2Y (2009.

LU) 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 aO2 ingp .tioh dtta has been loaded however wear rate analyses have not been completed at this time.

In 2'001 o.ir*tpnerits 6n the higher temperature end of the Condensate System. were lnspeted to cal0brate the CNIEC.'WO F(.S.mdi s. The ihspection data indicate minimal wear a*id shbould reinforce the assessnt of 16uw wear in the Cdrdeneat" ysta m. Additional compon~nts seleoledtor inspddtion in 2004 in Section LB above will 6e used to calibrtatd he CI4ECWORKS modeL.

Eftatbr.. .Win Moisture Sela__tor Dmins:

Pior te .-. 02 R'O there waslimited nspecton dat for the Heater Drain system. The current CHECWORKS md4~ (w*b anZd Come Pass 2) idicate low wdar rates. During 2-002 a number of ndw inspaotons w*re pYeftdU On th.e* carbo*n ste'el piping upstream of the lyevl control,Valves (tCV) to obtain a balirie:friov't operation 6t*deh watr chestry. Piping down stream of the LaVa is F'AC res*stant niaterial ex*cpt for iWoet 16 W65 Feadvate" heaters. No additional components on the Heater Drain system will be inspected in Ž005.

Feedwater:

No inspections on line 18"-FOW-12, have been inspected: Inspect FD12EL06 and FDI2SPOUS 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. In srect MS1 DEL07 and MS1 DSP W1S in 2005. ( Note this also addresses a license renewal consideration for monitoring of Main Steam Piping).

Page 8 of 14 Ný NEC037111

VY Piping FAC Inspectron Program PP 7028 - 2005 Refueling Outage Inspection Location Worlsheets / Methods and Reasons for Component Selection LE: Large Bore Components subjected to off normal flow conditions id entified by turbine perfornance monitoring system (Systems Engineering Group).

The Systems Erngineering Productbion Variance Reports for 2003 listed the "B' and "C' leedwater pump min flow valves'as leaking into the condenser. There are sections on carbon steel piping at the connection to the condenser 9n all three lines. As a minimum Inspect the "B" and "C" lines In 2005, There have been concerns with cavitation at condensate miri flow valve FCV-4. An intemal inspection of the valve performed in FRFO 24 showed some damage to the valve internals. However, due to a leaking isolation vai've the ocTlinhrg piping was flooded and an internal visual inspection could not be performed, UT Inspect the upstreaot adnldo~wnstreami piping during 0F026, The valve is operated during outages and startup at felaively low tiemperatures for FAC to occur. The piping is un-insulated and close to the floor. No insulation removal or scafot*ding vAll bie r~quired.

Since startup from 2004 (RF024), no other leaking valves or steam traps have been identified (to .ate) using the Tutffino Pe.tformance Monitoring (TPM) system. However, if new data indicates leaking valves then, additions to the outage scope may be required.

LF: Epginering Judgment/Other Nine A_,%NE Section XI Glass 1 Category B-J welds are to be inspected by the FAC program per Code Case N.56 in fj'+oft.&.S$oclon XI volumetric weld inspection. The VY I1S Program Interval 4.schedule for irnspetion bf thee Welds.

Rý4ur Ou*tag Section XI Description FAC Program Comrnponents IS[- Pgrnam Weld rwt-F3B3 uip'treatnjipe to tee 'A"Feedwater on Sketch 0110 FWIS-qFC tda lo rdoucer FD1T.E..01t "

trval4 FWI-9F4 redp.cer to pipe FDNEADP)i

.P~ilodl1, FW21-Fi tee to pipe FDI"QSFO4 Outage 1. SD21SPO1 Pall 2011 (RF029) FW 1 8-3A I>upltream pipe to tee "B" Feedwiter on Sketch 016 Interval 4 FW20-3A tee to reducer FD18TEQ1 Period 3, FW20-FI reducer to pipe FD20RDO1 Outage 6, FW20-F1B horizontal pipe to pipe FD20SP01 FW18-F4 tee to *ioa FD1eSP04 Continued Page 9 of 14 NEC037112

2 VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection f

LF: Engineering Judgment IOther -continued Extended Power Uprate (EPU)

-C.

Feedwater ystaem:

EPU evaluation for Feedwater System: The primary focus of work to date (for PUSAR and RAis ) was on velocity changes given onty.slight increases irt temps and no chemistry changes. With ail 3 FDW pumps running the 16 inch, diameter lines to the 24 inch FDW header have approx. [1.2(2M3) = 0.80120% reduction in velocity, Veibcitias in the remainder of the system increase approx. 2V16-, The highest veloOlties are at the 10 inch reducers upstream and downstreaffi of the FDW REG valves. The expander and downstream piping have multiple inspection datawith FD07R003/rFD07SP03 last inspected in 2001 and FD08RD03/FD08SPO2 last inspected in 1999, Both of thent6 segments shoiud be re- inspected after sorie time of operation at EPU flows. Assumvnjg EPU stating early in 20065, inispect components FDOB*R*03 & FP60$P02 in 2006 to obtain an up to date pre-EIU measurettte'nt.

Inspect FDO7 I FD07SP03 In 2007 for a post EPU measurement.

S03 9

Condensate System:

Given the 8/04 Mihama event: consider additional component in the condensate system for inspection:

downstream of flow orifices & venturies:,

FE--1O2-4 and downst-eam pipe on 24"C-8 venturi type (TB condensate pump room overhead) Given low operating tprnp&r*wre aod upstream of oxygen injection point, scope out and evaluate for in~spection .in RFtb2B.in 2007 FE.52--"A to FE-62*1 E.on0ndensata De-rnlnetaflz&r Sytem ( Restriction Orifices). Gfvbn low.

oper#trng temperp.e.rea and upstream of dxyg6dr injection point,, scope out and eValuate aor inspetoi i F t1h2 n20 FE-1 O24and dconosft!feA pipe on 14'C-21 venturi ty0p TB Heater Bay El 237.5 Given low opeirating tempeiratums and us6dtfbr start-up, scoPe, out.and ev ai.or inspection in RFO2S in 26 V FE-102-2A. oT0 ly the T b bl .r"Wfr*-p 1A (venturi type) Previbusly FE- 02-P$B on 2*0-31, ftAfeWf in the TB FPR 1bove FOW pur.tp I B (venWturi typo) No previous inspection data. rnsp'o Ft and downistream piping In RFVO25 FE-I 02-20C on 200-32, located in the TB FPR above FDW pump 1C (venturi type) Previously inspected in 2001 All Extraction Steam piping is A335-P11, a 1-1/4 chrome material, except for a short carbon steel stub piece in line 12"-ES-1A at the connection to the 36' A cross around line. An internal visual inspection of this stub piace WaS performed with the cross around inspection in RFO24. Also an UT inspection of ESI ASP01 was performed in RP024.

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 ipportunity 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 NEC037113

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets ! Methods and Reasons for Component Selection LG: Piping identified from EMPAC Work Orders (malfunctioning equip., leaking valves, etc,)

Word searches of open work orders on EMPAC were performed for the followingkeywords: trap, leak. valve, reptace, repair, erosion. corrosion, steam, FAC, wear, hole, drain, and inspet. No previausly unidentified components or piping were identified as rtquirhng monitoring during the Fall 2005 RFO.

Note: the internal baffle plate in Condenser Bior the AOG train tank return line to the conden ser is to be replaced in RFO 25 (ER 04-14541 ER 05-232 !ER 05-0274). Erosion on baffle plate is from condenser side (not piping side).

Internal visual inspection of LCV-103-3A-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 1590. The line typiically has no flow. Re-evaluate using the Thermal Performance Monitoring System Data and consider inspectibn vi downstream piping in RFO2S.--.

Through wall leak in the steam seal header supply line I SSH4 discovered on 9/24/04 (GR-VrY-20044)2985). A temporary leak enclosure was insta'led and a planned permanent repair is scheduled for RFO25. The leaks are on the bottom of uninsulated piping upstream of the gland seal. Field inspection of the leak location shows that the pipinlg at the leak sloping d6Wn to-tho gl.and seal, not sloping up to the seal a shown on the design drawings. UT data on the topi of the piping rhdr the leak shows fI'ti wall thicknesS. At this tirne, the exact m~echanism which huised the leak is not known. Additional inspections t6 determine the extent of condition on the 3 other gland seat Mtearm supply lines are required Insoct.the 90 dtgree ellow and appr6x. 2 ft. of downstream piping on lines 1SSH37 1 SSH4, 1 SHS, and 15 "durinAi- 46o-. Also b*abs on Industry OE and sirmiat piping geomery, ihspect 2 of the PE lines (1P3arid 1AVdfn IO28.

0 Page 11 of 14 NE0037114

(I VY Piping FAC inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets / Methods and Reasons for Component Selection 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 operating tine. No wear was found in previous inspections on Heater Vent Oiping from the ND.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 oan be deferred. The existing small bore date base and the piping susceptibilityanalysis is under revision, No additfonal corriponerts from Revision I of the data base will be inspected.

SB;Compo.khsts solected from measured or apparent wear found in previous lnspsetlori results.

Smtalt Bore Point No. 20. 2-10r MSD-6 @ connection to condenser A at Nozzle 33 (Inspection No. 96-B01 identified a low reading.at weld on stub to condenser). Upstream valves are normally closed- TPM system does not indicate any abnormnal flow. thspoct this piping In RFO 26

'A through wall teak in the turbine bypass valve chest 1" seat leqk-sff line form the No. I bypass vales occurred in 200.; (VY Event Report 2.63-0*44). A tetpor.ýy le~k enclosure w4s lstslled (T.M,2003-0W2) to contain the leak).

WV . 03-0.35 wasf rittn to inspectlfepainIr.pface/line. A loallzed ii64*oiNike (.arbon st6ee) replactbft o ibe leak location was perf6ru*be-inRFO 24. Additional inappctibns on this Rne dentirfifi6 l6aliebd Wall klss andf ne addiif6riai like-for-like rd-palr was performed. Engineering Request ER 04:0963 was writteh to compietely replace this pipjnig With oh*rome-mroy piping. (Dresden has already done ftis). The replaceent (ES 04-0964) is cuitsritly stbddtled for RPO 25. If this activityý gqt~s '4"d-coped" then -diintIneton w-Al befqieoisueiepjiI Is ac10Wptnbl for eorkitbnsd OjSrktiob.

Page 12 of 1.4 NEG037115

VY Piping FAC Inspection Program PP 7028 - 2005 Sefueling Outage /

Inspection Location Worksheets I Methods and Reasons for Component Selection Small Bore Piping SC: Components identilled by Industry eventslexperience via the Nuclear Network or through the EPRI CHUG.

Date Plant -Type . etion&Recommended Actions at VY 11/7P2003 Limerick 1, OEI 7818: Through wall leak in 1 inch drain line back to condenser off ES piping BWR at the connection to the large bore line. Normallyno flow in line due to N.C.

valve. Piping downstream of valves to condenser on all 3 lines w-s scheduled for raplacement. Location US of valve was thought not to be sdsceptible.

ES piping at VY is FAC resistant A335-P1 I with no drains back to the condenser. Lesson from this event is any carbon steel line in a Wet steam system is susceptible &should be monitored. Also ful line reptacement insures all susceptible piing isreplaced. ....

1/16V04 Clinton - BWR GEl7S54: Pdt*htihl tenid for adverse equipment condition downstream of orifices. (Ref. Previous experience a Clinton with CRD.pump rain flow FiOs)

InspetQCRD pump fldw orfh fFO2Sl aaso piping pp !)S of B0-64-2 in 122/08/04 V.C. Summer - 0E19798: Cronplete failtira e-a 1 irt.h ES Rile at the kiif otteof a pfrvia-uqsly PWR installed Fetmarnite clamp repair. Previous leak at weld in§tWlted in MAY'2004.

See presentation at January 205 CHUG maeting. (Thoy diL hot do UT on ffe

.pip..e.to auropucty ral*inteL Prior _y to installing :th*clamp.)

31W/06 McGuire 2- Thtiough-walt 10,in a 2 inrh carb6n stetýivefit- ite on thie'MS heating steam PWR vent line. Causedby FAG when fashlringoo~urmd upstream of Rd,(d6sigh iAt VY.i~

(I . -w . "

4/29r99 a4ýI'1'hbý~ atIt' connedtidn. EqA'nlezigt to PHWR HH8 @.tm (INPO Eveint 931 9904291-) Threaoded c typically lnneotidns oil 6da.nsate side of HIS.pipinjg .Low"er en*rgy/cosoequeohe 6f le04k. Include KHS 0pip9hg. i FAG S's.pib.ly .ReIew and in the.Small Bore Datdt9a9s.

6/--1/9 2-

-Dar-linlgton Le-!

ak or to steafat tra p.ipeat-l tfe~eOct gos.iarg Cdnntion. EtuivWl~rtt bHHS1 PHWR tern at VY N1O. Evt*. .9..0.0614.4s i me aýbov*.

9/1/01 Peach B6otom (From 1114j102 HUG.OH Metnig)

.0 .e n 1 In¢. S0h $lfroin -*Off G'at Rb-43 i v6 e,10 eti 9 ac oitAnr-`~dppi~ ~iea:WW-0 'lfl~

P16//0 Hat&1i112 nCoM- idhnser'in 166kaýe dtia td thtodgh Well eoih rQoV) ih"lp CHUG Mtg. drain. lines inri- the condenser. L.nes Ineach unit waeir cut: a4 c*a0.d

• 'similar events at Byron Unit) I(OE 1'209) 0'd Columbi' (OE1214) Lhiritk &

Dregden. VY slop drain lines inside condenser were walked olown during

-F024. Some external erosioon on piping and supports was found.

1/15102 Catawba 2 - Leak in HP turbine pocket shell drain 1 inch dia. OEM showed pipe as P-11, CHUG Mtg. PWR However, A-1 08 Or. B was installed. Inspections were be perormed on this line in 2004 to base Fne con.ition pujor to HP turbine rotor replacemept.

1/15102 Dresden 2 Thihning found in Bypass valve. IeAk-of line to the 7"stageextrion se CHUG MRg. EWR line. Line is 2" Sch. 80, GE 84A39B. Lowest reading was 0.070" found using Phosphor Plate radliography. Une was replaced with A335 P-II. Same line as 2003 VY through wall leak. Partial CS replacement was. performled in RF024.

Piping is scheduled to be replaced with. A,35-P1 I inRPO25 (ER 04-0965).

Page 13 of 14 I

NEC037116

VY Piping FAC Inspection Program PP 7028 - 2005 Refueling Outage Inspection Location Worksheets/Methods and Reasons for Component Selection Small Sore Piphi9 SD:CowipDnents subjected to off normal flow conditions, as indikated frotthe turbine performance monitoring system (Systems Engineering Group).

No small bore lines have been identified by Systems Engineering on or before 3/1/05.

SE: Engineering judgment Look at piping DS of orffices based on BWR OE Condensate: Given the 8/04 Mihama event: consider additional component in the condensate system for inspeton dowmstream of flow orifices & venturies.

FE-102-6 and downstream pipe on 21/20C-43 venturi type (TB heater bay elev. 230+1- Given low operating ttMpertLures and upstream of oxygen injection point, scope out and evaluate tor In ppmtifo ih R86 in 2007 SG: Piping Identfied from EMPAC Work Orders (malfunctioning oqulp., leaking valves, etc,)

See LW above. The EMPAC search performedin LG above is applicable to both Large and Small componerits.

Page 14 of 14 NE 117 NEGO37

MEMORANDUM Vermont Yankee Design Engineering To S.D.Goodwin Date May 5, 2005 From James Fitzpatriok File # VYM 2004/007a Subject Piping FAC Inspection Scope for the 2005 Refueling Outafe (Revision 1a)

REFERENCES' (a) PP 7028 Piping Flow Accelerated CorrusionInspection Program, LPC 1, 112/6/2001.

(b) V'.. Piping F.A.C. Inspection Program - 1996 Refueling Outage Inspection Report, March 23,1999, (c) V.Y. Piping F.A.C. Inspection Program - 1998 Refueling Outage Inspection Report, April 2,1999.

(d) V.Y. Piping FAG. Inspection Program - 1999 Refueling Outage Inspection Report, February 11, 2000.

(e) V.Y. Piping F.A.C. linspection Program,- 2001 Refueling Outage Inspection Report, August 11,2001.

(f) V.Y. Piping F.A.C. Inspection Program - 2002 Refueling Outage inspection Report, January 20,2003, (g) V.Y. Piping F.A.G. Inspection Program - 2004 Refueling Outage Inspection Report, February 15, 2005 (h) DISCUSSION Attached please find the Piping FAG Inspection Scope for the 2005 Refueling Outage. The scope includes locations identified using: previous inspection results, theCHEOWORKS models, industry and plant operating experience, input from the Turbine Performance Monitoring System, the CHEOWORKS study performed to postulate affects of Hydrogen Water Chemistry operation on FAC wear rates in plant piping, and engineering jutdgment.

The planned 2005 RFO inspection scope consists of 37 large bore components at 16 locations, internal. ihspeotion of three legs of the turbine cross around piping, and 5 sections of small bore piping.

Also, any ihduatry or plant events that occur in the interim may necessitate an increase in the planned scope.

I vill be available to support planning and inspections as necessary. I1you have any questions or need additional information please contact me.

(Revision 1 identifies Smafl Bore Inspections due to industry OE).

• (Revision la adds component Nos, to SSH & SPE piping & corrects inor typos in Attachment)

[@,*n, e.Fitzpatrick SDe n Engineering Mechanical/Structural Group ATTACHMENT: 2005 RFO FAC Inspection Scope 3/11/05 (3 Pgs) Revised 5/5/05 CC L-Lukons Code Programs Supervisor DIing (0St)

T.M.QOonnor (Design Engineering)

Ne0l Fales (Systems Engineering)

NE-037118

ATTACHMENT tv.. sYM 2004/007a VERMONT YANKEE PIPING FAC INSPECTION PROGRAM 2005 INSPECTION SCOPE (5/5105) Page I of 3 LARGE BORE PIPING: External UT Inspections I Point Component ID Location Location Previous Reason / Comments / Notes No. Sketch Inspections 2005-01 FF14EL03 008 iT.B. Htr. Bay Elev, 267. 1999 1999 recommendation for repeat inspection.

2005-02 FD 14 S P0 3 SU S 008 " 1 199 9...... ...... ....... . .... . ..............

2005-03 FDO4RD01 017 T.B. Htr, Bay Elev. 245. 1999 Inspect per 1999 calculated wear rate.

2005-04 FDO4TE01 017 1 1999 2005-05 Cond Noz 32A 017 " 1999 2005-06 FDOSRD01 018 T.i. Htr. Bay Elev. 245. 1993 TPM system indicated leakage by normally 2005-07 FDOS TE01 - 018 " = 1993 closed valve.

2 0 0 5-0 8 C o n d N o z 32 8 0 18 "

... .19.3... ........ .. 1 9 9. _ _.............

2005-09 FDO6RD01 019 1/2... itr. Bay Elev. 245. 1999i Inspect per 1999 calculated wear rate, Also, 2005-10 FD06TE01 019 " 1999 TPM system indicated leakage by normally 2005-1 1 Cond Noz 32C 019 1999 1 closed valve.

2006-12 FDQ8RDOS 011 T.B. FPR Elev. 231 1999 EPU flows increase.

2005-13 FDO 8S P0 2 O l0 . " . . .. U 1999.....................

...:...... 9 2005-14 FD12EL06 007 TB. Hit. BaRyEev. 264. NO Cheoworks Model Calibration. Asbestos 2005-15 FD12SPo8US 007 " " NO removal required.

2005-16 CD3OFE01 037 T.B. FPR Eiev. 241 1989 FE-102-2A (Mihama Event) 2005-17 CODSOELI 1 037 above "A" FOW pump 1989 2005-18 CD3OSP! 2 037 .... ,... .. ...... . 1989

~

______________________ A A A .1.________________ _________________________ __________________________

NEC037119 K

C-ATTACHMENT tz.- YM 20041007a Point Component ID Location Location Previous Reason / Comments / Notes No. Sketoh Inspections 2005-10 CD31 FE01 J 038 TB. FPR E 241 ~ev. NO FE-i 02-28 (Mihama Event) 2005-20 0031 EL04 038 above "B" FDW pump. NO Asbestos removal required.

/I 2005-21 CD31SP04 038 .. NO I 2005-22 CD21 RD02 040 T-B. Htr. Bay Elev. 230. NO Inspect piping upstream and downstream of 2005-23 CD21RD01 040 " A 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 1~SSH3SP06US _ 3 Htr, Bay Elev. 254. through wall leak at elbow on line I SSH4, 2005-26 ISSH4EL01 - Turbine deck at packing NO 2005-27 i$SH4SP02US _ 4 Htr. Bay Elev, 254, *See markup of Dwg. 5920-1239 2005-28 1SSHSELOI Turbine deck at packing NO 2006-29 1SSHSSP02US 5 Htr. Bay Elev. 254.

2005-30 1SSH6EL06

• Turbine deck at packing NO 2005-31 ISSH6SPOBUS C6Htr, Bay Elev. 254. _

2005-32 2SPESEL01 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 en line 2005-,34 2SPE5EL01 " Turbine deck at packing NO t SSH4.

2005-35 2SPESSPO1US

• Htr, Bay 5 _____ Elev, 254.

_____________________ *See

• Markup of Dwg. 5920-1239 2005-36 MS I DEL07 080 RX Stm Tunnel Elev. NO EPU and LR data required for Main Steam lines-2005-37 MSlDSP13US 080 254 to 260 NO LARGE BORE UT NOTES:

1. Coordinate minimum extent of insulation to be removecd witU' JFtzpatrickor T.M. O'Connor from DE-M/S.

2. A -NoWin the previous inspection oolumn indlostes asbestos abatement may be required.

Page 2 of 3 NEC037120

ATTACHMENT tVY IM 20041007a LARGE BORE PIPING; Internal V\wual inspections (with supplemental UT as required' ln~s ection Point No. Description -

2005-38 .. 36" CAR A (36 inch diameter Line A Turbine Cross Around under HP turbine) 2005-39 36"1 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 uqper east side of heater bay)

L SMALL BORE PIPING 2 Small Bore S3.B. Sysltem Description Location Drawings Reason /Comments Inspection Data -

Numtber Base No.

Die R 42 TB.Haer Bay 1II15 Sht.1 tndustry 0E17654 19 Condensate

.... .. .. : ...

• V'pipng

....... 5920- FS1[ -t17 05-SBO2 130 C 1" Piping D.S. of R.O.-3-24A Rx. SW Elev. 232.5 0G19t170/ G191212 Industry OE17654 05-804- .131 CR0 1" Piping DS, of R.O,-3-25B P38-lA Rx. SW Elev. 232.5 1G191215 G191170/G191212 Industry 0E17654 05-$806 J31 CRD 1"..Pi;Fipin~g D,S, of R.O.-.3-25B P38-1B Rx, SW Btev. 2S2..5

/G191215 191170 /0G191212 Industry OEI 7654 ...........

P38-18 -r11191215 Page 3 of 3 NEC037121

(COLL"N LUE F)

MATCH LUCESM-TC I~fl~O/

/

REVISION 1, II/241/9 wS 01A OJUTLST r# VERMONT YANKEE PIPING EROSION-4 -1 7

HOZ&E HEAT"*EGI CORROSION INSPECTION PROGRAM S>A FEEWAThR Lil 115-FOW TURBINE BUILOJQ-HEATER BAY REFERENCESt 0i91]157,1191 182.GIS I 1833"928-FS-I25 COMPONENT LOCATION SKETCH No.0B I

lAppndix A PP 7028 Ofiginal Pag- 13 of 202 NE0037122

TURBINE BULDN'4--EED PUMP ROOM/HEATER 3AY RERENCESr tgt1 157,GI91182tGI91 ea 5950-F$-124,5It2-FS-4/5 REVFS!CN ht f f24191 VERMONT YANKEE PIPING ERO$ON-CORROSON INSPECTION PROGRAM 15' FEEDWATER UNE 4'-FDW-4 COMPONENT LOCATION SKETCH No.0[7 Appndix A P? 702:80iginaJ Page-a-2 of 102 NECO37123

FD05ELM

?EATER BAY S\ % VERMONT YANKEE PIPING EROStON-PROGRAM CORROSION INSPECTION TURBMNE 6UtLDNG-FEED PUMP ROOM/*IEATER BAY FEEDWATER LINE 41 -JVW-5 REFERENCES, G 191 157,G 191 82,G191 11J3 5"9,--FS,-124?20-FS-r25 OPCPNENT LOCATION SKETCH No.O¶8 Appndix A PP7O28Oigimna Pa 23 of 102 NEC037124

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Appendix A PP 7028 OiginaglPag.* 24 d 102

• I

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AppeodLx A PP 702 Oriýna1 Pagv 2 of 102 NEC037127

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C0SO5PtS (FLANGED SPOOl PEICE 16'X27 R*¢DUCER SFEEDWAt PUMP VERMONT YANKEE PIPING EROSION-CORROSION INSPECTION PROGRAMfi COND*NSATE / LINE M'-C-30 (CONTINUEDI TUR*13tE BUIYNG-FEDWATER PUMP ROOM REFERENC-ES: Gi9g 1*57,G 19 E186,0 Z9 11R7g92-FS-I'6 COMPONE-NT LOCATrON *<(TCC No. 03.m7 I

App*ndix A PP 7028 Original Page ,42 of 102 NEC037128

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Appendix A PP 7028 Original Page 43 of 102 NEGO37 129

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nI 34P

VERMONT YANKEE flti SCOPE MANAGEMEfNT REVIEW FORMr Date: k(1hP*" Tracking Number:

(Assigned by Work Scope Control Coordinator)

Work Order NRmbe:f DOOXt - -

o r4-ence oeo -0 e- e_.

CR, TA C Initiator:-flrý nzýApoe

\ vN..*,*..:Depft. Mgr.

Location of Work to be Performed: UýAXJ-.*. Z..4.

"DELETiN ADDITION CHANGE Deacription

$ustifivation for Request s* "-OA-----..

Review Process Additional Cost:

Duxation and gcheduling hmpact:c" Assigned Dept./Man-Itours to Complete: ....

Source of Manpower/Other Scope Impacted:

Dose, Chemistry, Safety Implication:

Engineering Impact - Man-Hours/Engineering Dept.

Optional Ways to Address:

Approval Process Y__teasrovide a brief bistiflcahfon Sc~ope Review Commiuee Recomninendatioix/Planniing ,Priority:_4 PA7()O-' >A Thiority "C" WO Responsiblv Dept Approval Tantu Mapaertos~_____

PltOperationsager, ........

___"_____ (.v.isapprove Date:.-______

EMPAC Change Made for ent e & Priority_..

8CC Date Log Updated:

VYPPF 7102.01 PP 7102 Rev. 2 Page I of I NEG037136.

(

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

References:

Work Order 04-004983-000, FAC Inspections Work Order 04-004983-010, Surface Preparation on SSH piping TM 04-031 Work Order 04-004884-006 ER-05-0190 CR-VTY-04-2985 CA3 Sab~kqround:

CR-VTY-2004-02925 documents a steam/water leak on the turbine steam seal piping, line I SSH-14 to the No.4 packilg. TM 2004-031 installed a temporary [lak 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 determine the extent of condition on the remaining steam seal piping.

Work Scone These inspections require access to the 8SH & SPE piping on elevation 272 of the Turbine Building. The piping is located under the LP turbine appearance lagging deck plates and requires removal of section of the plates to access the piping for surface preparation and inspection, It was intended that these Inspections be performed along with restoration of Temp Mod 2004-031 (W.O.

2004-4884-006).

Discussion Restoration of TM 2004-031 was removed from the outage scope on 10/24/05 due to interference with critical path work planned on the LP turbines. A detailed rationale for delaying restoration of the TM from RF025 was developed by George Benedict on 9198105 and is attached here. The same reasoning and techn[cal basis applies to these inspections, In addition these Jnspections 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 pinhofe type leak vs. a catastrophic failure of the pipe.

NEC037137

A Prepared By G. Benedict

~l~ft~tgY Dre:9/28105 Replacement of N4 Steam Supply Piping Work Order 04-4884-06 TM 2004-031 ER 05-0190 The steam seal supply line to TB-I-IA, N4 packing developed a leak froni 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 most appropriate long term repair would be to install a pre-fabricated clamping devicec.The clamp was fabricated as recommended and successfully installed per the above referenced Temporary Modification (TM 2004-03 1).

WOr -Scop-M' The permanent repair for the N4 steam seal supply line is currently scheduled to be implemented during RFO 25. The pipe clamp and the degraded section of pipe will be removed and new piping will be field fit ad installed. To facilitate thi.4 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 reqiuired to remove/install piping and deck plates.

During RFO 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 dismantled to facilitate the installation of the new 8h stage diaphragms and to perform the required ten year inspection. The location of the degraded steam seal line is directly between both LP turbines and implementing the LP inspection in conjunction with the steam seal line repair will create personnel safety hazards, potential equipment damage, and logistical

• complicationS.

NEC037138

Prepared By; G, Benjedict

- .\. . -.. Date. 9/29105

--- E tutgy The following represents the specific issues that will be present during the impermentation of the N4 steam seal line replacement and the L? turbine inspection:

Personnel Safely:

> Fall and drop hazards will be created by both work crews in proximity to bolh work areas. 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 personnel are required to communicate changes to safety hazards these types of cbanges will be extremely difficult to manage due to the pace of the LP turbine inspection activity.

> The crew working on the steam seal piping will coatinually be interrupted due to overhead hazards from materials being removed and retumrned to the LP turbine centertline. Once again due to the pace of the LP turbine inspection and the fact that the steam seal piping replacement crow will be in and out of the work area which is not visible from the turbine floor only facreases the potential to inadvertently transfer a load over the piping replacement crew.

Equipment Safety and Quality:

> The removal and installation of the steam sea lpiping 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 sumrps, exposed shaft journals, and bearing babbitt surfaces increases the risk for accidental damage.

Schedule and Logistics

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

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

a'*"

• Prep Da Benedict

... Enterm.am 9/2.8/05 will create a delay in the transfer of tooling and materials betweeni LP "A" and

> Asbestos concern: There is a potential that the steam seal line being repaired contains asbestos insulation. Any asbestos insulation issues could shutdown-work on the turbine deck-SMaintenance resources: iMaintenance crews assi'gned to the steam seal line repair have 7 shifts available to perform this repair- If there arc any delays in performing 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 (o the refuel floor.

'ream Inc. was contacted todetermine the feasibility of operating the unit for an additional cycle with the Team olamp in place, The response from Team Inc. was very favorable with regard to operating an additional cycle with the clamp in place. According to Jim Savoy (Team Inc.

District Manager) many corrmiercial industrial facilities that have utilized clamps similar to the one installe d on the N4 steam seal supply line have operated for extended periods much greater than the requested 18 months.

The steam seal supply is approximately 2 - 5 lbs. of pressure with a maximum temperature of 255 degrees F. This is considered very low in comparison to many of the applications that Team Inc. has installed similar long term clamps on. If the clamp is left installed for an additional operating cycle there is a risk that the clamp will leak once the plant is placed back on-lihe.

Although considered a low probability, the risk is due to the thermal cycling of dissimilar.

materials that are utilized in the clamping and sealing process. If a leak were to occur Team Inc.

would re-inject the clamp with sealant which has been successfully performed at other locations.

Q Ns NEC037140

VERMONT YANKEE ,

SCOPE MANAGEMENT REVIEW FORM Date~ /14 03c Tracking Number:

(Assigned by Work Scope Control Coordinator),

Work Order Number: t1/2 Reference Document M 200* -63 1

(.R, MM, TM, 0028, etc.)

Initiator: e/<

e Approved By:.

DepL- Mgr.

Location of Work to be Performed" t*,fl _

ADDITION I]DELETION CHANGE C Description Adb4ed>A*42VOr4 lt'A-A"O tAlacc6"1 e Justification for Request

.tnheA pt* 4 ht.,c _ . _* - e?-"* e ..

Review Procers Additional Cost: -------- I' Dtiatioo and Scheduling Impact:

Assigned Dept./Man-Hours to Complete:"

Source of Manpower/Other Scope Impacted:

Dose, Chemistry, Safety Implication: =

Engineering Impaci - Man-Hourr.igiEngmecring Dept-Optional Ways to Addresms Approval Process Please provide a brief jt~iflation Scope Review Committee Recommendalion/Planning Priority:

Priority "C" WO asib Dept Approval PlAntoMana Disapprove Dame:--

HMPAC C kg~Mor Event CO4&y3 !Xity___.

xCC Date Log Updated:

Copies, to Work Control, Outage Scheduling. .  ; _;

VYPPF 71.tOl" P2 7102 Rev. 1 Page 1 of 1 LPIC 915 NEC037141

RFO-25 Piping FAC Inspections Outage Scope Challenge Meeting 5/4/05 Shod or cryptic summary of what the proeect involves and why we need to complete the pect in RFO 25 (ega. regufatory reauirement. risk to generation, oroaram requirement, appropriate management of the asset.)

In response to USNRC Generic letter 89-08, inspections of piping components susceptible to damage from FRow Accelerated Corrosion (FAG) are performed each refueling outage.

The planning, inspection, and eypluation 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-315.

D.,escription of the scope of the groiect, what it encompasse%-options that have been considered (identify minimal requiredvs.. discretionary - could be deferred age scope that interface~swith or can be included in this project; Impacts on others.

The scope of the inspections for each refueling outage is based on previous inspection results, predictive modeling, industrý and plant operating experience, postulated power uprate effects, and engineering judgment. The scope for the Fall 2005 RFO is defined in Design Engineering-MIS Memo VYM 2004/007, Revision 1. The 2005 RFO Scope includes:

External Ultrasonic Thickness (UT) Inspection of 37 large bore components at 16 locations.

Includes:.

• 5 components recommended for repeat inspections based on prior UT data

• 2 components for CHECWORKS model calibration

- 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

% 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.

CR0 pumps.

Internal Visual Inspection Of two 36 inch CAR lines to assess changes in flows from HP turbine modifications installed in RFO 24. Internal Visual inspection of the only remaining carbon steel 30 inch diameter line 30"-B.

Pre-outage scope and lono lead time parts/contracts that have been identified.

None Page I of 3 NEC037142

/..

- . " RFO-25 Piping FAC Inspections Outage Scope Challenge Meeting 5/4105 Initiatives, creative, opportunities, unique problems associated with the proect.

None The inspection process used is the industry standard. Removal of insulation and surface preparation are required for the UT equipment. Remote methods which do not require insulation removal are still in the development stage, and do not currently have the accuracy required to trend low wear rates (EPRI CHUG). Phosphbr 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 - MIS has minimized the number of Inspections performed each RFO.

VY has traditionally trended well below industry average number of components inspected each RFO. This is primarily due the original design of the plant and replacements with Chrome-Moly piping- Recent trends in numbers of components inspected at other plants show reduced numbers of inspections based on piping replacements.

Ide ntiy additional organizational support required, and specificially, management support 3cssa.v Inspections will be performed by the ISI personnel. Scheduling and staffing will be coordinated with other ISI activities. lnspections 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-O05 Primary DE-M/S interface is the ISI Level Ill andlor 11 Program Engineer for coordination in review and approval of inspection data. Interface with craft & other plant groups is normally through established links in the IS! program. Unusual .situations which require additional support will be raised to management level as required.

Two DE-MIS engineers (J.ritzpatrick & T.O'Connor) currently trained in evaluation

.procedures arid 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 !13coordinator (Dave King), Any problems that arise that can not be handled at the engineer level, will be elevated per outage management guidelines (30 minute rule, etc.).

Page 2 of 3 NE(C037143

./

RFO-25 Piping FAC Inspections Outage Scope Challenge Meeting 5/4/05 Identify anypreparation issues necessary to meet upcoming outag e milestones.

& Coordination with L.P Turbine work for inspection of SSH components (physical space) 6 Coordination with LIP Turbine/Condenser work for ventilation path (opening) for the 30" S Cross Around Line and for a window to perform inspections (noise issue).

6 ER for Design Engineering - Fluid Systems to develop a (paper) Design Change to K 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.

Identif if all necessary outage and pre-0loage WO's for the proiecVp'ncram scopeare -generated.

Work Orders to for support activities and inspections (04-4983-000 series) / 3/44.xW

,.entif it any opportunities to perfonnT an part of this scope could be completed pre-outage?

The only components which are not high temperature and are in an accessible location during plant operation are 4 sections of small bore piping downstream of restriction orifices at the CRD pumps. These may be inspected during operation. _However, this is a high noise area.

Page 3 of 3 NEG037144

Engineering Standard Review & Approval Form Engineering Standard Change Classlticatio, Engineering Standard Titl... Doc. No, Rev No. TCN No.

Flow Accelerated Corrosion Component Scanning and ENN-EP-S-005 j 0 1 NA Grkidin 9 Standard Functional Discipline T Engineering Standard Owner . ngi.neering Standard Preparer

[Egineering Programs Jeffery Goldstein fan MewI

[eiIei IANO IriUngElReviews I E-H F CNndS 3 R13GGSI0[

aS WF;3 I 0 I I' I Ei I JAF I in I PNFPS I n 1 VY I 0 1 wPo I [E I apptable ER.

I An ER?Numner SCross DISCIlplne Is rra Reviews tor Dsi ufor en*

,Siyn (Canf *t Crtent Reviews.i , Reviewer Name / Signature Date Jp NIA eneerin Standard Champion Scott D.Goodwin...,>-'

Editotlal Change / TON Approval Name: Sionature: Date.,

l ~ ~Commen*Sets o Comments made Below Iii. N. Comoet ttce TCH Ohange Selow TCN Chanige Attached TCN Effective/Expiration Date ...

Thtis standard replaces VY specific 'Component Gridding Guidelines" previously contained in Appendix A of VY NDE Sprocedure NE'605$. NE-8053 has bedn superseded by ENN-NDE-9.05 All VY comments were resolved during development olthiis standard.

'S NEC037145

.7 ,RUý

.2>

ENTERGY ENN ENGINEERENG STANDARD ENN-EP-S-005 Rev, 0 Effective Date: JAFIWPO - 911/04 PH - 6`1105 IPEC-10/I04 FloW Agcelerated Corro__sion Component Spannnq and Gdd inn Standard 7-Applicable Site(s)t IP1 E l IP2 IP3[2 JAF 0 PNPS y WE]

Safety Related:, Yes

__ No Prepared by:'

Print Nametgnature/ ate Approved by: TeN Date:

Engineering G(fie Own4&r NEC037146

Engineering Standard Review & Approval Form Eng9neelng9 Stndard Change classification New Revised 5 Cacel Can l Editoral 'E Temporary-En inesripA StandardTitle T'c*c-. NO. Rev No. I TON No.

Pip WilSruturl hinig vauaton_,ENN-q-S.-OOfS 0 r unct-tonal Disciglir Eg"ern Ower*..

W"r~t engineerl fg '3iandard PtereLer i e rn l da d P e a r ro S~tandaird Ow eEn 9trISlEngineering te Conducting Review Review Type Yes No- Reviewer Na a/Si ure Diae Technical Review 0 0 (See Note below for Design Change Standards) - J ames Q Fitatdok Independent Design Veitficatlon (See Note below for Design Change Standards) J ames Q.,Fitzpatrok, 10CFRSO9bProoeas Appricabhiity Review I V (attach screening and evaluation donzmnents) 05James G. Fitzpatrck jL§etNote below lor oJnCag Sadas __

Note: Revteows for D"sgn Change Stan-dari*s are oc-umrnted wklhia Ihe i e app/lcave ER. R Nuilbe

• An ER Number kvrequ/red for Des/gn} Chance Stanrder o_& ___, ___.

Cross Discipline Reviews Revewe Nam Dalh~taoto (eaietName) -- eve-r-a-?-igat-NWA Site Engineering Standard Champio. I a.

o Goodwin oot Editorial Change ! TCN Approval Name: Signature: ].Date:

Comments Section l ___

Comments Made BeW-!Comments Attached TON Changee Bow, TCN Change Attached l TON Effectivef(x iration Date ComQ ntw ,Chan e:

AIJVY comments resolved during development of thIs standard.

L

)

NEC037147

" Page 1 of 1 Fitzwatridk, Jim I.- !om: Fitzpatrick, Jim

.41nt: Tuesday, September 27, 2005 11:45 AM To: VTYEngineering-Mechanical Structural; VTY-EFINDL

Subject:

PRN: Communication of Approved Engineering Standard FYI This is a new fleet standard for evaluation of thinned wall piping components which will replace ENN-DC-i 33. ENN-DC-133 will be superseded.

VY Department Procedure DP 0072, "Structural Evaluation of Thinned Wall Piping Components will be revised or superseded as required when ENN-DC-315 is adopted.

Use:

Entry Conditions for this Standard wiff be *nENN -DC-315 "Flow Accelerated Corrosion Program" and ENIN-DC- 185 "Through wall leaks in ASME Section Xl Class 3 Moderate Energy Piping Systems". WPO has the responsibility to revise the references to ENN-DC-133 in these procedures.

Qualifications/Traninu.;

At present there is no ENN QUAL CARD for use of this Engineering Standard. Calculations performed using standard are documented per ENN-DC-126..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 ot Changes from ENN-DC-1 33 as applicable to VY:

6 More formalized ties to ENN-DC-315, Wear rate defermination 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) Irom 1.2 to 1.1.

& The methods used to calculate the code required thickness for pr6ssure and moment loads are consistent with DP0072, but presented in a different format.

• No significant changes to application of ASME Code Case N-513 for though wall leaks

• Added attachment for guidance in calculation ofcvomponent wear rates.

• Excel spreadsheet templates are available to facilitate calculations.

TFrom: Ettlinger, Alan Sent: Monday, September'26,.2005 9:33 AN

.To, Casella, Richard; Fitzpatrick, Jirm; Lo, Kai; Pace, Raymond Cc: Unsal, Ahmet /

Subject:

Communication of Approved Engineering Standard In accordance with EN-DO-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-S-008, fevision 0 . Pipe Wall Thinning Structural Evaluation This standard supersedes ENN-DG-133. The standard can be accessed in IDEAS on the Citrix server.

The standard becomes effective, and will be posted on September 28, 2005.

It you have any questions, please give me a call.

10/22/2005 NEC037148

ATTACHMENT C NEC-UW_03 REDACTED EVALUATION OF VERMONT YANKEE NUCLEAR POWER

\ STATION LICENSE EXTENSION: PROPOSED AGING MANAGEMENT PROGRAM FOR FLOW ACCELERATED CORROSION

/

Ulrich Witte Northern Lights Engineering 71 Edgewood Way Westville, CT 06515 April 25, 2008

TABLE OF CONTENTS I. Introduction ........................................................... 1 II. Summary Assessment ................................................... ....... .4 III. Licensing Basis for Management of Flow-Accelerated Corrosion at Vermont Yankee-and Review of the Program Implementation .................................................. 10 A. -The Current Licensing Basis and the Proposed Licensing Basis for the Flow-Accelerated Corrosion Program ...................................................... 10 B. Implementation of the Flow-Accelerated Program in Accordance with the CLB ......................... ................................ 12 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 .......................... 12 D. Current Status of the FAC Program with Respect to the Licensing Basis ......... 13 IV. Time Needed to Benchmark CHECWORKS for Post-EPU Use at VYNPS ............. 21 N

I. Introduction I submit the following comments in support of the New England Coalition, Inc.'s

("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.

TheApplicant has represented that its FAC management program during the period of extended operationwill be the same as its program Under the currentoperating license, and consistent with industry guidance, including EPRI NSAC 202L R.3. The use of the CHECWORKS model is a central element in the Program implementation.

In the Applicant's motion for summary disposition, the Applicant proffered a response that credits the its current program for FAC management at the facility, and simply extends the current program for the renewal period, making the following statement: "furthermore, the FAC program that will be implemented 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 199.0, 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

/ r-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 2

basis of condition reports, the categorization as unsatisfactoryin a Quality Assurance Audit dated November 11, 20041, and noted as "yellow" in a cornerstone roll-up report circa 20062. In addition, the NRC Project Manager made a recent inquiry into indications of an out-of-date program.3 On Monday, April 21, 2008, I spoke by phone with NRC resident inspector Beth Sienel, and she confirmed that, even now, Entergy has not completed verification of the upgrade of the CHECWORKS model to EPU design conditions. This concern regarding deficiencies in implementation of the program brings

(

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.

Exhibit NEC-UW_9, Audit No.: QA-8-2004-VY-i, "Engineering Programs", page 2, NEC038514 2 Exhibit NEC-UW 7, Cornerstone Rollup, Program: Flow Accelerated Corrosion, Quarter: 3 rP, dated 10/03/2006, page NEC03824, Open Action Items, (includes All CR-CAs, ER post action items and LO-CAs, is shown as "yellow", however, 6 LO-CAs are shown as open. By definition, "Red" includes 2 or more CR-CAs and /or E/R post action items (excluding LOs action items) greater than one year.

'Exhibit NEC-UW_14.

2

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 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 4 10CFR Part 50, Appendix B, XVI, "Corrective Action," states: "Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall dssure that the cause of the conditi6n is determined and corrective action taken to preclude repetition., The identification of the significant condition adverse to quality, the cause of the condition, and the corrective action taken shall be documented and reported to appropriate levels of management."

3

for years 5 led the Japanese Mihama Plant FAC pipe rupture in 2004, causing five fatalities. 6 As discussed in detail below, Vermont Yankee missed dozens of points.

Identification of discrepancies and timely corrective action are the cornerstones of a well-managed plant. In my experience assisting problematic plants, change usually begins with a cultural shift toward proactive corrective action and away from a reactive mentality of delaying needed corrective actions to programs such as FAC that result in unresolved deficient conditions and unnecessarily narrowed safety margins for longer periods of time. than are necessary.

A common metric used by the regulator (for example in ROP reviews) and management is the volume of the backlog of open corrective actions and the number of open corrective actions that date further back than one year, two years or even three or more years, to establish the fidelity of the licensee's compliance with the terms of its operating license and associated commitments. The metric is useful in evaluating Flow

• Accelerated Corrosion management at 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.

NEC0737 109 6 The Japan Times, September 28, 2004.

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 were 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 page NEC03119,also footnote Action "Corrective Plan to complete open Cornerstone, developed3 ,10/02/2006, LO-CA tasks Quarter: dated 10/03/2006, (CR-2006-02699)--see 3.

8 Exhibit NEC-UW_20, VY Piping FAC Inspection Program PP 7028- 2007 Refueling Outage, Inspection 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.

I To be an even marginally predictive modeling tool, the CHECWORKS model should havebeen kept current for successive outages, including multiple systems changes (as defined by EPRI guidanceS) that were required to be managed for FAC as far back as 1999. The predictive capability of CHECMWORKS 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 sihs 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 the rationale for selection of grid points relied on (1) length of time since the lapsed

'0Exhibit NEC-UW_22.

"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 showed an trend of increased frequency of reinspection. See NEC037106. Page 4 of 14 provides for negative margin, or no inspections for Feedwater System. Conclusions called for "assessing the need" for inspections in 2007 outage. See page NEC37107. 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 NEC0737108.

6

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 2

was therefore void.'

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 12 Exhibit NEC-UW- 11, Official Transcript of Proceedings ACRST-3397, Advisory Committee on Reactor Safeguards Subcommittee on Plant License Renewal, June 5, 2007, atpage 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

CHECWORKS was not done until 3rd quarter 2006.13 Grid points, scope selection, and small bore piping susceptibility do not appear to have been ranked under NSAC 202L guidance or in an orderly trending of data by CHECWORKS based upon repeated passes with, new grid points and new rankings selected. Data input and passes by CHECWORKS 14 were not accomplished on an outage-by-outage basis.

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 licensedto 120% increase in.

power in one step. Given the uniqueness of the design of VY's power up-rate, CHECWORKS has little industry benchmarking data, and is of marginal use.

The history of the one other up-rated power plant, Clinton Power Station, suggests the possibility of future problems at Vermont Yankee. The NRC inspected Clinton Power Station, including a review of the FAC program, after its up-rate in January 2003 and found the program to comply with its licensing basis, including NSAC 202L and the, use 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-13Exhibit NECUW-10.

14 Exhibit NECUW-20, VY Piping FAC Inspection Program PP 7028- 2007 Refueling outage, Inspection Location Worksheets / Methods and Reasons for Component Selection" at 9, NECO 17896 IS Exhibit 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,ircrease the number of FAC inspections by 50 percent from whatwe 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-ounder a well managed program, without significant changes to the model-such as a power uprate.

8

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 7

EPRI guidance. 1 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 habitability18 . 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 FAG at the plant.

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 16Exhibit NECUW-20, at 7, NECO 17894 "Exhibit NECUW-04; Exhibit NECUW-05.

IS Exhibit NEC-UW_22 U.S. NRC NUREG 0933; Issue 139: thinning of Carbon Steel Piping in LWRs (Rev. 1).

'9 Exhibit NECUW-21, Milwaukee Sentinel, March 9, 1995.

20 Exhibit NECUW-20 at 9, NECO17896 9

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 implementation I reviewed the FAC program in four parts: Part A, examining the current licensing basis; Part B, the implementation of the licensing basis; Part C, the Licensee's own record.

of problems with implementation; Part D, my independent observations based on the record provided to NEC, and the requirements for implementing an effective program under NRC-endorsed guidance, with which the Licensee has stated that it has complied.

A. The current licensing Basis and the proposed licensing basis for the flow accelerated corrosion program:

My review to establish the current licensing basis and the current status of application for license renewal includes the following documents:

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

3. CHECWORKS EPRI procedures provided by the Applicant, including fleet procedure EN-DC-315, PRev. 6, "Flow-Accelerated Corrosion Program" effective December 1, 2006.

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

i. USNR generic letter 89-08, Erosion corrosion -induced pipe wall thinning; ii. Vermont Yankee Letter to USNRC; iii. Vermont Yankee letter to the USNRC, Vermont Yankee Response to NRC Bulletin No. 87-01: Thinning of Pipe Walls in Nuclear Power Plants, dated September 11, 1987; iv. Vermont Yankee letter to the USNRC, Supplement to Vermont Yankee Response to NRC Bulletin No. 81-01: Thinning of Pipe Walls in Nuclear Power Plants, dated December 24, 1987; V. USNRC Generic Letter 90-05, Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2 and 3 Piping, dated June 15, 1990; vi. Vermont Yankee letter to the USNRC, request from code relief for use of ASME Code Case N-597, as analternative 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_0 1, Reevaluate FeedwaterHeater 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:

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.

II

ix. Flow accelerated corrosion in power plants TR- 106611 RI, 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 (LROO1576);

xii. Section 12-2 Wear rate analysis (Excerpt from an EPRI report);

xiii. VYNPS License renewal Project Aging Management Program Evaluation Results. (NEC00113191)

B. Implementation of the Flow Accelerated Program in accordance with the CLB.

I reviewed the following documents to ensure the implementation of the FAC program in accordance with the CLB:

xiv. ENN-DC-315, Rev. 1, "Flow Accelerated Program;"

xv. VY-PP7028, Piping Flow Accelerated Corrosion Inspection Program; xvi. VY -PP7028, FAC Inspection program PP 7028- 2007 Refueling outage; xvii. VY -PP7028, piping inspection program, FAC inspection records for 2005 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 repoits, and one cornerstone report rollup on trending in the FAC Program (2003)-

12

through October, 2006), NRC Inspections, and various revisions to VYLRP subsection's 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 Vermont Yankee Nuclear Power Flow-accelerated corrosion, dated February 28, 2000; xxiii. CR--VTY-2005-02239; xxiv. Cornerstone Rollup update last dated 10/23/2006; xxv. VYNPS License RenewalProject Aging management Program Evaluation Results.23 D. Current status of the FAC Program with respect to the licensing basis.

I

1. The current licensing basis goal is to preclude negative design margin or pipe rupture due to Flow-Ac'celerated 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 td 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 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.

13,

(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 24 OECD Pipe Failure Data Exchange Project (OPDE) database provides that information.

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:

1. Scope

2. Preventative actions

3. Parameters monitored or inspected

4. Detection of aging effects

5. Trending

6. Acceptance criteria

7. Corrective actions

8. Confirmation processes

9. Administrative processes 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. Pages 20 and 30 include a failure rate for BWR plants. The probabilistic risk assessment for BWR plant FAC failures is reported as 10E-5 (higher than reactor accident threshold PRA for Design Basis Accidents).

14

25

10. Operating experience

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

4.

27 The record indicates that the Vermont Yankee Nuclear Power Station ("VYNPS") FAC program only partially implemented its licensing basis requirements to achieve a successful FAC program and that Entergy was aware of the problematic state of the program for many years.28 .

28

5. The self-identified deficiencies in Entergy's current VYNPS FAC Program are identified in multiple documents. Perhaps most significantly, it appears that Entergy was first notified by EPRI as early as 2000 that it had not been fully updating the CHECWORKS model in use at VYNPS with plant inspection data collected or plant modifications performed during previous inspections. 29 Entergy apparently ignored the warning. More troubling is that Entergy continued to be in non-compliance with its

, 5 Exhibit NEC-UW06; 26 Exhibit NEC-UW_1 8 at 20, 30. This Exhibit provides industry-wide data on FAC failures. The high rate of failure in BWR plants underscores the need for precision in implementing an FAC program.

28 Exhibits NEC-UW-05 at NEC017893-912: Exhibit NEC-UW-09 at NEC038422.

29 Exhibit NEC-UW-10.

15

licensing basis through the years 1999-2006. This deficiency was again noted in late 2004 30 under an internal quality assurance audit, and two Condition Reports were written.

6. Relevant data apparently was not entered into the CHECWORKS model until the third quarter of 2006.31 The October 23, 2006 rollup thus confirms that the model was not kept current during a seven-year period and ýuggests 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 30 Exhibit NEC-UW- 11; Exhibit NEC-UW-12.

3' Exhibit NEC-U W-09 at NEC038424 ("CHECWORKS models and wear data analysis updated with all previous inspections in 3 d quarter 2006.").

32 Exhibit NEC-UW 14, Email letter

" Exhibit NEC-UW 17.[Proprietary], Entergy: Letter to NRC re: Extended Power Uprate Response to Request for Additional Information..

16

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 outdated version of the CHECWORKS software. As far back as 2000, EPRI recommended that VYNPS update to the current version of the software, but the recommendation was not implemented until 2006.35 Entergy's failure to 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,"

35 Exhibit NEC-UW-10.

36 Exhibit NEC-UW-05 at NECO 17893.

17

meaning wall thinning beyond acceptable code limits, were also predicted. The hours negative to the next inspection were substantial-predicting potential code violation or failure could have occurred 3000+ hours previously to October 23, 2006. Itis surprising that the Licensee apparently did not write condition reports for this condition. I do not believe that NEC received any notice of Condition Reports relevant to this significant indication by CHECWORKS predicting substantial wall thinning beyond code limits to occur with /negative margin of this magnitude.. This issue is particularly troubling given that the equipment failure event is unpredictable, and catastrophic when wall thinning is beyond acceptable limits. Despite CHECWORKS' prediction of wall thinning, the plant continued to operate. I have not seen any inspection or audit discussion of this situation.

It does, however, appear on the RFO 24 Inspection Plan, 37 oddly with the same number of hours of negative time to Tmin, even with the plan including w~ar data observed of 30%

38 increase at Quad Cities and Dresden after the up-rate.

10. The VYNPS FAC program was deemed unsatisfactory under quality assurance review dated November 22, 2004, and two condition reports were written.39 iOn page 5, the report notes the need for program management to ensure "update of susceptible piping 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 '

37 Exhibit NEC-JH 43 at 5.

" Id. at 41.

39 Exhibit NEC-UW-I I at NEC038514.

40 Exhibit NEC-UW-I 1 at 5.

4' Exhibit NEC-UW- I.

18

11. The 2006 cornerstone report shows a number of indicators as yellow, with lists of open CR corrective actions, and a new CR written in August 30, 2006.42 The report lists 43 six corrective actions and four CRs that were written as early as 2003 that remain open.

These include references to a rnumber 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."" 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 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 42 Exhibit NEC-UW-09 at NEC038419, NEC038422.

4' Exhibit NEC-UW-09 at NEC038424.

4' Exhibit NEC-UW- 13 at 1.

19

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 plant modifications and inspection results as not updated since May 15, 2000.46

15. Ranking of small-bore piping was not done. With no ranking, the basis for selection of high susceptibility points for small-bore piping is not evident.4 7 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 d quarter 2006.49 4

17. Entergy appa ntly reduced the n mber of FAC ýinection data points bet een the 2005 refueling tage and the 2006 fueling outage, violation of its cor itment to increase 137 large-borespection data point inispection oints.2y The 50%. The 200 refueling outage ins ction calledfor/

2006 fueling 5 outage inspe ion, presented to the ACRS on June 5, 20 Z,covered only 6'ypo'mts.5°

18. The 2006 refueling outage FAC inspection scope, planning, documentation, and procedural analysis all appear to have been performed under a superseded program document. ENN-DC-315 Rev. 1 was effective March 15, 2006, superseding the PP7028 4- Exhibit NEC-JH_44 at 17.

46 Id. at 18.

47 Id.

48 Id. at 27.

49 Exhibit NEC-UW-09.

'oExhibit NEC-UW- 14.

20

0 Piping FAC Inspection Program.51 Yet VY inspection plan for FAC Program PP7028 was approved on May t1, 2006, almost two months after the PP7028 program document was superseded. 52 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.5 3 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 invalid. NSAC 202L calls for the baseline for the configuration change to be treated the same as new design. 54 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.

19. No indication is provided that plant isometrics were updated as required as of 10/22/04.5 IV. Time needed to benchmark CHECWORKS for Post-EPU use at VYNPS I agree with the testimony of Dr. Joram Hopenfeld that CHECWORKS is an empirical model that must be updated with plant-specific data. NUREG 1801 does not specify the number of years' data necessary to benchmark CHECWORKS, but does s' Exhibit NEC-UW- 15 (ENN-DC-315); Exhibit NEC-UW_20(PP7028).

52 Exhibit NEC-UW-05 at NECO17888.

s3 Exhibit NEC-U W-06 § XI.M 17.

s4 Exhibit NEC-UW-06.

" Exhibit NEC-JH_44 at 19.

21

advise that a baseline must be established as noted above.

This requirement is reasonable given that each plant has unique characteristics and operating history. Separate industry guidance supports five to ten years of data trending.5 7 Trending to the high end of the range is appropriate where variables affecting wear rate, such as -flow'velocity, have significantly changed, as at VYNPS following the 120% power up-rate.

Given the deficiencies in the current VYNPS FAC program discussed in this statement, trending under the program is of marginal value. In addition, substantial "Cnegative 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).

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 m/any 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 5 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.").

22

increased operating power by more than 15%.58 Of this group, at least three - Clinton, Dresden, and Quad Cities - appear to have FAC-related issues.5 9 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 hadpassed since EPU design was completed, licensed, and implemented. The apparent failure to update the program underscores the lack of benchmnarking 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 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.

5 Exhibit NEC-UW 18, Union of Concerned Scientists, "Power Uprate History," July 12, 2007.

59 Exhibit NEC-UW-05..

23

(

It is also my opinion that benchmarking can only be accomplished after the current program deficiencies are corrected and a proper baseline is established.

24

ATTACHMENT B NEC-UW_01 UNITED STATES OF, AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:

Alex S. Karlin, Chairman Dr. Richard E. Wardwell Dr. William H. Reed Inthe Matter of Docket No. 50-271-LR ENTERGY NUCLEAR VERMONT YANKEE, LLC, and ASLBP No. 06-849-03-LR ENTERGY NUCLEAR OPERATIONS, INC.

(Vermont Yankee Nuclear Power Station)

PRE-FILED DIRECT TESTIMONY OF ULRICH WITTE REGARDING NEC CONTENTION 4 Qi. Please state your name and address.

Al. My name is Ulrich Witte. I reside on 71 Edgewood Way, Westville, Connecticut, 06515.

Q2. What is your educational and professional background?

A2. I obtained a BA in. physics from the University of California, Berkeley in 1983. 1 have over twenty-six years of professional experience in engineering, licensing, and regulatory compliance of commercial nuclear facilities. I have considerable experience and expertise in the areas of configuration management, engineering design change controls, and licensing basis reconstitution. I have authored or contributed to two EPRI documents in the areas of finite element analysis, and engineering design control optimization programs. I have chaired the development of industry guidelines endorsed by the American National Standards Institute regarding configuration management programs for domestic nuclear power plants. My 26 years

of experience has generally focused on assisting nuclear plant owners in reestablishing fidelity of the licensing and design bases with the current plant design configuration, and with actual plant operations. In short, my expertise is in assisting problematic plants where the regulator found reason to require the owner to reestablish competence in-safely operating the facility in accordance with regulatory requirements. My experience is further detailed on my curriculum vitae filed with this testimony as Exhibit

/1 NEC-UW 02.

Q3. What is your understanding on NEC Contention 4 in this proceeding?

A3. NEC Contention 4 asserts that Entergy's plan for managing flow-accelerated corrosion (FAC) in plant piping fails to meet the requirements of 10 C.F.R. § 54.21 (a)(3),

i.e., "fails to demonstrate that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operations."

Q4. Did you prepare a report regarding this contention?

A4. Yes I did. My report is filed with this testimony as Exhibit NEC-UW_03. This testimony and my report provide, to the best of my knowledge, true and accurate statements of the facts and my conclusions regarding the issues relevant to NEC's Contention 4.

Q5. What materials did~you review in support of your report and testimony?

A5. I reviewed the implemented FAC program and FAC inspection program, other inspection programs that Entergy has in place, and records and histories of these inspections. I also reviewed industry-wide standards for FAC programs, NRC data, information and reports, the CHECWORKS program and Entergy's commitments to 2

upgrade the CHECWORKS model to EPU design conditions, inspection reports, EPU parameters, Plant Quality Assurance audits, Condition Reports, Corrective Actions, NRC regulations, EPRI review of the VY plant, Cornerstone Rollup, examples from other plants, and Entergy's application and the record (including reports, proposed programs, and testimony to the NRC Advisory Committee on Reactor Safeguards Subcommittee on Plant License Renewal) provided by Entergy or others in support of its application, including pipe wall thinning structural evaluation.

Further materials that I reviewed are specified in my attached report.

These are materials that are regularly used by experts in my field to assess aging management programs and flow-accelerated corrosion. I applied these materials in a standard manner that is routine with experts in this field.

Q6. Were these materials sufficient to allow you to form opinions and draw conclusions using your expertise?

A6. Yes, I had sufficient information to formulate the assessment stated in my report and maintain standards that.are widely accepted by experts in this field. The Applicant did not,

/however, produce complete information to NEC regarding its methodology. My report notes where the Applicant's materials fail to provide sufficient information. As I have explained in my report, the information the Applicant produced is insufficient' to validate its aging management J

programn Q7. Please summarize your conclusions.

A7. In summary, I reached two conclusions:

3

First, the data collected under the current VYNPS FAC program during the post-EPU refueling outages scheduled prior to the expiration of the current VYNPS license is insufficient to benchmark CHECWORKS to VYNPS's post-EPU conditions. The Applicant states without ambiguity that the present program is sufficient not just for current operations and maintenance of the plant, but for the license renewal period as well. The record of a historical regulatory compliant program indicates otherwise.

.J Second, the current VYNPS'FAC program does not appropriately implement industry guidance, and does constitute an adequate aging management plan with respect to FAC.

More specifically, my conclusions are:

0 Contrary to EPRI recommendations, from 1999-2006, Entergy apparently failed to update the CHECWORKS model in use at VYNPS with plant inspection data or information concerning plant modifications. This lengthy lapse may have significantly weakened the trending and predictive capability of the software, both during the lapse period and presently.

The update to incorporate EPU design data appears to still be in progress as of February 2008.

W Contrary to EPRI recommendations, the VYNPS FAC program apparently used an outdated version of the CHECWORKS software during the years 2000-2006.

m In 2005, the CHECWORKS model predicted wall thinning close to or exceeding acceptable code.limits at several locations, but Entergy apparently produced no Condition Reports addressing these imminent potential pipe ruptures, or at least has not produced such reports to NEC in this proceeding.

4

0 Numerous internal Entergy reports label the VYNPS FAC program unsatisfactory. The program was deemed unsatisfactory in the 2004, and the 2006 cornerstone report expressed concern about the program and specifically the continued slow progress in updating the CHECWORKS model.

0 An FAC-related pipe rupture appears to have occurred during the third quarter of 2006.

'M The 2006 refueling outage FAC inspection scope, planning, documentation and procedural analysis all appear to have been performed under a superseded program document, potentially invalidating the pre-EPU baseline for use of CHECWORKS.

Entergy pparently reduce he number of C inspection ta points by fi perce t (50%) betw en the 2005 refue g outage and e 2006 refueli outage, in vio tion of its ommitment increase inspect n data points b fifty percent (5%).

Further detail and supporting information is in my attached report.

I declare pursuant to 28 U.S.C. § 1746 under penalty of perjury that the foregoing is true and correct.

Executed on April -, 2008 Ulrich Witte 5

I declare under penalty of perjury that the foregoing is true and correct.

Ulrich Witte At _____________, Connecticut, this 2f--t day of April, 2008 personally appeared Ulrich Witte, and having subscribed his name acknowledges his signature to be his free act and deed.

fore me: ýb_ a o V S--

Notary Public My Commission Expires &- Z I- (

ATTACHMENT D

• J UNITED STATES.

NUCLEAR REGULATORY COMMISSION In the Matter of )

)

ENTERGY NUCLEAR VERMONT YANKEE, LLC ) Docket No. 50-271-LR and ENTERGY NUCLEAR OPERATIONS, INC. ) ASLB No. 06-849-03-LR Vermont Yankee Nuclear Power Station )

PRE-FILED REBUTTAL TESTIMONY OF ULRICH WITTE REGARDING NEW ENGLAND COALITION, INC.'S CONTENTIONS 2A, 2B AND 4 Q1. Please state your name.

Al. My name is Ulrich Witte.

Q2. Have you previously provided testimony in this proceeding?

/

A2. Yes. I provided direct testimony in support of New England Coalition, Inc.'s (NEC) Initial Statement of Position, filed April 28, 2008.

Q3. Have you reviewed the initial statements of position, direct testimony and exhibits concerning NEC's Contentions 2A and 2B filed by Entergy and the NRC Staff?

A3. Yes. I have reviewed Entergy's Initial Statement of Position on New England.

Coalition Contentions (May 13, 2008), and the Joint Declaration of James C. Fitzpatrick and Gary L. Stevens on NEC Contention 2A/2B - Environmentally-Assisted Fatigue (May 12, 2008) and exhibits thereto. I have also reviewed the NRC Staff Initial Statement of Position on NEC Contentions 2A, 2B, 3, and 4, the Affidavit of John R. Fair 1

Concerning NEC -Contentions 2A & 2B (Metal Fatigue) (May 13, 2008) and exhibits thereto, the Affidavit of Kenneth Chang Concerning NEC Contentions 2A & 2B (Metal Fatigue) (May 12, 2008) and exhibits thereto, and the revised Affidavit of Dr. Chang provided on May 22, 2008.

( .

I. NEC's Contentions 2A and 2B - Environmental Assisted Metal Fatigue Analysis

_Q4. Please describe your qualifications to provide testimony concerning NEC's Contentions 2A and 2B.

A4. I have extensive experience in original stress analysis in qualifying Class 1 and Class 2 pipe and components, and applicable ASME codes as well as ANSI B3 1.1 codes, in particular in the design, analysis, construction, and qualification of Class I and 2 systems within the domestic nuclear industry. This experience includes, for example, original stress analysis for McGuire, Catawba, and V.C. Summers Power Plants. In addition, I have performed non-linear finite' element analysis for a number of components and I am familiar with Swanson's computer algorithms such'as ANSYS., RELAP, and other commercial analytical computer programs. Under contract to EPRI, I conducted detailed 'correlation studies of non-linear finite element analysis code predictions against actual in situ testing of piping and components at the Indian Point 1 Nuclear facility after the plant was closed. The results are published in EPRI Report Number 8480, - Seismic Piping Test and Analysis, 1980.

QS. Do you agree that Entergy's "confirmatory" CUFCn analysis of the feedwater nozzle fully incorporates thermal fatigue history for the feedwater nozzles?

2

A5. No. The NRC questioned the Applicant's "simplified analysis" with respect to the Feedwater nozzle as part of Request for Additional Information (RAI) dated October 9, 2007, during NRC LR Audit. The Staff was unsatisfied with the responses by Entergy,

/

dated October 19, 2007 and November 14, 2007. During a meeting with Staff on January 8, 2008, the Applicant committed to performing refined analysis on the Feedwater nozzle including the use of actual operational thermal fatigue histories, as opposed to derived histories from the GE Specification. Incorporation of operational histories of the Feedwater nozzle was made a formal commitment in BVY 08-008, dated February 5, 2008.

An operational event that results in an unanalyzed thermal transient to the reactor vessel is relevant and cannot simply be set aside as licensees did for some period of time.

The event at Vermont Yankee (VY) was no exception. The causal relationship between the event as found in historical records and the consequences in terms of thermal shock is key. During the early years of plant start-up and operation there where many unplanned forced shutdowns. I found 42 for VY; Not exactly a silky smooth running reactor. Three were downright dangerous.

GE and the Licensee did not fully predict all of the events in their shutdown estimates. Hence, those that were outliers needed detailed analysis. During the mid-1980s and into the 1990s this fact came to light starting with NUREG 0599 and others.

I -

Operational events led to the need for careful and refined transient analysis. The simplified method was shown to be overly dependent on skillful and experienced engineering. New methods removed the uncertainties and doubts of accuracy in CUF and 3

CUFen. Not just cycle counting but examination of derivative temperature changes forced on the reactor vessel, the associated safe end; and on, of course, the feedwater nozzle as well. I know, because I was required immediately to notify the Technical Support Center (the ,emergency response area assembling management to provide technical support) for just such an event occurred on December 26'h, 1986, at 6am, which brought down another plant for many months, placing the plant under its emergency plan. There was a concern that the plant would never operate again.

Based upon my examination of Vermont Yankee's historical records and my own experience of the challenge of maintaining nuclear plant operational history beginning with plant start-up, it appears to me that major thermal transients have likely not been incorporated into the operational history, as referenced in the SER. This deficiency is particularly significant where the reactor vessel has experienced an unplanned and unanalyzed transient that was outside the engineered design basis. Occurrence of these events throughout the industry was not as uncommon as one might presume.

Assessment of transient impact to specific component life is reluired following such an event to reestablish fidelity with the plant's design basis and is. accompanied by additional fatigue analysis. The outcome of the engineering analysis holds one of three possibilities: (1) severe damage has occurred to the nozzle or vessel (less likely), (2) no additional fatigue usage outside the GE Specifications has occurred (also not likely), or (3) some additional usage outside the GE Specifications has occurred and therefore the component life is shortened (likely). Assessment and incorporation of the assessment of these impacts into plant operating records is essential to providing a basis for effective aging management programs.

4

An example of an historical Vermont Yankee event with the pbtential.to impact the useful life of a number of systems, structures, and components occurred on December 1, 1972. Ondthat date, the reactor automatically scrammed when an internal fault on a startup transformer resulted in a loss of offsite power. The emergency diesel generators automatically started and connected to their electrical buses. The high pressure coolant injection (HPCI) system got an automatic start signal on high drywell pressure, but failed to start. The operators manually started HPCI. Three relief valves opened when reactor pressure increased to 1,130 pounds per square inch gauge. A fourth relief valve should have opened, but failed to do so. One of the three relief valves that opened chattered on its seat about 100 psig below its set point. The transient was significant as reflected by the fact that odds of a core melt from this single event were 1.4E-3. See, Exhibit UW-24.

More significant to the issue of fully recovering the record of all transients and accurately incorporating them in assessing remaining fatigue life is the assessment of wear, damage,.

and stress on each relevant component during each significant transient event.

There are other examples of transients that appear to have not been incorporated as 6

input in the refined fatigue, analysis. During the period from 1973 through 1977, Vermont Yankee experienced 42 -unplanned forced shutdowns. This is a significant number, and expended much of the fatigue life of the reactor vessel and feedwater nozzle. See Exhibit UW-25.

Of these 42 forced shutdowns, in 1976 Vermont Yankee experienced 10 unplanned reactor scrams. Exhibit UW-24. One of these, on July 6, 1976, occurred during surveillance testing when the air operator plunger on a relief valve did not move when air was applied. Two of the other three relief valves failed. The failures were traced to air 5

operator diaphragms damaged during excessive heating. The damage was attributed to improper insulation in the proximity of the diaphragms and an extended operating cycle.

Core melt frequency for this event was an astoundingly high number 6.25 E-2. Exhibit UW-24. Again, the event stressed a number of systems and impacted the fatigue life of numerous components.

I made a comparison of the Engineering Design Input document, EN-DC- 141, Rev. 3 provided to NEC by Entergy, to available records contained in the following documents and as compared to the responses provided to Dr. Chang's questions contained in Exhibit UW-26, "NRC Audit 10/09/07, with responses provided 10/18/07."

It appears that, in Entergy's calculation of 60-year CUFs in its CUFen reanalyses, operational histories were not properly or accurately compiled and that instead of documented transients, estimated thermal transient histories were used to predict the 2

number of Reactor Thermal Cycles for 60 years. Purported added conservatisms remain unqualified and unjustified. The estimates of thermal transients are provided on , Page 1 of 6, EN-DC-141, Rev. 3. See Exhibit UW-27 "Design Input Record, Environmental Fatigue Analysis for Vermont Yankee Nuclear Power Station."

Q6. Why is this of concern in assessing the validity of Entergy's CUFen reanalysis?

A6. Refined fatigue analysis fidelity largely turns on correct design inputs. The simplified Green's. Function method challenged by Staff on January 8, 2008 and in other records, was essentially about uncertainty in assumptions and estimates. My observation is that this particular design input is an

/

ungrounded estimate, an assumption, and not an actual historical number; any conclusion stemming from it, therefore, cannot be relied on without corroboration. Clearly, to proceed with estimates based on a flawed record of all 6

transient events is not appropriate. The rationale provided for not using actual transient operational cycles as found in Exhibit UW-26 at sequential page no. 8 (Bates number NEC069994), is not valid in the event of a thermal transient event that was outside the original design basis. Entergy, has not shown that those events were incorporated.

Second, the estimated transient history - assumption - may or may not be conservative. As noted above, the plant experienced certain transients during its operational life from initial plant start up and testing, commercial operation, then uprate to 120% power beginning in 2004. Actual excursions, in particular those that appear to be outside the GE design specifications, should have been accounted for in the refined analysis. From the analysis provided, at least in the first example, they were not.

Third, considering Extended Power Uprate contributing factors such as increased flow, component modification, increased vibration, and increased core heat and neutron flux, the transients experienced by the plant beginning with power escalation to 120%

should be given more weight in forecasting thermal transient cycles. There is no credible basis provided in the Applicant's analysis that justifies thermal cycle projections. to 60 years.

In summary, by using estimated histories as opposed to actual history, specific, transients that shorten the component fatigue life appear not to be acknowledged or included in the Applicants fatigue analysis, making the results including CUFen, unsubstantiated.

II. NEC's Contention 4: Flow Accelerated Corrosion Plan 7

/ý

Q7. Have you reviewed the initial statements of position, direct testimony and exhibits concerning NEC's Contention 4 filed by Entergy and the NRC Staff?.

'A7. Yes. I have reviewed Entergy's Initial Statement of Position on New: England Coalition Contentions (May 13, 2008), and the Joint Declaration of James C. Fitzpatrick and Dr. Jeffrey Horowitz on NEC Contention 4 - Flow Accelerated Corrosion (May 12, 2008) and exhibits thereto. I have also reviewed the NRC Staff Initial Statement of Position on NEC Contentions 4, and the Affidavit of Kaihwa R. Hsu and Jonathan G.

Rowley Concerning NEC Contention 4 (Flow-Accelerated Corrosion) (May 13, 2008),

and exhibits thereto.

Q8. Entergy contends that you have no experience or: expertise relevant to the testimony you have provided concerning NEC's Contention 4. How do you respond?

A8. I have extensive experience in development of engineering programs including controls for design change processes, configuration management programs and' comprehensive initiatives in affecting operating nuclear power stations. These processes typically involve complex multifunction and multi-organization challenges. These programs are often mandated under federal regulations, or committed programs for a licensee to re-establish fidelity with its current design basis and license conditions. I have substantial experience in, for example, implementation and validation of NUREG 0737, "Clarification of TMI Action Plan Requirements," and was a principal manager in the successful restoration of Indian Point 3 from the NRC's Watch list, as well as Millstone

,Units 2 and 3. For the Tennessee Valley Authority, specifically the completion of the Watts Bar Nuclear Plant, I developed a program entitled "Program to Assure Completion and Quality." For Georgia Power's Plant Hatch, I developed and implemented a 8

Configuration Management Program, led in-house Safety System Functional Inspections, and an Electrical Distribution Function Inspection so as to prevent Plant Hatch from going on the NRC's watch list. For Northeast Utilities, I developed a multiple department and multi-function program to reestablish the fidelity of the design basis and licensing basis, including identifying, dispositioning and either eliminating or implementing over 30,000 regulatory commitments. My leadership in establishing and implementing these programs

- successful initiatives - was well-received by the Licensee and well-received by the regulator. By, their transparency to the community, they were generally accepted as improvements by the Licensee in protecting the health and safety of the public and minimizing risk to public assets.

• As a seasoned engineer, manager, and problem solver, my expertise and track record demonstrate successfully implemented solutions to complex organizational, technical, or regulatory challenges in nuclear plant operations.

Applying my expertise in Engineering Design Control Programs, I note that Entergy's proposed Flow Accelerated Corrosion management program is based On use of a predictive modeling tool derived from an empiricallybased program with heavy reliance on engineering judgment, coupled with experience, oversight, and effective monitoring of FAC-related wear to certain vulnerable plant systems. My expertise in program management focuses on correct and effective implementation of the program and finding a record that is auditable, defendable against program requirements and transparent. To quote the NRC Staff's position regarding flow accelerated corrosion, "Corrosion is not an exact science. Due to epistemic and aleatory uncertainty, absolute, wear rates cannot be determined...." NRC Staff Initial Statement of Position at 20. Thus the burden in 9

constructing and maintaining an effective FAC program must emphasize reliance on engineering judgment, coupled with experience, oversight, and effectiye monitoring of FAC-related wear.

While I do not purport to be intimately familiar with the empirically based CHECWORKS algorithm, I can attestto sufficient expertise in evaluating the fidelity of a comprehensive FAC program. I believe that the parties and witnesses are not in dispute that an effective flow accelerated program is highly, dependent on sound engineering judgment and precise implementation, including the program goal of effective management of the predictive results, so as to preclude wall thinning beyond acceptance criteria during the license renewal period.

A. Summary Rebuttal Q9. Do you believe that Entergy's Flow Accelerated Corrosion Management Program as implemented to date will be adequate for purposes of aging management during the period of extended operation, as Entergy and the NRC Staff assert in their initial statements of position and direct testimony?

A9. No.' Entergy asserts on page 34, 35, and 37 of their Intial Statement of Position to New England Coalition Contentions, that their intention to credit the existing program as demonstrated to be adequate with no changes planned. Staff underwrites this assertion as well on page 20 of the NRC Staff's Initial Statement of Position on New England Coalition Contentions. I do not agree the program as implemented to date is adequate.

NEC raised significant concerns regarding the Flow-Accelerated Corrosion Program and asserted 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 10

)

I equipment dud to flow-accelerated corrosion during extended plant operation. The responses provided in summary disposition as well as Entergy's Reply and Staff s Reply do not address NEC's concerns and in fact raise troubling new concerns beyond simply the sufficiency of the Vermont Yankee flow-accelerated corrosion program as presently credited for license renewal.

The Applicant's response summarized during motion for summary disposition is that it's present FAC program is consistent with industry guidance including EPRI NSAC 202L R.3 and that the use of the CHECWORKS model is a central element in the FAC program 'implementation. The Applicant stated that it is relying on its current program for FAC management for the license renewal period, and "furthermore, the FAC program that will be implemented by Entergy is the same program being carried out today... [and] will meet all regulatory guidance." See Entergy Reply at 34.

Entergy represents that it will rely on its current FAC management program for purposes of FAC management during the license renewal period, that no changes to this program are planned, and that this program complies with EPRI guidelines. See, Entergy's Initial Statement of Position on New England Coalition Contentions at 34 ("The current FAC program, which will be used during the license renewal period, meets industry prac'tice as reflected in NSA C-202L..."). My review provided in pre-filed testimony shows that Entergy's current program is not in compliance with EPRI guidelines.

Q10. Entergy asserts on page 34 of its Initial Statement of Position that "the program has been reviewed, audited, and inspected with only minor, mostly 11

administrative issues identified," and discounts its own Quality Assurance audit, which declared the program "unsatisfactory." How do you respond?

A10. I believe thatthese statements indicate that Entergy may have ignored or misconstrued the fundamental requirements of 10CFR Part 50, Appendix B, "Quality Assurance Requirements for Nuclear Power Plants." It appears that federal requirements for Quality Assurance (QA) are being set aside. Quality Assurance Division Audit No.

QA-8-2004-VY-1 declared the Flow Accelerated Program "unsatisfactory," submitted two 2

Condition Reports, and found five findings and seven areas of improvement. See, Exhibit NEC-UW_09 at 2. Yet Entergy's Initial Statement of Position interprets the 38-page document as containing "only minor, mostly administrative issue[s]." Entergy Initial Statement of Position at 34.

Furthermore, the Entergy asserts this single analytical tool for predicting unacceptable wall thinning should, as policy, be set aside as it was for four components, See Exhibit NEC-UW_20 at 5 of 14. Thus the Entergy provides a second indicator where the Licensee obliquely waived Appendix B requirements for Quality Assurance. See Entergy Statement of Initial Position at 48.

That again is misapplication of the requirements of Appendix B, which is particular to the Flow Accelerated Program, where the Applicant's only defense to its failure to prepare condition reports associated with unacceptable wall thinning,, a prediction derived from its own analysis, is somehow that this component shown .not to be meeting quality standards is deemed acceptable "as is" until the next outage. Therefore, there are two indications of a troubling and clearly deep-seated failure to properly implement the requirements of a compliant Quality Assurance Program. Appendix B to 12

10 CFR Part 50 requires among other things,Section III, "Design Control; and Section XVI, "Corrective Action" The latter section of the rule includes the following:

Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances 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 the appropriate levels of management.

Quality Assurance requirements~are not a practicethat may. or may not be voluntarily implemented by the Licensee, but are in fact are regulatory requirements promulgated under federal rules. The Applicant incorrectly asserts that a failure theoretically predicted by the CHECWORKS model is somehow treated differently than a failure predicted by actual inspection data. The Applicant is incorrect in assuming that a failure predicted by CHECWORKS does not meet the threshold for a condition report, with timely follow-up or corrective action, as fundamentally required under Appendix B.

The Licensee has no regulatory grounds to escape a determination of potential failure by reason of its assertion that "if a planning tool such as CHECWORKS ..... determines a theoreticalconclusion... as such no condition reports are required." See Entergy Statement of Initial positionat 48. This improper rationale is essentially analogous to a Licensee ignoringa Technical Specification requirement calling for declaration of a component or system to be classified as inoperable and a Limiting Condition of Operation started if a surveillance is missed. In the analogous situation, a component is administratively (theoretically) declared inoperable, although its actual functionality is unknown.

13

The consequences of the Licensee's apparent policy regarding Appendix B requirements, for Vermont Yankee's Flow Accelerated Corrosion Program are significant and have broad implications .to multiple programs relied upon for renewal. Essentially, following the Licensee's logic every program can be viewed as theoretical when it is intended to be a predictive tool. The implications of Entergy's statements are profound and raise questions regarding credibility of all the Aging Related Management Programs proposed and Entergy's actual intentions for monitoring, and maintaining the plant if the license is extended.

Qll. Has-applicant provided in its response any reasonable assurance that pipe thinning beyond code limits will not occur in the period between outages?

All. No. Quite to the contrary, the applicant has stated at page 48 of its Initial Statement of Position, in reference to page 5 of 14 of PP7028 Piping Inspection Program, Exhibit NEC-UW_20, that wear rates predicted to exceed code limits will not be acted upon until the next outage. Based on statements made by the Applicant regarding pipe thinning predictions including negative time to inspect (described as negative Tmin in the document) and predictions of unacceptable wear rates leading to thinning beyond code limits prior to the next outage, coupled with the decision to not prepare condition reports (or an analogous report consistent with requirements of a corrective action program as part of Appendix B), it is my opinion that reasonable assurance is not provided, and that the NRC Staff erroneously concluded that the program is complete, correct and adequat6.

Therefore, my opinion is that the staff erroneously concluded that the program is complete, correct and adequate.

14

Q. 12 Does Entergy's Initial Statement of Position resolve the programmatic weaknesses you identified in your direct testimony, including open corrective actions, stale open action items from condition reports, and the negative assessment of the program stated in the 2006 cornerstone roll up report?

A12. No. Entergy characterizes the issues I have identified as shortcomings in the documentation paperwork with no substantive implications. I disagree. Any one of the Quality Assurance findings are significant. For example, a classic indictor of a problematic program is age of open corrective actions. A second indicator is number of Condition Reports, and number of extensions planned and then postponed to implement necessary actions to maintain the program current. Data drawn was sometimes more than fifteen years old.

Entergy expends much discussion, largely on a generic basis, on what ought to constitute a good FAC program. Entergy Statement of Initial Position at 36. However, Entergy does not respond to or take into consideration the VY's actual repeated historical failures to implement the FAC program from 1999 to the present day, which I have identified in my report, filed in this proceeding as Exhibit NEC-UW-03. With few exceptions, these numerous programmatic failures go unchallenged by Entergy.

Most significantly, successive implementation of CHECWORKS to current plant design inputs is undisputed as a mandatory element of the program, as required under NSAC 202L rev. 2 and rev. 3. Entergy makes no claim that this was consistently done.

Successive data passes at appropriateintervalsi with scope selection, current operating conditions etc, taken into consideration are a fundamental element to identifying appropriate grid selection points, and trending of wear items. However, this obligation 15

was consistently ignored for many years and at best done in fragments for many outages.

,See Exhibit NEC-UW 03, "Evaluation of Vermont Yankee Nuclear Power Station License Extension." This approach places the reviewer in the untenable position of having to look a look at wear data for trends with only very limited data points and then speculate as to whether the data set is sufficient. This approach is invalid.

Detailed Review of Entergy and Staff Reply Q13. Do you take issue with the general merits of the approach to FAC management recommended in NSAC 202L?

A13. No. My focus is strictly on the adequacy of the implementation of NSAC 202L at VY.

Q14._On Page 38 of its Initial Statement of Position, Entergy makes the following assertion regarding FAC Susceptibility review: "the only CHECWORKS inputs affecting'FAC wear rate that need to be changed to model uprate conditions were the flow rate and the temperature. These were updated at VY upon implementation of, the EPU." Do you agree that flow rate and temperature are the only inputs that were necessary to incorporate into the model?

A14,- No. I disagree. Identification of the added inputs should be made, incorporating the results of all pertinent susceptibility analyses. Apparently, this has not been done. First, Exhibit E4-32 is a copy of a susceptibility analysis performed by Entergy in 2005.. This analysis was performed fully five years after the previous-analysis was completed in 2000.

This five year gap is found by examining the dates associated with the 2005 Susceptibility analysis. Numerous changes to the plant occurred between 2000 and 2005. For example, in 2003, the reactor recirculation and residual heat removal piping was replaced. See, Exhibit NEC-UW_27 at 6, Attachment 1. Second, operational factors (such as TECH 16 N)

SPEC changes, configuration changes, and material changes) should have triggered a new susceptibility analysis well before the analysis performed in 2005.

In brief, beginning in 2004, substantial plant modifications were performed, including system modifications etc, yet a current Susceptibility Analysis was not performed until 2005. The premise that only flow rate and temperature input changes were needed is not properly supported and incorrect.

11t is apparent that Vermont Yankee's FAC program management was broken from February 28, 2000 through October 25, 2005 based-ipon lack of Susceptibility Analysis

.alone. A comparison of program scope for piping inclusion, exclusion, small bore, large bore, fluid type etc, should have been incorporated into the FAC Program under the station Engineering Design Controls program on an ongoing basis-essentially any time a plant modification, system function change, Or operational change was contemplated.

Based upon the Applicant's information provided on page 38 of Entergy's Statement of Initial Position, as well as the Table 2 of Exhibit E4-32, the susceptibility analysis was set aside for more than five years, losing both continuity and assurance that all modifications have been evaluated and taken into consideration.

Proper grid point selection, proper sampling, proper frequency and the consistent integration of new data all. serve to remove speculation and uncertainty in the accuracy of CHECWORKS. This'fact by itself provides the impetus for a "new baseline," especially in light of the fact that a current baseline is, for all practical purposes, lacking. In conjunction with the relative uniqueness of the CPPU power uprate-chemistry changes, geometry changes, and of course velocity changes, the need for a "new baseline" is compelling. The strength of the CHECWORKS and the NSAC 202L methodology 17

endorsed in the GALL Report, is in its successive passes with tight control of changes in requisite input variables. These core elements have yet to be implemented.

In 2005, Entergy relied. on ancient susceptibility data for component selection points, such as small bore piping from data circa 1993. See Exhibit NEC-UW_20 at page 12 of 14. Five small bore points were selected that had never been inspected previously,,

indicating loss of control of the program. Entergy's defense of this methodology raises significant doubt as to the efficacy of the current program, and therefore the FAC program for the license renewal period.

A lack of a timely susceptible review can only serve to skew the results appropriate selection of specific wear points. An updated and inclusive Susceptibility Review should definitely have been required by NRC Staff in their review. It apparently was not.

The Susceptibility review did not appear to address wear points associated with plant modifications, and based upon the descoping of the inspection, even after recommending by engineering judgment, to include certain points they were not. See

'Exhibit E4-38 referenced in Entergys Statement of Initial Position at page 39.

Q15._On p e 39 of its Initial tatement of Position, E ergy states that in 2007, RFO 26, the rst outage since EPU, the inspections pe was altotal of 63 in ections !

per ormed, including 9 large bore inspections ono5you 0i?

by believe that E ergy met its cope of inspec/

ease n the s t i mm itment A15. No. It is parent on reviewing the r cord that Entergy first re ced the effective inspection scope and then enlarged it, in'the process offsetting any increase." A-mirror 18

analogy would be the retail store that raises its prices on certain goods, prior to o ing th at a sale discount.

ntergy's commitment to increase the number of inspection poi by 50% was made in re onse to an RAI, acknowledged in Entergy's Statement Initial Position at 39, but this co itment was tacitly fulfilled by increasing the mber of inspection points for RFO 26 on after decreasing the number of insp tion points (by descoping) for RFO 25. The Scoping ocument.for RFO 25 containd significantly. more inspection points. See, Exhibit NEC-UW_ 0, "PP7028 Piping FC Inspection Program FAC INSPECTION PROGRAM RECO S FOR 200 REFUELING OUTAGE." On page 20, it states "The planned 2005 RFO insp cti scope consists of 0137 large bore components at 16ldcations.. . [a]lso, any dus or'plant events that occur in the interim may necessitate an increase in the p1 ed scope." addition, criteria for inspection of components outside of CHECW S grid selection is iculated to include points simply because of the lengtintervals since previous inspe ons. These include Feedwater piping, and insteam piping. Id. at 3.

However, th umber called for in the above scoping docume is considerably more than the a al number of large bore components reported to be insp ted during RFO 25, as n Exhibit E4-38, where the Applicant notes that it limited its inspe ion to 27 lagere pontsf Th acua insp1c tio ofd6 lrg bre: pointsmfo.r* RF0.26 is abou2 Of Q16. Entergy disagrees with your statementin direct testimony that-"trending to.

the high end of the range [for bench marking] is appropriate where variables 19

affecting wear rate, such as flow velocity, have significantly changed, as at VYNPS following the 120% power up-rate...". How do you respond?

/

A16. Entergy questions the relevance of the report brought forward in my direct testimony in support of this statement. The report in question is "Aging Management and Life Extension in the U.S. Nuclear Power Industry," Exhibit NEC-UW_1 3, or the "Chockie Report." Entergy asserts that this report does not support trending to the high end of the range where variables such as flow velocity etc have significantly changed, because it is not industry guidance, but a report produced at the behest of the Petroleum Safety Authority of Norway regarding aging management and life extension in the U.S.

nuclear power industry.

The Chockie Report most certainly assimilates industry guidance, including regulatory rules and implementation of those rules, and compiles aging programs strictly with respect to the United States domestic nuclear power plants. On page 38, it answers exactly what is required if there is no pre-existing baseline, as is the case for Vermont Yankee. The use of the report by the Norway Petroleum Safety Authority has no bearing on its content. The report is on point to Contention 4.

The Chockie Report is applicable to the question of what constitutes an adequate baseline. Entergy assumes that its present baseline is adequate. I believe after examination of the failure to adequately implement the program, that VY does not have an adequate baseline. The Chockie Report is a concise primer on the effective implementation of NSAC 202L, including CHECWORKS, and by inference impeaches Entergy's Application as well as the adequacy of NRC Staff Review.

20

Q17 Do you agree with Entergy's statement contained in a single paragraph on page 45 of Entergy's Initial Statement of Position that the following eight claims you made in your direct testimony have no merit?

a. "that data from previous FAC inspections (prior to the EPU) were not entered into the CHECWORKS database (NEC-UW_03 at 2, 3, 6, 7-8, 15, 16, 17);"

b. "that CHECWORKS was not updated with the uprate parameters (id. at 5, 23);

c. that, for the period 2000-2006, VY failed to use a current version of CHECWORKS (id. at 6, 17);"

d. "that four components were predicted in 2004 to have wall thinning beyond operability limits (id. at 17-18, 22);"

e. "that open corrective actions identified in condition reports may not have cbeen completed (id. at 3-4, 18-19);"

f. '"that~ranking of small bore piping was not done (id. at 8, 20);"

2." "thlat the nnmbýef i~nspection poi wg'ere redu ced a the 2005 *ge

/Xid. at 7, 8, 2K* and" /

h. "that the 20061 refueling outage inspection "scope, planning, documentation, and procedural analysis appear to have been performed under a superseded program document" (id. at 5, 7, 20-21)."

A17. No. I disagree. Entergy states that these claims have no merit but does not actually refute them, or specifically address the majority of the documents I cite in support of my direct testimony. Entergy's reply to my direct testimony consists primarily of conclusory denials.

Q18. Does this conclude your rebuttal testimony.?

A18. Yes 21

OG/06/2008 14:40 2033896657 NORTHERN LIGHTS ENGI PAGE 011/01 I declare under penalty of perjury that flae foregoing is true and correct.

Ulrich Witte At . Connecticut, this 6_,_ day of June, 2008 personally appeared Ulrich Witte, aid having subscribed his name acknowledges his signature to be his free act and deed.

Before me:

Notary Public My Commission Expires K

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

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

)

(Vermont Yankee Nuclear Power Station) )

CERTIFICATE OF SERVICE I, Christina Nielsen, hereby certify that copies of NEW ENGLAND COALITION, INC.'S MOTION TO FILE CORRECTIONS TO EXHIBITS AND TO WITHDRAW CERTAIN TESTIMONY OF ULRICH WITTE in the above-captioned proceeding were served on the persons listed below, by U.S. Mail, first class, postage prepaid; and, where indicated by an e-mail address below, by electronic mail, on the 2 7 th of June, 2008.

Administrative Judge Office of the Secretary Alex S. Karlin, Esq., Chair Attn: Rulemaking and Adjudications Staff Atomic Safety and Licensing Board Mail Stop: O-16C1 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001 E-mail: hearingdocket@nrc.gov E-mail: ask2@nrc.gov Sarah Hofmann, Esq.

Administrative Judge Director of Public Advocacy William H. Reed Department of Public Service 1819 Edgewood Lane 112 State Street, Drawer 20 Charlottesville, VA 22902 Montpelier, VT 05620-2601

'E-mail: whrcvillea.embaromail.com E-mail: sarah.hofmanna.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: OCAAmailgnrc.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; mcbl@nrc.gov; Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission susan.uttal@nrc.gov; jessica.bielecki@nrc.gov Washington, DC 20555-0001 E-mail: rew@nrc.gov Anthony Z. Roisman, Esq.

National Legal Scholars Law Firm 84 East Thetford Road Lyme, NH 03768 E-mail: aroisman(inationallegalscholars.com

David R. Lewis, Esq.

Marcia Carpentier, Esq. Matias F. Travieso-Diaz Lauren Bregman Pillsbury Winthrop Shaw Pittman LLP Atomic Safety and Licensing Board Panel 2300 N Street NW Mail Stop T-3 F23 Washington, DC 20037-1128 U.S, Nuclear Regulatory Commission E-mail: david.lewis@pillsburylaw.com Washington, DC 20555-0001 matias.travieso-diaz(~ipillsburvlaw.com E-mail: mxc7@nrc.gov Lauren.Bregman@nrc.gov Diane Curran Harmon, Curran, Spielberg, & Eisenberg, L.L.P.

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 Concord, NH 03301 E-mail: Peter.roth@doi.nh.gov Matthew Brock Assistant Attorney General Environmental Protection Division Office of the Attorney General One Ashburton Place, 18th Floor Boston, MA 02108 E-mail: Matthew.BrockCistate.ma.us by:

Christina Nielsen, Administrative Assistant SHEMS DUNKIEL KASSEL & SAUNDERS PLLC