ML081620254

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

ML081620254
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	06/02/2008
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-71
Download: ML081620254 (283)

Text

SHEMS DUNKIEL KASSEL & SAUNDERS P LL C RONALD A. SHEMS* GEOFFREY H: HAND KAREN L. TYLER BRIAN S. DUNKIEL** . REBECCA E. BOUCHER

_ _ _ _ASSOCIATE ATTORNEYS JOHN B. KASSEL EILEEN I. ELLIOTT OF COUNSEL MARK A. SAUNDERS ANDREW N. RAUBVOGEL DOCKETED USNRC 2008 June 2, June 3, 2008 (8:00am)

Office of the Secretary OFFICE OF SECRETARY Attn: Rulemaking and Adjudications Staff RULEMAKINGS AND Mail Stop O- 16C1 ADJtJDICATIONS STAFF 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 A Proprietary Document

Dear Sir or Madam:

Please find enclosed for filing in the above-stated matter New England Coalition, Inc.'s Rebuttal Statement of Position, Testimony and Exhibits. One document that Entergy has designated proprietary is discussed in the rebuttal testimony of Dr: Joram Hopenfeld, Exhibit NEC-JH_63.

This document is:, Letter to James Fitzpatrick from EPRI (February 28, 2000). It 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.

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 9 I COLLEGE STREET . BURLIN'GTON, VERMONT 0540 I TEL 802 / 860 1003

• FAX 802 / 850 1208 - www;sdkslaw .com

• Adso admitted in the State of Maine

• Also admitted in the District of Columbia

NEW ENGLAND COALITION- INC.'S REBUTTAL EXHIBIT IIST Exhibit Number Name of Exhibit NEC-JH_63 Prefiled Rebuttal Testimony ofJoram Hopenfeld NEC-JH_64 Electric Power Research Institute ("EPRI"), "Materials Reliability Program: Guidelines for Addressing Fatigue Environmental Effects in a License Renewal Application (MRP-47, Revision 1)" (September, 2005).

NEC-JH_65 EPRI, "R&D Status Report: Nuclear Power Division," EPRiJournal (Qanuary/February 1983): 52-54.

NEC-JH_66 Wire, Gary L. and William J. Mills, "Fatigue Crack Propagation Rates for Notched 304 Stainless Steel Specimens in Elevated Temperature Water," Journalof Pressure Vessel Technology 126 (August 2004): 318-326.

NEC-JH_67 US NRC Docket Numbers 50-247-LR and 50-286-LR, "New'York State's Supplemental Citation in Support of Admission of.Contention',

26A" (May 22, 2008).

NEC-JH_68 Entergy, "Condition Report: Steam Dryer Inspection Indications,"

CR-VTY-2007-02133 (May 28, 2007).

NEC-JH-69 Simonen, Fredric, A. and Stephen R. Gosselin, "Life Prediction and Monitoring of Nuclear Power Plant Components for Service-Related Degradation," Journalof Pressure Vessel Technology 123 (February 2001):

58-64.

NEC-JH_70 Tennessee Valley Authority, "Memorandum: Sequoyah Nuclear Plan Units 1 and 2 - Preliminary Report on the Condensate-Feedwater Piping Inspection - Suspected Erosion-Corrosion Areas" January 27, 1987).

NEC-JH-71 Bignold, G.J. et al, "Paper 1," Water Chemisti ii, BNES (1980): 5-18.

NEC-JH_72 Woolsey, I.S. et al, "Paper 96: The Infulence of Oxygen and Hydrazine on the Erosion-Corrosion Behaviour and Electrochemical Potentials of Carbon Steel under Boiler Feedwater Conditions,"

Water Chemisty of Nuclear Reactor SAystems 4 (1986): 337-44.

NEC-RH_04 Prefiled Rebuttal Testimony of Rudolf Hausler NEC-RH_05 Hausler, Rudolf H., "Flow Assisted Corr6sion (FAC) and Flow Induced Localized Corrosion: Comparison and Discussion" Uune 2, 2008).

I 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.

'REBUTTAL STATEMENT OF POSITION In accordance with 10 C.F.R. § 2.1207(a)(2) and the Atomic Safety and Licensing Board's ("Board") November 17, 2006 Order,I New England Coalition, Inc. ("NEC") hereby submits its Rebuttal Statement of Position ("Statement") on NEC's Contentions 2A and 2B (environmentally-assisted metal fatigue analysis), 3 (steam dryer), and 4 (flow-accelerated r

corrosion). In support of this Statement, NEC submits the attached rebuttal testimony of Dr.

Joram Hopenfeld 2 and Dr. Rudolf Hausler,3 and the Exhibits listed on the attached Rebuttal Exhibit List.

I. NEC CONTENTIONS 2A AND 2B Licensing Board Order (Initial Scheduling Order) (Nov. 17, 2006) at 10(D) (unpublished).

2Exhibit NEC-JH_63.

3 Exhibit NEC-RH_04.

(Environmentally-Assisted Metal Fatigue Analysis)

The evidence contained in Entergy's and the NRC Staff's direct testimony and exhibits fails to prove the validity of Entergy's CUFen Reanalyses. Indeed, NRC Staff witness Dr. Chang has testified that the NRC Staff cannot determine the conservatism of Entergy's analysis, and must therefore rely on Entergy's proposed fatigue monitoring program to demonstrate its conservatism during the period of extended operation. See" Chang Rebuttal Testimony at Al10. The Board should therefore decide Contentions 2A and 2B in NEC's favor. The Board should find that Entergy has failed to satisfy § 54.21(c)(1)(ii) by projecting its environmentally-assisted metal fatigue TLAA to the end of the period of extended operation, and therefore must now rely, pursuant to*§ 54.2 1(c)()(iii), on an aging management program to provide reasonable assurance of public health and safety. NEC should then be permitted to litigate its Contention 2, now held in abeyance, which addresses the sufficiency of Entergy's aging management plan for environmentally-assisted metal fatigue.

I7 NEC's rebuttal evidence concerning Contentions 2A and 2B is'contained in the prefiled rebuttal testimony of Dr. Joram Hopenfeld, Exhibit NEC-JH,_63 at 2-19 and additional rebuttal Exhibits NEC-JH_64 - NEC-JH_67.

A. The\NRC Staff Misconstrues the ReqUirements of 10 CFR § 54.21(c)(1).

The NRC Staff's ("the Staff") Initial Statement of Position misconstrues 10 CFR

§ 54.21 (c)(1). By the Staff's construction of this rule, Entergy could resolve any of NEC's Contention 2A and 2B criticisms of the CUFen reanalyses through a commitment to continued "refinement" of these analyses after the close of the ASLB proceeding. The Staff s position is inconsistent with standard rules of statutory and regulatory' 2

construction, as well as with this Board's treatment of NEC's Contention 2, 2A and 2B in this proceeding to date. Most importantly, it would defeat the ability of any license renewal intervenor to litigate an applicant's Time Limited Aging Analysis ("TLAA")

methodology.

Section 54.21 (c)(1) allows a license renewal applicant three options to address an aging-related health and safety issue that it has evaluated under its current license through analysis that involves time-limited assumptions. It reads as follows:

(c). An evaluation of time-limited aging analyses.

(1) A list of time-limited aging analyses, as defined in § 54.3, must be provided.

The applicant shall demonstrate that -

(i) The analyses remain valid for the period of extended operation; (ii) The analyses have been-projected to the end of the period of extended operation; or (iii) The effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

2N 10 CFR § 54.21 (c). Under § 54.21 (c)(1)(i), the applicant may demonstrate that the>

analysis performed under its current license is valid for the period of extended operation.

If the applicant is unable to satisfy § 54.21(c)(1)(i), it may project the analysis to the end of the periodof extended operation under § 54.21 (c)(1)(ii). Finally, if the applicant is unable to demonstrate reasonable assurance of public health and safety through a TLAA analysis under § 54.21 (c)(i) or § 54.21 (c)(ii), it must then develop an aging management

,plan under § 54.21 (c)(1)(iii).

Entergy's CUFen reanalyses are properly subject to 10 CFR § 54.21 (c)(1)(ii) -

Entergy has performed these reanalyses in an attempt to demonstrate that its CUFen TLAA has been projected to the end of the period of extended operation. This was the 3

NRC Staff s view in August, 2007. Then, the Staff rejected Entergy's license renewal commitment to complete its CUFen reanalyses prior to entering the period of extended operation on grounds that "in order to meet the requirements of 10 CFR § 54.21 (c)(1), an applicant for license renewal must demonstrate in the LRA that the evaluation of the time-limited aging analyses (TLAA) has been completed." See, Exhibit NEC-JH_62 at Enclosure 2.

Now, however, the NRC Staff takes the position that Entergy's CUFen Reanalyses constitute a "corrective action" to "manage the effects of aging" that falls under 10 CFR 54.21 (c)(1)(iii). The Staff has thus reversed its view of when Entergy must complete its CUFen reanalyses. It is now the Staff s opinion that Entergy may perform the CUFen Reanalysis as part of its aging management program after its license renewal application is granted, possibly even during the period of extended operation.

The Staff explains:

If a licensee chooses to satisfy § 54.21 (c)(1)(i) or (ii), the 'demonstration' must be in the LRA, and a commitment to perform analyses projecting 60-year CUFs prior to the period of extended operation is inconsistent with the regulatory language. However, if the licensee chooses to satisfy § 54.21 (c)(1)(iii), the licensee must instead demonstrate that effects of aging will be adequately managed and a commitment to perform refined CUF analyses in the future as part of an aging management program is acceptable.

NRC Staff Initial Statement of Position at 1I-12 (emphasis'in original).

The Staff's interpretation of § 54.21 (c)(1) is inconsistent with its plain language, and with standard rules of construction. Part 54.21 (c)(1)(iii) is properly interpreted as a requirement to manage aging in the event the TLAA cannot be projected to the end of the license renewal period. In other words, an applicant may avoid the obligation to develop an aging management plan un/der § 54.21 (c)(1)(iii) if it satisfies § 54.21 (c)(1)(i) or 4

54.21 (c)(l)(ii) by including a demonstration that the TLAA is either valid or can be projected for the period of extended operation in the LRA. Under the NRC Staff s construction, parts 54.21(c)(1)(i) and 54.21(c)(1)(ii) collapse into part 54.21(c)(1)(iii):

that is, the TLAA demonstration becomes a component of the aging management plan, instead of a means to avoid the obligation to develop an aging management plan. The Staff's construction is therefore invalid. Cf Dunn v. CFTC, 519 U.S. 465, 472, 473, 117 S.Ct. 913, 137 L.Ed.2d 93 (1997) (rejecting an interpretation of a statute that would have left part of it "without any significant effect at all," because "legislative enactments should not be construed to render their provisions mere surplusage.").

The Staff's interpretation is also inconsistent withthe Board's interpretation of NEC's Contentions 2, 2A and 2B in this proceeding to/date, which treats Entergy's CUFen reanalyses as distinct from its metal fatigue aging management plan, and as an alternative to a management plan. The Board ruled that NEC's Contention 2 addresses the sufficiency of the metal fatigue) management program. It held Contention 2 in abeyance, to be litigated only if NEC prevails on Contentions 2A and 2B, and Entergy then reverts to reliance on fatigue management. The Board's Order of November 7, 2007 reads in relevant part as follows:

When this litigation began, Entergy's application showed certain CUFs to be greater than unity, and Entergy indicated that it would manage such metal fatigue over the 20-year renewal period. NEC's original Contention 2 challenged the adequacy of Entergy s demonstration of its metal fatigue management program. Now Entergy says it has recalculated the CUFs to show that they are all less than 1, thus eliminating the need to manage metal fatigue over the renewal period. NEC Contention 2A challenges Entergy's recalculation of the CUFs. If NEC Contention 2 is successful and Entergy's revised CUF analyses are not shown to be sufficient, then Entergy might return to relying on a fatigue management program as a way of satisfying the Part 54 regulations.

5

• Thus,we conclude that NEC Contention 2A will be litigated now, and NEC Contention 2 will be held in abeyance. The proviso is that the parties are not to litigate Contention 2 unless and until Entergy returns to reliance on a metal fatigue management program (as would likely happen if NEC prevails on NEC Contention 2A).

Memorandum and Order (Ruling on NEC Motions to File and Admit New Contention),

November 7, 2007 at 12.

Finally, the Staff's position that Entergy's environmentally-assisted metal fatigue TLAA analysis should be treated as a component of its metal fatigue aging management

/

plan under § 54.21 (c)(1)(iii) has significant consequences for the rights of NEC and other license renewal intervenors to obtain information about and contest the validity of TLAAs. Per the Staff's view, the applicant may comply with § 54.21 through a commitment to perform the TLAA analysis after the application is granted, an approach that will obviously frustrate public scrutiny of the TLAA methodology.

These consequences are already playing out in the ASLB proceeding concerning Entergy's license renewal application for the Indian Point plant, in which both the State of New York and Riverkeeper, J

Inc. have petitioned for admission

/

of a con-tention similar to NEC's Contention 2. Entergy hastaken the positions that it should not be required to provide a information about its CUFen analyses for the NUREG/CR-6260 locations until after the close of the ASLB proceeding, and the Staff should accept a commitment to perform CUFen analyses as part of the Fatigue Monitoring Program per 10 CFR § 54.21 (e)(1)(iii); See, Exhibit NEC-JH-67 at Attachment 1, Enclosure 2, (see discussion of D-RAI 4.3.1.8-1 and D-RAI 4.3.1.8-2). The NRC Staff has apparently acquiesced in

• Entergy's effort to avoid public scrutiny of its CUFen methodology, and withdrew requests for this information. Id.

6

The Board should reject'the Staff's interpretation of 10 CFR § 54.21(c)(1). It should find that Entergy's CUFen Reanalyses fall under § 54.21 (c)(1)(ii), and must be completed as part of Entergy's License Renewal Application. The Board should further find that Entergy cannot satisfy § 54.21 (c)(1) with a license renewal commitment to fix any problems in its CUFen Reanalyses, demonstrate the conservatism of those analyses, or finish those analyses after the close of the ASLB proceeding.

B. Enterly's Evidence Does Not Include Information Necessary to Validate its CUFen Reanalyses; Enteray Therefore Fails to Satisfy its Burden of Proof.

Dr. Hopenfeld testifies that Entergy has not provided to NEC or filed in the evidentiary record before the Board the following information necessary to validate its CUFen Reanalyses:

I. Drawings of the VY plant piping from which it would be possible to validate Entergy's assumptions of uniform heat transfer distribution, including orientation angles, weld locations and internal diameters, Hopenfeld Rebuttal at A18, Exhibit NEC-JH_03 at 8;

2. A complete description of the methods or models used to determine velocities and temperatures during transients, Hopenfeld Rebuttal at A19, Exhibit NEC-JH_03at 9; and

3. Information regarding exactly how the number of plant transient cycles was determined for purposes of the 60-year CUF calculations, from which it would be possible to evaluate the conservatism of the cycle count, Hopenfeld Rebuttal at A2 1.

Regarding the first two issues, Entergy represents that some information was provided: 36 drawings, a copy of the Design Information Record, and some information regarding the calculation of flow velocity in response to Counsel's inquiry. Entergy Initial Statement of Position at 14. Dr. Hopenfeld testifies that the information Entergy provided is insufficient. Hopenfeld Rebuttal at A18 and A19.

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Entergy further faults NEC for failing to request any additional information it considered necessary to a complete evaluation of the CUFen analyses in "discovery." Id.

This argument of course ignores the fact that, to its tremendous disadvantage, NEC has no right to formal discovery in this Subpart L proceeding. See, 10 CFR § 1.1203, Hearing file; prohibition on discovery; In the Matter of Entergy Nuclear Vermont Yankee, LLC, and Entergy Nuclear Operations, Inc. (Vermont Yankee Nuclear Power Station), 64 NRC 131, 202, ASLBP 06-849-03-LR, (September 22, 2006)("under the 'informal' adjudicatory procedures of Subpart L, discovery is prohibited except for certain mandatory disclosures.").

More importantly, Entergy's argument that NEC should have requested information in fictitious "discovery" misses the point. Entergy has the burden of proof regarding whether its CUFen reanalyses satisfy 10 CFR § '54.2 1(c)(1)(ii), and provide reasonable assurance of public health and safety. Entergy does not even attempt to

.explain why its record evidence concerning the VY pipe configuration and the methods or models it used to determine velocities and temperatures during transients is sufficient to validate its CUFen reanalyses. Entergy therefore fails to meet its burden.

With respect to the third issue above, the transient cycle count, Dr. Hopenfeld testifies that the explanation stated in Entergy's direct testimony of its means of determining the number of plant transients for purposes of its CUF calculations-is inconsistent with information Entergy provided in-its LRA and in the reports of the CUFen analyses produced to NEC. Hopefifeld Rebuttal at A21. Entergy's direct testimony on this subject is vague, and does not indicate that an allowance was made for the likely increase in plant transients resulting from the 20 percent power uprate or the 8

fact that the number of plant transients is likely to ihcrease as a plant ages. Id. Dr.

Hopenfeld is unabl&eto determine whether Entergy's transient cycle count is conservative.

Id.

The NRC Staff's Initial Statement of Position misrepresents the testimony of NRC Staff witness Dr. Chang with respect to the transient cycle count. -The Statement of Position represents that the Staff "disagrees with NEC's assertion that Entergy's assumptions about the number of transients in its analyses are not conservative," and states that "[t]he Staff's position is that Entergy's assumptions are appropriate." NRC Staff Initial Statement of Position at 18. In fact and to' the contrary, Dr. Chang testifies that the staff, like Dr. Hopenfeld, "cannot determine the level of conservatism regarding the number of transient cycles at this time," and therefore relies on Entergy's Fatigue Monitoring Program to "ensure that the cycle projection is valid and that the fatiaue analysis results are conservative." Chang Rebuttal at A1O (emphasis added).

Thus, per the testimony of NRC Staff witness Dr. Chang, Entergy has not provided information to the NRC, or filed evidence before the Board, from which it is possible to determine whether its CUFen analysis results are conservative. Again, Entergy has not satisfied its burden of proof, and the Board must decide Contentions 2A I,/

and 2B in NEC's favor.

C. Calculation of the Fen Multiplier

1. The NRC Staff and Entergy are Incorrect that the ASME Code Does Not Require the Fen Correction.

Both Entergy and the NRC Staff contend that the ASME Code does not require any accounting for the effects of coolant environment on component fatigue life. This is incorrect. The Code requires that the code user must account for conditions in which 9

the environment is more aggressive than air. Rebuttal Testimony of Joram Hopenfeld at A5, citing, ASME Code, Appendix B at B-2 13 1.

2. NRC Staff guidance that sanctions use of the equations and procedure described in NUREG/CR-6583 and NUREG/CR-5704 to calculate Fen multipliers is not dispositive. The Staff must prove the validity of this guidance, but has not done so.

In response to Dr. Hopenfeld's argument that Entergy used outdated statistical equations published in NUREG/CR-6583 and NUREG/CR-5704 to calculate Fen values, when it should have instead considered data much more recently published in NUREG/CR-6909 (February 2007), both the NRC Staff and Entergy cite NRC guidance stated in Section X.MI of the GALL Report, NUREG-1801, Vol. 1, which sanctions use of the NUREG/CR-6583 and NUREG/CR-5704 equations to calculate Fen multipliers.

Entergy and the Staff also note that Regulatory Guide 1.207 recommends reference to NUREG/CR-6909 only for fatigue analyses in new reactors.

These guidance documents are by no means dispositive of NEC's criticisms of Entergy's method of calculating Fen values. "Agency interpretations and policies are not

'carved in stone' but must rather be subject to re-evaluation of their wisdom on a continuing basis." Kansas Gas and Electric Co. (Wolf Creek GeneratingStation, Unit 1),

49 NRC 441, 460 (1999), citing, Chevron USA, Inc. v. NaturalResources Defense Council, "Inc., 467 U.S. 837, 863-64 (1984)).

The GALL report and Regulatory Guide 1.207 do not contain legally binding regulatory requirements. The Summary and Introduction to NUREG- 1801, Vol. 1

/

includes the following explanation of its legal status:

10

Legally binding regulatory requirements are stated only in laws; NRC regulations; licenses, including technical specifications; or orders, not in NUREG series publications.

The GALL report is a technical basis document to the SRP-LR, which provides the Staff with Guidance in reviewing a license renewal application .... The Staff should also review information that is not addressedin the GALL reportor ik otherwise differentfriom that in'the GALL report.

NUREG-1801, Vol. 1, Summary, Introduction, Application of the GALL Report (emphasis added). Likewise, the face page to Regulatory Guide 1.207 states the following: "Regulatory Guides are not substitutes for regulations, and compliance with them is not required." Regulatory Guide 1.207; See also, In the Matter of International Uranium (USA) Corporation,51 NRC 9, 19 (2000) ("[NRC NUREGS, Regulatory

-Guides, and Guidance documents] are routine agency policy pronouncements that do not carry the binding effect of regulations...

NUREG-1801, Vol. 1 and Regulatory Guide 1.207 do not preclude this Board from considering the question at the heart of NEC's Contentions 2A and 2B: What is the most appropriate method of calculating the effect's of the environment on fatigue?

[NUREGs] do not rise to the level of regulatory requirements. Neither do, they constitute the only means of meeting applicable regulatory requirements.... Generally speaking,.., such guidance is treated simply as evidence of legitimate meansfor complying with regulatory requirements, and the staff is requiredto demonstratethe validity of its guidance if it is called into question during the course of litigation.

In the Matter of CarolinaPower & Light Company andNorth CarolinaEastern Municipal Power Agency (ShearonHarrisNuclear Power Plant), 23 NRC 294 (1986),

citing, Metropolitan Edison Co. (Three Mile IslandNuclear Station, Unit 1), 16 NRC 1290, 1298-99 (1982) (emphasis added); See also, In the Matter of Connecticut Yankee 11

Atomic Power Company (Haddam Neck Point), 54 NRC 177, 184 (2001), citing, Long Island Lighting Co. (Shoreham Nuclear Power Station, Unit 1), 28 NRC 288, 290 (1 988)("NUREGs and similar documents are akin to 'regulatory guides.' That is, they provide guidanice for the Staff's review, but set neither minimum nor maximum regulatory requirements."); In the Matter of Private Fuel Storage, LLC, 57 NRC 69, 92 (2003)("[A]n intervenor, though not allowed to challenge duly promulgated Commission regulations in the hearing process... is free to-take issue with ... NRC Staff guidance and thinking .....

The Staff is required in this proceeding to prove the &urrentvalidity of its guidance concerning the calculation of Fen multipliers, but has produced little if any evidence of this. Entergy and the NRC Staff offer only one substantive reason 4 for use of the NUREG/CR-6583 and NUREG/CR-5704 equations over information contained in NUREG/CR-6909: both contend that the NUREG/CR-6909 "procedure" is less conservative and will generally producelower Fen multipliers for operating reactors.

See, Fair Rebuttal at A5 and A6, Stevens Rebuttal at A50. Dr. Hopenfeld explains that the overall NUREG/CR-6909 "procedure" could be considered less conservative because NUREG/CR-6909 contains new air fatigue curves thiat are less conservative that the current ASME Code fatigue curves. Hopenfeld Rebuttal at A6. He further testifies, however, that he has never recommended use of these new air fatigue curves. Until the current fatigue curves in the Code are officially modified, these curves must be considered the "best representation of fatigue life in air." Id.

/

4 The Staff also offers a nonsubstantive reason: i.e., that it would be inconvenient to change its guidance while a number of license renewal applications are pending or anticipated.'

12

Dr. Hopenfeld explains that the alleged greater conservatism of the NUREG/CR-6583 and NUREG/CR-5704 "procedure" is irrelevant to his main point about how Entergy should have used information contained in NUREG/CR-6909 in its CUFen analyses. Hopenfeld Rebuttal at A6, A7. As Dr. Hopenfeld has previously testified, \

NUREG/CR-6909 describes many factors known to affect fatigue life that are not accounted for in the ANL 1998 Equations contained in NUREG/CR-6583 and NUREG/CR-5704. Dr. Hopenfeld's rebuttal testimony provides a summary of these factors at A5, Table I',and observes that Entergy's direct testimony addresses only one of them, surface finish. Hopenfeld Rebuttal at A5. This is the relevant information Entergy should have taken from NUREG/CR-6909. Hopenfeld Rebuttal at A7. Entergy and NRC staff witnesses fail to explain why this information contained in NUREG/CR-6909, published after the GALL report, should beignored in the license renewal process.

Dr. Hopenfeld testifies that, given the current state of the technology, it simply is not possible to calculate Fen multipliers that are precision-adjusted to plant conditions, as Entergy purports to have done. Hopenfeld Rebuttal at A7. Given the many uncertainties in the calculation of Fen, he recommends use of bounding values contained in NUREG/CR-6909 - 12 for austenitic stainless steel and 17 for carbon and low alloy steel.

Id.

3. NEC's Rebuttal Evidence Concerning Calculation of Fen Multipliers NEC witness Dr. Joram Hopenfeld's rebuttal testimony addresses the following

,7 t additional technical issues regarding the calculation the Fen multipliers raised by Entergy and the NRC Staff.

13

N Dr. Hopenfeld disagrees with NRC witness Dr. Chang that Fen values of 12 for austenitic stainless 17 for carbon and low alloy steel represent a "worst case scenario," or that application of these values is unreasonably conservative. Hopenfeld Rebuttal at A9.

" Dr. Hopenfeld disagrees with Entergy witness Mr. Stevens that Fen=] 7 applies only to high oxygen and temperature environments that do not exist at VYNPS.

Hopenfeld Rebuttal at A 10.

N Dr. Hopenfeld does-not agree with Entergy and NRC Staff witnesses that any lack of conservatism in Fen values calculated by the ANL 1998 Equations is counterbalanced by excess conservatism in the ASME Code design fatigue curves. He observes that there is no general agreement among researchers that the current Code is conservative. Hopenfeld Rebuttal at A 12.

E Dr. Hopenfeld disagrees with Entergy witness Mr. Fitzpatrick that Entergy properly accounted for surface roughness effects through use of ASME Code design fatigue curves that include a "safety factor" to account for these effects. Hopenfeld Rebuttal at A 13.

E Dr. Hopenfeld disagrees with Entergy witness Mr. Fitzpatrick that Entergy has demonstrated its use of bounding values for oxygen as an input to the ANL equations in all its CUFen analyses. Hopenfeld Rebuttal at A14. Mr. Fitzpatrick refers to steady state values as determined by a computer Code called BWRVIA that Entergy has neither described nor provided to NEC. Id. Mr. Fitzpatrick does not address the impact on Fen of oxygen concentrations that occur during transients at higher levels than at steady state.

Id.

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• Dr. Hopenfeld testifies that it was inappropriate for Entergy to exclude a correction factor for cracking in the cladding and base metal of the feedwater nozzles based on results of its 2007 inspection of these nozzles for cracks in the base metal.

Hopenfeld Rebuttal at A 15.

D. Calculation of 60-Year CUFs NEC witness Dr. Joram Hopenfeld's rebuttal testimony addresses the following issues, in addition to the above-discussed potential lack of conservatism in projecting transient cycles, regarding the calculation the 60-year CUFs raised by Entergy and the NRC Staff.

0 Dr. Hopenfeld disagrees that Entergy's CUFen analyses properly applied a heat transfer equation that applies only to a fully developed turbulent flow to the VYNPS nozzles. Specifically, he disagrees with Entergy witness Mr. Stevens that flow in the feedwater nozzle is fully developed because the upstream horizontal pipe is 48 inches long. Hopenfeld Rebuttal at A16. Dr. Hopenfeld further observes that Mr. Stevens did not explain why, in transients where the flow stops and heat transfer occurs by natural K

convection, a correction was not made for circumferential variation of the heat transfer.

both during single phase flow and during condensation. Id.

E Dr. Hopenfeld disagrees with Entergy witness Mr. Stevens that it i's unnecessary to correct a heat transfer equation used in the CUFen Reanalyses by the ratio of the viscosities evaluated at the bulk and wall temperatures during each transient because there are minimal differences in temperature between the pipe wall and the bulk of the fluid. Hopenfeld Rebuttal at A17. Mr. Stevens did not quantify actual temperature 15

differences, which could only be determined from data on wall and bulk fluid temperature histories for sample transients. Id. Such information was not provided. Id.

Nt M Dr. Hopenfeld disagrees that Entergy's use of the simplified Green's Function methodology in its Initial CUFen Reanalysis introduced only a small error.

Hopenfeld Rebuttal at A20. Entergy has neither explained nor investigated the physical reasons for discrepancies between results 6btained by the Green's Function methodology and the more exact methodology, classic NB-3200 analysis. Id. Results obtained by the Green's Function methodology therefore incorporate unquantified uncertainties. Id.

E. Error Analysis NEC witness Dr. Joram Hopenfeld's rebuttal testimony addresses the following issues regarding the need for error analysis raised by Entergy and the NRC Staff.

a Dr. Hopenfeld disagrees with Entergy's witness that it was not necessary to perform an error analysis to validate its analytical techniques because the stress analysis is based on bounding values. Hopenfeld rebuttal at A23.

0 Dr. Hopenfeld disagrees with NRC witness Dr. Chang that an error analysis was unnecessary because of conservatism built into the ASME Code and the ANL 1998 Equations. Hopenfeld Rebuttal at A24.

Ill. NEC CONTENTION 3 (Steam Dryer)

NEC's rebuttal evidence concerning Contention 3 is contained in the prefiled rebuttal testimony ofDr. Joram Hopenfeld, Exhibit NEC-JH_63 at*20-24, and additional rebuttal Exhibits NEC-JH_68 and NEC-JH'69.

A. The Issue Before the Board is Whether a Steam Dryer Aging Management Plan Uninformed by Knowledge of Stress Loads on the 16

Dryer for Comparison to Fatigue Limits is Adequate to Provide Reasonable Assurance, of Public Safety.

The validity of the steam dryer stress load modeling Entergy conducted during implementation of the VY power uprate as a basis for Entergy's steam dryer aging management plan during the period of extended operations has not been litigated in this proceeding or otherwise established. The Board has ruled that the assessment of this modeling conducted during the EPU proceeding was not dispositive for purposes of life extension:

Entergy's apparent assertion that the history of the steam dryer issue in the separate EPU proceeding should resolve the issue in this proceeding is...

without foundation. As demonstrated by Entergy's own pleadings,.steam dryer issues were addressed in the EPU proceeding primarily in regard to the power ascension toward EPU levels and the first few operating cycles thereafter.

In the Matter of Entergy Nuclear Vermont Yankee, LLC, and Entergy Nuclear Operations,Inc.-(Vermont Yankee Nuclear Power Station), 64 NRC 131, 189 (September 22, 2006).

Moreover, Entergy represented in its Motion for Summary Disposition of NEC's Contention 3 that its steam dryer aging management program will consist exclusively of periodic visual inspection and monitoring of plant parameters as described in General Electric Service Information Letter 644 (GE-SIL-644), will not involve the use of any analytical tool to estimate stress loads on the steam dryer, and will not rely on the finite element modeling conducted prior to implementation of the extended power uprate (EPU) in 2006 for knowledge of steam dryer stress loads.

In partially granting Entergy's Motion for Summary Disposition, the Board accepted Entergy's representation that its steam dryer aging management plan would not 17

rely on the pre-EPU steam dryer modeling. Memorandum and Order (Ruling on Motion for Summary Disposition of NEC Contention 3), September 11,2007 at 10 ("Entergy's expert confirms that this program does not require the use of the CFD and ACM computer codes or the finite element modeling conducted during the EPU."). In doing so, the Board rejected NEC's argument that it should be permitted to litigate the validity of the EPU steam drer modeling as the basis for aging management. NEC's pleading in opposition to Entergy's Motion for Summary Disposition stated the following regarding this issue:

As stated in the attached Third Declaration of Dr. Joram Hopenfeld, Entergy's claim that its steam dryer aging management program will not involve any means of estimating and predicting stress loads on the dryer simply is not credible. Exhibit 1, Third Declaration of Dr. Joram Hopenfeld ("Hopenfeld Declaraition 3") ¶ 6. A valid steam dryer aging management program must include some means of estimating and predicting stress loads on the steam dryer, and determining that peak loads will fall below ASME fatigue limits. Hopenfeld Declaration ¶ 5.

Entergy represents that it did conduct this analysis as part of the, Vermont Yankee EPU power ascension testing using the ACM and CFD models.

Hoffman Declaration ¶¶ 11-13. Entergy now proposes sole reliance on visual inspection and plant parameter monitoring during the renewed license period. Such reliance must be based on Entergy's previous ACM/CFD-based predictions that stress loads on the dryer will not cause fatigue failures. Hopenfeld Declaration ¶ 7. NEC's concerns regarding the validity of the ACM and CFD models and the stress and fatigue analysis Entergy conducted using these models therefore remain current and relevant.

New England Coalition, Inc.'s Opposition to Entergy's Motion for Summary Disposition of NEC's Contention 3 (Steam Dryer) (May 9, 2007) at 4.

Both Entergy and the NRC Staff now contend that Entergy's steam dryer aging management program does in fact rely on the steam dryer modeling conducted during EPU implementation for knowledge of dryer stress loads. See, Entergy Initial Statement of 18

Position at 32 ("[T]he loadings on the dryer derive from plant geometries ... that have not changed since the uprate was implemented, so there has been no change to the loadings on the dryer and the resulting stresses. Therefore, there is no reason, to provide continued instrumentation to measure loadings or further analytical efforts."); NRC Staff Initial Statement of Position at 19 (The Staff's position is that stress analysis as a means of estimating and predicting stress loads during operations "is not necessary because the results of the EPU power ascension program demonstrated that the pressure loads during the EPU operations do not result in stress on the steam dryer that exceed ASME fatigue stress r

limits.").

In light of the above-discussed procedural history, and Entergy's prior representations, the Board must disregard these current contentions that the modeling of the dryer during the EPU power ascension program is a proper basis for aging management.

This issue has not been determined, and the Board took it off the table in its decision of Entergy's Motion for Summary Disposition. The issue now properly before the Board is whether an aging management plan that consists solely of plant parameter monitoring, and partial visual inspection, uninformed by knowledge of dryer loading, can provide reasoriable assurance of public safety.

B. Hopenfeld Rebuttal Dr. Joram Hopenfeld provides the following rebuttal testimony regarding the above-stated issue properly before the Board.

N Dr. Hopenfeld testifies that the ability to estimate the probability of formation of loose parts requires knowledge of the cyclic loads on the dryer'to ensure that 19

the dryer is not subjected to cyclic stress that would exceed the endurance limit.

Hopenfeld Rebuttal at A28.

\ Dr. Hopenfeld observes that Mr. Hoffman and Mr. Lukens do not provide a single quantitative assessment in support of this position, discussed in A56-62 of their testimony, that the inspection programs at VY ensure that the dryer will not fail. Id.

a Dr. Hopenfeld disagrees with Entergy witness Mr. Lukens that "operating experience after the EPU (exemplified by the data collected during the 2007 inspection and the subsequent year of monitoring of plant operating parameters) demonstrates that the stresses experienced by the dryer are insufficient to initiate and propagate fatigue cracks." Hopenfeld Rebuttal at A29.

0 Dr. Hopenfeld provides a section of the Entergy Condition Report previously filed as Exhibit NEC-JH_59 that includes General Electric's statement that "continued [steam dryer crack] growth-by fati'gue cannot be ruled out." This section of the Condition Report was previously inadvertently excluded due to a clerical error.

Hopenfeld Rebuttal at A29. Dr.,Hopenfeld also disagrees with Entergy witness Mr.

Lukens that theinspection photographs provided in Entergy's Condition Report, Exhibit.

NEC-JH59 at 2-8, show that the cracks are inactive. Metallographic examinations would be required to demonstrate this, not remote camera photos. Hopenfeld Rebuttal at A3 1.

0 Dr. Hopenfeld observes that IGSCC cracks that now exist in the VY steam dryer can provide sites for corrosion attack which would in turn accelerate crack growth under cycling loading. The rate of crack propagation would depend on load intensities and duration. Id.

20

0 Dr. Hopenfeld disagrees with Entergy witness Mr. Hoffman that design basis loads ("DBA") cannot cause dryer failure. Hopenfeld Rebuttal at A32.

[ Dr. Hopenfeld disagrees with Entergy witness Mr. Hoffman that it is not necessary to estimate and predict dryer stresses because "[c]onfirmation that stresses on the VY steam dryer remain within fatigue limits is provideddaily by the fact that the) dryer has been able to withstand without damage the increased loads imparted on it during power ascension and for the two years of operation since EPU was implemented."

Hopenfeld Rebuttal at A33. Vibration fatigue is a time-related phenomenon; the fact that the dryer has not failed to date is not at all an indication that it will not fail in the future.

Id.

a Dr. Hopenfeld testifies that Entergy has not provided a quantitative estimate of the probability of crack detection, but should have done so, since the entire dryer is not accessible to visual inspection. Hopenfeld Rebuttal at A35.

IV. NEC CONTENTION 4 (Flow-Accelerated Corrosion)

NEC's rebuttal evidence concerning Contention 4 is contained in the prefiled rebuttal testimony of Dr. Joram Hopenfeld, Exhibit NEC-JH_63 at 24-41; additional rebuttal Exhibits NEC-JH_70- NEC-JH_72; the prefiled rebuttal testimony of Dr. Rudolf Hausler, Exhibit NEC-RH_04; and Dr. Hausler's report titled "Flow Assisted Corrosion (FAC) and Flow Induced Localized Corrosion: Comparison and Discussion," Exhibit NEC-RH_05.

Entergy witness Dr. Horowitz has testified that it is not necessary to recalibrate or "benchmark" the CHECWORKS model with plant inspection data following a twenty.

21

percent power uprate. Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4 - Flow-Accelerated Corrosion at A33, 34. Rather, Dr. Horowitz contends that the only update to the CHECWORKS model that is necessary following a twenty percent power uprate is the input of new values for flow rate and temperature into the model. Horowitz at A33, 34. Dr. Horowitz bases these assertions on his view that

"[flow-accelerated corrosion (FAC)] wear rates vary roughly with velocity and do not increase with velocity in [a] non-linear (exponential) manner. . . .", Horowitz at A49, and his beliefs that FAC is not fundamentally a local phenomena, and the CHECWORKS model can accurately predict any variations in FAC rates related to geometric features.

Dr. Horowitz contends that th9 CHECWORKS model accounts for any localized variations in FAC associated with geometric features through the use of "'geometric factors' to relate the maximum degradation occurring in a component, such as an elbow, to the degradation predicted to occur in a straight pipe." Horowitz at A47, A48.

Dr. Hopenfeld and Dr. Hausler disagree with Dr. Horowitz that recalibration of the CHECWORKS model is unnecessary following substantial changes in flow velocity and changes in temperature, and respond regarding Dr. Horowitz's grounds for this opinion as follows.

M Dr. Hausler testifies that the linear relationship between FAC rates and fluid velocity transitions to an exponential one as the local turbulence becomes such that erosional features become manifest. Whether such transition actually occurs when flow velocity increases following a power uprate must be determined experimentally. Hausler Rebuttal at A5, Exhibit NEC-RH_05.

22

M Dr. Hopenfeld stresses that "FAC is fundamentally a local phenomenon due to variations of local turbulence in curved pipe, nozzles, tees, orifices, etc," and that corrosion rates can be expected to "vary with location depending on the intensity of the local turbulence." Hopenfeld Rebuttal at A42, A52, A53, A54 He also disagrees with Dr. Horowitz that the rate of FAC corresponds weakly with the velocity, and varies less than linearly with time, and disputes the relevance of the data Dr. Horowitz cites in support of his position. Hopenfeld Rebuttal at A41, A46, A53, A55.

M Dr. Hausler does not agree that the CHECWORKS model, or any model, can fully account for variations in the rate of FAC due to geometric features and discontinuities. Hausler Rebuttal at A6; Exhibit NEC-R-H_05. Some things cannot be specified. For example, the internal residual weld bead from the root pass may be 1/8 inch high in one case, and 'A inch high in another case. Id. The upstream and downstream turbulence surrounding the weld bead will be more severe in the latter case, and a power uprate may disproportionately affect the flow over the larger bead. Id.

0 Dr. Hopenfeld observes that, while Dr. Horowitz denies the need to recalibrate CHECWORKS, he recognizes the need to increase the FAC inspection scope by 50% to account for the power uprate. Hopenfeld Rebuttal at A48. Entergy does not disclose what fraction of the total FAC susceptible area in the VY plant the proposed increased monitoring would represent, and its significance is therefore entirely unclear.

Id.

• Both Dr. Hopenfeld and Dr. Hausler take issue with Dr. Horowitz's definition of FAC as corrosion in proportion to the flow rate, Horowitz at A46, and observe that this definition excludes the more severe forms of localized corrosion - erosion-corrosion, 23

impingement and cavitation. Hausler Rebuttal at A6; Exhibit NEC-RH_05; Hopenfeld Rebuttal at A45. Both Hopenfeld and Hausler observe that this definition of FAC is entirely arbitrary. Erosion-corrosion, impingement and cavitation are extensions of FAC as the local flow intensity due to turbulence increases. The transition from one to the others is continuous and difficult to identify. Id. If CHECWORKS is unable to predict these more severe forms of localized corrosion related to high flow rates, which can particularly occur after a power uprate, then this is a serious shortcoming of the model and its application. Id.

Dr. Hausler and Dr. Hopenfeld also address the following additional issues:

0 Dr. Hausler observes that the accuraicy of CHECWORKS has been said to be within +/- 50%, but this statement is based on an erroneous interpretation of the graphic representation of predicted vs. measured wear. Hausler Rebuttal at A6; Exhibit NEC-R-_05. Actually, the accuracy is within a factor of 2 - the measured wear rates range from twice the prediction to half the prediction. Id. A factor of two difference between measured and predicted corrosion [or corrosion rate] can be quite significant with respect to selecting a particular item (line) for inspection during a refueling outage.

Id.

0 Dr. Hopenfeld disagrees with Dr. Horowitz's evaluation of industry FAC experience, and his contention that this experience demonstrates the efficacy of CHECWORKS. Hopenfeld Rebuttal at A39, A40, A49, A52, A53. Dr. Hopenfeld specifically disagrees that, in assessing industry FAC experience, a distinction should be drawn between pipe failures due to leaks and failures due to ruptures. Hopenfeld Rebuttal at A44, A53.

24

• Dr. Hopenfeld faults Entergy for its failure to specify the total FAC-susceptible area that is inspected during a typical outage. Hopenfeld Rebuttal at A43.

0 Dr. Hopenfeld disputes Dr. Horowitz's suggestion that the oxygen concentration at VY did not change in 2003. Hopenfeld Rebuttal at A5 1.

V. CONCLUSIONS Extended operation of VYNPS as Entergy has proposed in its LRA will jeopardize public health and safety. The LRA should be denied unless the important

)

issues addressed by NEC's Contentions 2A, 2B, 3 and 4 are resolyed.

June 2, 2008 New England Coalition, Inc.

by: I)

Andrew Raubvoge()

Karen Tyler SHEMS DUNKIEL KASSEL & SAUNDERS PLLC For the firm Attorneys for NEC 25

PROPRIETARY: REDACTED NEC-JH_63 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 In the Matter of I Docket No. 50-271-LR ENTERGY NUCLEAR VERMONT YANKEE, LLC, and ASLBP No. 06-849-03-LR ENTERGY NUCLEAR OPERATIONS, INC.

June 20, 2006 (Vermont Yankee Nuclear Power Station)

PRE-FILED REBUTTAL TESTIMONY OF Dr. JORAM HOPENFELD REGARDING NEC CONTENTIONS 2A, 2B, 3 AND 4 K\

Ql.' Please state your name.

Al. My name is Joram Hopenfeld.

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 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 all exhibits thereto, the Joint Declaration of James C.

Fitzpatrick and Gary L. 'Stevens on NEC Contention 2A/2B - Environme~ntally-Assisted Fatigue (May 12, 2008), the Joint Declaration of John R. Hoffman and Larry D. Lukens on NEC

Contention 3 - Steam Dryer (May 12, 2008), and the Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4 - Flow-Accelerated Corrosion (May 12, 2008). I have also reviewed the NRC Staff Initial Statement of Position on NEC Contentions 2A, 2B, 3, and 4 and all exhibits thereto, the Affidavit of John R. Fair Concerning NEC Contentions 2A &

2B (Metal Fatigue) (May 13, 2008), the Affidavit of Kenneth Chang Concerning NEC Contentions 2A & 2B (Metal Fatigue) (May 12, 2008), the Chang Colrrection Letter with Enclosures (May 22, 2008), the Affidavit of Kaihwa R. Hsu, Jonathan G. Rowley, and Thomas G. Scarborough Concerning NEC Contention 3 (Steam Dryer) (May 13, 2008), and the Affidavit of Kaihwa R. Hsu and Jonathan G. Rowley Concerning NEC Contention 4 (Flow-Accelerated Corrosion) (May 13, 2008).

Q4. Entergy contends that you have no experience or expertise relevant to the testimony you have provided concerning NEC's Contentions 2A, 2B,,3 and 4. How do you respond?

A4. I have a Ph.D in mechanical engineering, concentrating in Heat Transfer, Applied Electrochemistry, and Fluid Dynamics. I have 46 years of experience in the area of material/environment interaction (corrosion, erosion, fatigue) and related instrumentation. I have designed and conducted corrosion tests, I have reviewed and approved material fatigue-related issues for the FFTF and the CRBR reactors, and I have participated in the development of related codes and standards. I have participated in the evaluation of numerous material/environment related issues, including stress corrosion cracking in BWRs. I have managed experimental programs related to fatigue and corrosion in nuclear and fossil plants. I worked on PWR steam generator material-related issues for eight years at the NRC. I have published many papers in related areas in peer-reviewed scientific journals. I hold two patents relating to the detection of 2

¢

erosion/corrosion piping damage. I personally funded erosion-corrosion research studies at the University of Virginia.

To address the issues NEC raises in its Contentions 2A, 2B, 3 and ,4 requires a broad knowledge of heat transfer, corrosion and material fatigue. I believe that I have the expertise necessary~to provide the Board with a competent assessment of the fatigue and FAC issues relevant to the determination of the effects of the BWR environment on FAC and fatigue life.

The FAC and fatigue issues that I am addressing are not unique to the BWR environment, but rather' are common to many environments.

I. NEC CONTENTIONS 2A AND 2B (environmentally-assisted metal fatigue analyses)

A. Entergy's Calculation of Environmental Correction Factor, Fen Q5.' Does the fact that NRC guidance stated in Section X.M1 of the GALL Report sanctions use of the NUREG/CR-6583 and NUREG/CR-5704 equations to compute Fen multipliers demonstrate that this methodology satisfies ASME Code specifications?

A5. No. Section 111 of the ASME Code prescribes a set of curves for calculating fatigue life for different materials. These design curves, also known as S-N curves, are presented in terms of stress and the number of cycles to failure and are strictly based on laboratory tests in air. These tests incorporate correction factors for the effects of surface roughness, data scatter, and component size. See, Exhibit NEC-JH-26 at 3. These factors are not "safety margins," as Entergy witness Mr. Fitzpatrick suggests in his direct testimony at A8; they are correction factors. Exhibit NEC-JH-26 at 3. The Code requires that in situations where the environment is more aggressive than air the owner must account for such conditions. ASME Code, Appendix B at B-2131 (emphasis added). The LWR environment is known to reduce fatigue life significantly compared to air. Exhibits NEC-JH-26 at 3 and NEC-JH-03 at 1.

3

The Fen methodology described in NUREG/CR-6583 and NUREG/CR-5704, is a developing technology still unfinished. It is a work in progress; it contains many loose ends that allow the analyst to a large degree to select a desired outcome. This has not gone unnoticed by EPRI, which cautioned that "the current state of the technology with respect to the Fen methodology is incomplete or lacking in detail and specificity." Exhibit NEC-JH_64 at 4-25

/

(emphasis added).

Entergy and the NRC Staff are wrong in arguing that Entergy must strictly follow the provisions of Section XM. 1 of the GALL report and use the NUREG/CR-6583 and NUREG/CR-5704 methodology ("ANL 1998 Equations") to calculate Fen in spite of the fact that new information in NUREG/CR-6909, Exhibit NEC-JH_26, conclusively demonstrates that the ANL 1998 Equations only partially account for the effect of LWR environments.

NUREG/CR-6909 describes in detail the many factors known to affect fatigue life that are not included in either the ANL 1998 Equations or the ANL 2007 Equations included in NUREG/CR-6909. A summary of the most significant of these factors is contained in the following Table 1. In my opinion, to comply with the ASME Code, Entergy must account for these known effects. As further discussed below, I believe it should do so by using bounding Fen values contained in NUREG/CR-6909.

Table 1- Uncertainties in the ANL 1998 and 2007 Fen equations No. Factor NUREG/CR Addressed/ Not Addressed Comments

-6909 Page # by Entergy in Reply to NEC I Data scatter 13, 59 Not addressed Included only in the ASME Code design fatigue curves ( in air only) 2 Surface Finish 14 &34 &35 Addressed (JCF) A52 JCF, A 52, is wrong that the surface finish is accounted in the ASME Code 4

No. Factor NUREG/CR Addressed/ Not Addressed Comments

-6909 Page # by Entergy in Reply to NEC

'design fatigue curves. The Code accounts only for surface finish in air.

The Fen as calculated by the ANL equations does not account for the effects of roughness in water which may not be the same as in air.

3 Size, 62 Not addressed Included in the ASME code design fatigue curves ( in air only) 4 Flow Rate 33 Not addressed Not included in the ASME-Code design fatigue curves 5 Strain rate 12, 38-40, 57 Not addressed Not included in the ASME Code design fatigue curves 6 Heat to Heat 36 Not addressed Not included in the ASME Code design Variation fatigue curves 7 loading 62 Not addressed These effects are also discussed by Dr.

history, mean Chopra at the ACRS hearing of Dec. 6, stress 2006, Exhibit NEC-JH-27 at 22.

8' Cyclic strain 13 Not addressed Not included in the ASME Code design hardening fatigue curves.

9 Temperature. 28 Not addressed At the December 6, 2006 ACRS hearing, below 150 C Dr. Chopra stated that a decrease by a factor of two on life is possible. Exhibit NEC-JH-27 at 25.

10 Oxygen Not addressed " During reactor startups and shut downs below 250 C the oxygen concentration increases by more than an order of magnitude in comparison to normal operating conditions as shown by EPRI. Exhibit NEC-JH_65 at 53. Entergy calculations are based on concentrations during normal operating conditions, which at VY varied between 123 and 31 ppm depending on period of operation and reactor location. Exhibit NEC-JH 06 at A2. Allowing for data scatter in the above oxygen concentrations, an increase by a factor of four in oxygen

/ would increase the Fen by a factor of 55 5

No. Factor NUREG/CR Addressed/ Not Addressed Comments

-6909 Page # by Entergy in Reply to NEC in comparison to the steady state values.

11 Trace 30-31 Not addressed impurities in Wvater 12 Sulfide 13 Not addressed At low strain rate, variation morphology Morphology could result in an order of magnitude variation on life.

13. Existing Not addressed Existing fatigue cracks in the cladding or Surface cracks base metal can provide sites for accelerated corrosion and thereby accelerate fatigue failure under cycling loads.

NRC witness Mr. Fair testifies at A5 that the NRC does not require license renewal applicants to use the results of NUREG/CR-6909, Exhibit NEC-JH_26, because those results were not completed when the GALL guidelines were issued. The fact that the 8-year-old Section XM. 1 specifications are silent about most of the required adjustments to the Fen equations because the NUREG/CR-6909 data was not available when the GALL report was published does not excuse Entergy from properly accounting for environmental effects. Mr. Fair does not V

ekplain how a methodology that ignores the factors that are not included in the ANL 1998 Equations but discussed in NUREG/CR-6909 can be in agreement with the ASME Code.

The NRC's acceptance of Entergy's CUFen values is not proof that 'Entergy is in compliance'with the ASME code. It is also not proof that Entergy complies with 10 CFR 54.21 (C), which requires a demonstration that components will operate safely in the reactor environment.

6

Q6. Do you agree-that the ANL 1998 Equations contained in NUREG/CR-6583 and NUREG/CR-5704 are more conservative and will generally yield higher Fen multipliers for currently operating plants than the ANL 2007 Equations contained in NUREG/CR-6909?

A6. No - the ANL 2007 Equations will yield higher Fen multipliers in some cases, and lower Fen multipliers in other cases. -See, Exhibit NEC -JH_26 at 38. NRC witness Mr. Fair incorrectly told the ACRS that the ANL 1998 equations result in higher Fens than the ANL 2007 equations. See, Exhibit NEC-JH_28 at 97., In the light of such blatant distortion by the NRC staff, one cannot expect decision makers such'as the ACRS to understand the degree of uncertainty in Entergy's methodology.

When both the Entergy and NRC Staff witnesses allege that the NUREG/CR-6583 and NUREG/CR-5704 "procedure" is more conservative (Fair A5 and A6, Stevens A50), I believe they are referring to the fact that NUREG/CR-6909 contains new air fatigue curves that are less conservative than the current ASME Code fatigue curves. I have never recommended use of these new air fatigue curves. Until (the current fatigue curves in the Code are officially modified, these curves must be considered the "best representation of fatigue life in air" and must be adhered to.

Most importantly, and I want-to make this very clear, Entergy's and the NRC's Staff's discussion of the alleged greater conservatism of the NUREG/CR-6583 and NUREG/CR-5704 equations and ','procedure" are totally irrelevant to my main point about how Entergy should have used information contained in NUREG/CR-6909 in its CUFen analyses.

Q7. What is your main point regarding the significance of NUREG/CR-6909? What, information contained in this document should Entergy have used in its CUFen Analyses?

7

A7. As I have discussed in A5, above, NUREG/CR-6909 &escribes in detail the many factors known toaffect fatigue life that are not included in either the ANL 1998 Equations or the ANL 2007 Equations. These factors do not exist in the laboratory environment but are important .and known to be present in the reactor environment. This i's the relevant information Entergy should have taken from NUREG/CR-6909.

My main point is that, given the current state of the technology, it simply is not possible to calculate Fen multipliers that are precision-adjusted to plant conditions, as Entergy purports to have done. Given the many uncertainties in the calculation of Fen, I recommend use of bounding values contained in NUREG/CR-6909 - 12 for austenitic stainless steel and 17 for carbon and low alloy steel.

Q8. Please further 'explain why you used a Fen of 12 for austenitic stainless steel and a Fen of 17 for carbon and low alloy steel in the CUFen recalculation stated in your report, Exhibit NEC-JH_03 at 19-20.

A8. As discussed in NUREG/CR-6909, these values are based on a review of laboratory data from 41 sources. The reason for favoring the bounding numbers over the use of the ANL equations is that the bounding values factor in a much wider range of parameters than the ANL equations, such as fatigue loadings' data acquisition and material variability.

Q9. Do you agree with NRC witness Mr. Chang that Fen values of 12 for austenitic stainless 17 for carbon and low alloy steel represent a "worst case scenario," or that application of these values is unreasonably conservative?

A9. No. The factors 12 and 17 may in fact represent the best-case scenario after all the uncertainties outlined in Table 1 are considered. In addition, application of Fen values of 12 and 17 in the VY environment is not overly conservative because these values do not account for the 8

presence of cracks in the cladding and base metal of the feedwater nozzles, or for high oxygen concentrations during transients.

J I also note that if the ASME Code design fatigue curves are conservative as some believe, including ANL, any lack of conservatism in the above Fen values may be compensatedby the ASME curves. If on the other hand the ASME Code curves are not conservative, as other researchers believe, See, Exhibit NEC-JH_26 at 71, then the Fen factors 12 and 17 will have to be adjusted upwards.

Q10. Do you agree with Entergy witness Mr. Stevens that Fen=17 applies only to high oxygen and temperature environments that do not exist at VYNPS, in part because the plant has operated usinghydrogen water chemistry since 2003?

A10. No. I do not agree that the factor 17 is restricted to high temperature and high oxygen environments. This factor is specified in NUREG/CR-6909 at 3 as applicable to "certain reactor operating conditions." NUREG/CR-6909 does not indicate that the factor of 17 is restricted only to high oxygen and high temperatures. Mr. Stevens provided no reference for his assertion that Fen=l 7 applies only to high oxygen and temperature environments for carbon and low-alloy steels.

I do not agree that either Fen= 12 for austenitic stainless or Fen= 17 for carbon and low alloy steel would apply only in extreme environments. For example, my reference 3 to this testimony is a paper by Garry Wire and-William Mills, reporting a factor of 12 for 304 stainless steel in 288 degrees C and 20ppb oxygen concentrations. Exhibit NEC-JH_66 at 318. This temperature is typical of BWR operations and the 20 ppb is considerably below the VY oxygen concentrations. It is definitely not an extreme environment as claimed by Entergy. Wire and Mills report that "[c]rack growth rates of 304 SS in water were about 12 times the air rate." Id. I 9

did not research the literature to find the exact conditions that correspond to the factor 17. 1 believe that this factor was provided by ANL as a general bounding number.

Even if Fen= 17 did apply only to high oxygen environments, I would not agree that this factor should not be used at VY due to the 2003 switch to Hydrogen water chemistry. First, because Entergy switched to Hydrogen chemistry relatively recently, calculations must still be conducted for the higher oxygen concentrations. Second, as discussed below, Entergy does not know what the actual oxygen concentration is during transients at the surface of a given component and therefore an adequately conservative analysis must assume that this concentration is high.

Qll. Entergy and the NRC Staff argue that NUREG/CR-6909 does not recommend use of the bounding Fen values you used in your CUFen recalculation. How do you respond?

All. Di. Chopra, author of NUREG/CR-6909, understands the limitations of the Fen Imethodology very well, but he can only describe the "state of the art." He is not in a position to recommend or not recommend use of bounding Fen values. It is up to the user to assess his specific conditions and make the appropriate corrections to the ANL equations. Entergy has not done so. It selected a procedure that would produce CUFens less than unity. /

Q12. Do you agree that any lack of conservatism in Fen values calculated by the ANL 1998 Equations is counterbalanced by excess conservatism in the ASME Code design fatigue curves?

A12. No. The Fen issue must be kept separate from.the ASME Code design fatigue curve issue. One is not justified to use an arbitrary number for the Fen because one believes that the Code is conservative. There'is no general agreement among researchers that the current Code is conservative. Until the current fatigue curves in the Code are officially modified, these curves must be considered the "best representation of fatigue life in air" and must be adhered to.

10

Entergy's and the NRC's opinions regarding the ASME code are irrelevant. Entergy and the NRC should not be allowed to create their own rules concerning how to adjust the ASME code, which in essence is exactly what they are doing by using a non-conservative Fen in the hope that this will be compensated by a perceived conservatismo in the existing ASME fatigue curves. If all the users of the ASME Code were to follow Entergy's example it would render the ASME Code useless. /

C Q13. Do you agree with Entergy witness Mr. Fitzpatrick that Entergy's CUFen analyses properly accounted for surface roughness effects through use of ASME Code design fatigue curves that include a "safety factor" to account for these effects.?

A13. No. The ASME Code incorporates a factor-of about four on surface finish-to account for different fabrication processes (on the order of 0.5 mils). Surfaces exposed to the LWR environment are subject to corrosion, erosion and pitting, exhibiting a combination of smooth surfaces, ridges and holes of various sizes, making it difficult to compare such surfaces to machined surfaces. Until data show that the corroded surfaces and machined surfaces equally affect fatigue, possible differences cannot be ignored because surface holes and grooves may provide sites for accelerated corrosion attack; the corrosion reactions could then accelerate crack growth under cyclic loads. Mr. Fitzpatrick did not provide any support for his statement that the ASME Code design fatigue curves already incorporate the relevant surface roughness.

Mr Fitzpatrick is also wrong in representing at several points in his testimony that the ASME Code includes safety factors for environmental effects. As discussed in NUREG/CR-6909 at 3, surface finish, size and scatter are adjustments, not safetyrmargins.

Q14. Do you agree with Entergy witness Mr. Fitzpatrick that Entergy used bounding values for oxygen as an input to the ANL equations in all its CUFen analyses?

11

A14. No. First, Mr. Fitzpatrick is referring to steady state value as determined by a computer code called BWRVIA that Entergy has neither described nor provided to NEC. Second, Mr.

Fitzpatrick completely ignores the high oxygen concentrations that occur during transients. See, Exhibit NEC-JH_65 at 52-53. To the best of my knowledge, there is no technology that can predict the oxygen concentration at a given surface during reactor transients. Furthermore, no analysis has been presented to show how such temporary high oxygen concentrations affect the Fen. Mr. Fitzpatrick also stated that the BWRVIA has been calibrated-in steam under unspecified conditions that he'did not describe. Such calibration does not address the oxygen concentrations in water during transients.

Q15. Was it appropriate for Entergy's Fen calculations to exclude any correction for cracking in the cladding and base metal of the feedwater nozzles based on results of Entergy's 2007inspection of these nozzles for cracks in the base metal?

A15. No. Entergy stated in RAI 4.3-H-02 that the feedwater nozzle cladding may contain cracks and that such cracks could grow into the base metal. NRC Staff Exhibit 1 at 4 4-27.

Entergy's 2007 inspection report stated that "No relevant information was recorded". Exhibit 2-33 at 4. Without stating the probability of detecting cracks at the clad metal interface and defining "relevant," the inspection results are useless. Even if thedcad cracks have not yet penetrated the base metal, the interface between the clad'and the base metal is a site for crack initiation where corrosion products can accumulate. Such surface cracks when discovered in pressure systems are usually ground out to prevent fast crack growth under cycling loads. The ANL equations were not corrected for the presence of known surface cracks even if they did not yet penetrate the base metal.

Bli B. Enter*-y's Calculation of 60-Year CUFs in Air 12

Q16. You have testified that Entergy's CUFen analyses improperly applied a heat transfer equation that applies only to a fully developed turbulent flow to the VYNPS nozzles where flow most likely is not fully developed. Entergy witness Mr. Steven's has testified (A 54) that flow in the feedwater nozzle is fully developed because the upstream horizontal pipe is 48 inches long. How do you respond?

A16. Both the local distribution and the absolute rate of the heat transfer to or from thewalls of the pipes affect fatigue loading. The CUF results are very sensitive to the heat transfer coefficients. See, Exhibit NEC- JH_15.

Mr. Stevens is wrong in stating (A 54) that the flow in the feedwater nozzle is fully, developed because the upstream horizontal pipe is 48 inches long. Since the inside diameter of the nozzle is 9.7 inches, the L/D is approximately 5, which is not sufficient to estabiish a fully developed flow. See, Exhibit NEC- JH_29. About 30 to 60 diameters, depending on the Reynold's number, are required to establish a fully developed flow through the nozzle. Mr.

Stevens did not provide the straight section lengths upstream of the recirculation and spray nozzles. If that length is also on the order of 48 inches the flow in these nozzles will not befully developed because the diameter of these nozzles is larger than the diameter of the feedwater nozzle. Because the flow in the'nozzles is not fully developed, variation in the heat transfer coefficient both axially and circumferentially can be expected. Data on wall thinning in the upstream sections of the straight pipe where the flow is not fully developed is also required because it may affect the velocity distribution in the nozzle.

In transients where the flow stops and heat transfer occurs by natural convection, Mr.

Stevens did not answer the question why a correction was not made for circumferential variation of the heat transfer both during single phase flow and during condensation. It appears that Mr.

13

Stevens does not understand the issue because he refers to axial variations and not variations in the vertical direction that is inherent in natural convection flows.

Mr. Stevens' statement that Equation,( 3 ) is "bounding" is meaningless without any further explanation.

Q17. You have testified that Entergy improperly failed to .correct a heat transfer equation used in its CUFen Reanalyses by the ratio of the viscosities evaluated at the bulk and wall temperatures during each transient. Entergy witness Mr. Stevens states that this correction is unnecessary when there are minimal differences in temperature between the pipe wall and the bulk of the fluid. How do you respond?

A17. Mr. Stevens is correct that when there are minimal differences in temperature between the pipe wall and the bulk of the fluid, variations in viscosity can be neglected. However, Mr.

Stevens did not quantify actual temperature differences. A difference of 100 degrees F would affect the heat transfer coefficient by about 4%. The actual effect can only be determined from data on wall and bulk fluid temperature histories for sample transients. Such information was not provided.

Q18. You have testified that Entergy's reports of its CUFen Reanalyses do not include, and Entergy did not produce to NEC, drawings of plant piping from which you could obtain information necessary to validate Entergy's assumption of uniform heat transfer distribution. Entergy notes that it'supplied NEC With 36 drawings. How do you respond?

A18. Exhibit NEC-JH-25 is illustrative of the "piping diagrams"; Entergy produced. It would be virtually impossible to extract information necessary to determine the flow conditions from*

such sketches - for instance, orientation angles, weld location and internal diameters as they exist today.

Q19. ' You have testified that Entergy's reports of its CUFen Reanalyses do not include, and Entergy did not produce to NEC, a complete description of the methods or models used to determine velocities and temperatures during transients. Entergy represents that 14

this information was conveyed to NEC through counsel on April 14, 2008. How do you, respond?

A19. I do not agree that information sufficient to validate Entergy's analysis either appears in Entergy's reports of its analyses or was conveyed on April 14, 2008. Tor calculate flow velocity, Entergy advised on April 14, 2008 that I should take the flow rates (of unknown accuracy) and divide them by flow area. It failed to indicate how one does this when the flow is zero. At the January 2008 public meeting between Entergy and the NRC Staff, Entergy's Counsel specifically instructed Entergy representatives not to answer any of my questions regarding the above issues. NEC requested information about the methods that were used to calculate temperatures during the transients, but Entergy did not supply that information, contrary to what is claimed in Entergy's Initial Statement of Position at 36.

I believe that Entergy's strategy in this and, other. proceedings has been to withhold the information necessary to support a thorough assessment of its analyses by intervenors. Notably, Entergy has now taken the position in the ASLB proceeding concerning Entergy's License Renewal Application for the Indian Point plant that it is not required to provide a information about its CUFen analyses for the NUREG/CR-6260 locations until after the close of the ASLB proceeding. Exhibit NEC-JH_67 at Attachment 1, Enclosure 2, (see discussion of D-RAI 4.3.1.8-1 and D-RAI 4.3.1.8-2). The NRC Staff has apparently acquiesced in Entergy's effort to avoid public scrutiny of its CUFen methodology, and withdrew requests for this information. Id.

Q20. Entergy claims that its use of the simplified Green's Function method in its initial CUFen Reanalysis introduced only a small error. Do you agree?

A20. No. Unlessihe analyst can explain the physical reasons for discrepancies between results obtained by the Green's Function methodology and the more exact methodology, classic NB-,

15

3200 analysis, the results of the Green's Function methodology will incorporate unquantified uncertainties. At the'January 2008 meeting between Entergy and the NRC Staff, Entergy was not able to. explain such differences, and Entergy witness Mr. Stevens has now testified atA58 that

"[t]he reason for this difference was not specifically investigated:'

After arguing for months that the analysis with Green's Function produces conservative results, i.e. large CUFen values, Entergy agreed to prove this by using the classical NB-3200 analysis without Green's Function. The demonstration showed that the CUFen was 0.35341, seemingly confirming that the use of Green's Function produces conservative results because this value is smaller than 0.6392 (the value Entergy calculated with the Green's Function). See, Exhibit NEC-JH_03 at 6. This result, however, was obtained by lowering the Fen to 3.97 instead of keeping it at the 10.05 level for a valid comparison. When the correct value of Fen was used, 10.05, Entergy obtained a CUFen of 0.8930, which is substantially greater than 0.63 92 (obtained with the Green's Function). Thus the u'se of the Green's Function may generate non-conservative results. My report, Exhibit NEC-JH_03 at 6, includes a table of the four different CUFen values Entergy has calculated for the feedwater nozzle. It is interesting to note that Entergy does not explain why an internal Entergy audit did not discover that the analyst was using incorrect Fen numbers before the NRC audit discovered that this was the case.

Q21. Has Entergy fully explained how it determined the number of plant transients, or provided information from which you could conclude that Entergy assumed a conservative number of transient cycles?

A21. No. Entergy has provided inconsistent and vague information regarding how it determined the number of transient cycles, and has not indicated that it made any allowance for the likely increase in plant transients resulting from the 20 percent power uprate or the fact that 16

the number of plant transients is likely to increase as a plant ages. NRC Staff witness Mr. Chang has testified at A 10 that "the staff cannot determine the level of conservatism regarding the number of transient cycles at this time."

Based on the documentation provided to NEC, Entergy determinedthe number of transients, N,. for the total 60-year reactor life by counting the number of transients that the plant has experienced up to a'certain date, n, and adjusting this number proportionally i.e. N= n x 60/t, where t is the number of years as of the above date. This procedure is described in License Renewal Application Table 4.3-2, Note 2; and Exhibit NEC-JH_ 8 at 3-18, Table 3-10, Note 2.

Both of these documents state that CUF results are based on "actual cycles to date and projected to 60 years." Table 4.3-2 defines the projection as a linear extrapolation.

Entergy witness Mr. Fitzpatrick has testified at A55 that the procedure described in the License Renewal Application and in Exhibit NEC-JH_18 actually was not followed; instead the following was done:

VY projections for 60 years were made based on all ,available sources, including the numbers of cycles for 40 years in the VY reactor pressure vessel Design Specification, the numbers of cycles actually analyzed in the VY Design Stress Report, and the numbers of cycles experienced by VY after approximately 35 years of, operation (July 2007).

The above method of determining the number of cycles appears to be different from what was

- described in Tables 3-10 and 4.3.2, which are referenced above. In any event, the above description is too vague to allow one to determine how the number of transients was actually calculated. Mr. Fitzpatrick did not provide a reference that would explain how the above procedure was implemented.

17

Q22. You used the CUF values Entergy originally provided in its License Renewal Application in the CUFen recalculation stated in your report, Exhibit NEC-JH_03 at 19-20.

Why did you use these values?

A22. Due to the many uncertaiInties and errors in Entergy's calculation of plant-specific 60-year CUFs discussed in this rebuttal testimony and in my direct testimony and report, Exhibit NEC-JH_03, I used the more conservative design basis CUFs which were produced by Entergy in Table 4.3-3 of the LRA.

C. Error Analysis Q23. Entergy contends that it was not necessary to perform an error analysis to validate its analytical techniques because the stress analysis is based on bounding values. How do you respond?

A23. Because the level of uncertainty in Entergy's analysis is very high and the amount of valid data is meager, properly identified assumptions and a competent assessment of their relative effects on the CUFens is paramount. Entergy considered such an approach unnecessary and apparently found it sufficient to label their assumptions "bounding." Without quantifying b'y how much the various parameters are "bounding," Entergy's statement is meaningless. It has already been demonstrated that the heat transfer coefficients and the Fen factors are not bounding the'results conservatively.

Q24. NRC Staff witness Mr. Chang contends that an error analysis was unnecessary because of conservatism built into the ASME Code and the ANL 1998 Equations, which he claims "have been adjusted for uncertainties in life." How do you respond?

A24. As I have discussed in A 12 of this testimony, there is no agreement among researchers that the ASME Code design fatigue curves are conservative. With respect to the ANL 1998 Equations, Mr. Chang does not explain how adjustments were made for the factors listed in the Table I included in A5 of this testimony. Ten years of data and research have been accumulated 18

since the ANL 1998 Equations were published; Mr. Chang does not explain why the license renewal process should ignore this data.

Q25. You have stated that Entergy's CUFen Reanalyses should be reviewed by an independent third party. Why do you make this recommendation? /

A25. In addition to the uncertainties in heat transfer coefficients, Green's Function and the number of transients used in the analysis, there are many other uncertainties that are not possible to assess: The results of the stress analysis largely depend on the judgment of the analyst because he alone decides where the maximum stress points are and how to link transient pairs.

The changes that were made in the Fen, discussed in A20 of this testimony, which resulted in an erroneously low CUFen is an example of how the analyst can affect the results. In the absence of an independent review by an unbiased third party without financial ties to Entergy, Entergy's 60-year CUF calculations are of questionable validity.

D. References Q26. Please list any references to this testimony that were not filed as Exhibits to your direct testimony.

A26.

1. Materials Reliability Program: Guidelines For Addressing Env'ironmental Fatigue License Effects in License Renewal Applications, EPRI- MPR-47 Rev. 1, September, 2005. Exhibit NEC-JH_64.

2. R&D Status Report, EPRI Journal, Jan/Feb 1983. Exhibit NEC-JH_65.

3. Gary L. Wire and William J. Mills, "Fatigue Crack Propagation Rates for Notched 304 Stainless Steel Specimen in Elevate Temperature,", Journal of Vessel Pressure Technology. Exhibit NEC-JH_66.

4. New York State's Supplemental Citation In Support of Admission of Contention 26A, Docket Nos. 50-247-LR and 50-286-LR (May 22, 2008), and the attached NRC May 8, 2008 Summary of an April 3, 2008 Telephone Conference Between Entergy and NRC Staff. Exhibit NEC-JH_67.

19

Q27. Does this conclude yourrebuttal testimony regarding NEC's Contentions 2A and 2B?

A27'. Yes.

II. NEC CONTENTION 3 (steam dryer aging management program)

Q28. Please summarize your disagreement with Entergy regarding the validity of its steam dryer aging management program.

A28. My position regarding the steam dryer at VY is simple: I disagree with Entergy that an.

aging management plan that consists solely of plant parameter monitoring and partial visual inspection, uninformed by knowledge of dryer loading, complies with the General Design Criteria insofar as they require that protection must be provided against the dynamic effects of loss of coolant accidents ("LOCAs").

Entergy's strategy is based on monitoring moisture carryover, steam, flow, water level and dome pressure and periodic visual inspections. Entergy witness Mr. Hoffman was asked in Q33 whether these activities "enable Entergy to determine whether a dryer crack is about to form?" He responded in A33 that they do not. Of course no one can predict the exact time for transition from crack initiation to crack propagation. The question that was asked of Mr.

Hoffman is almost irrelevant. The questions that should have been asked are as follows: (a) are all of the above precautionary measures- sufficient to ensure that the probability of the formation of loose parts under DBA loads will be very low?; and (b) is Entergy taking all practical measures to minimize the probability of such failures? As discussed in my report submitted to the ASLB on April 28, 2008, Exhibit NEC-JH_54' the answer to both of these questions is no.

20

Entergy's witnesses, Mr. Hoffman and Mr. Lukens, described in detail various procedures of steam dryer inspection and the operational experience with the dryer, but they either dismissed or did not address properly the above two issues. The ability to estimate the probability of formation of loose parts requires knowledge of the cyclic loads on the dryer to ensure that the dryer ,is not subjected to cyclic stress that would exceed the endurance limit. In A56-62 of their testimony, Mr Hoffman and Mr. Lukens discuss this key issue and state that the prediction of cyclic stresses on the dryer is not required because there are no specific regulatory requirements to do so, and the inspection pro'rams at VY ensure that the dryer will not fail. Mr.

Hoffman and Mr. Lukens did not provide even a single quantitative assessment in support of these opinions.

I agree that there is no regulatory requirement to estimate dryer stresses. However, the fact that dryers at other plants have failed following power uprates, the fact that this was a surprise to General Electric ("GE"), the fact that even small pressure fluctuations can give rise to stresses that exceed the endurance limit and the fact that the formation of loose parts can lead to major safety problems are all factors that must be considered even though there are no specific NRC requirements to calculate stresses on the dryer.

Q29. Entergy witness Mr. Lukens testified at A56 that "operating experience after the EPU (exemplified by the data collected during the 2007 inspection and the subsequent year of monitoring of plant operating parameters) demonstrates that the stresses experienced by the dryer are insufficient to initiate and propagate fatigue cracks." How do you respond?

A29. Mr. Lukens is wrong that the inspection data he mentions is a measure of cyclic stresses.

The only way of determining stresses on the dryer is to actually measure them. Fatigue cracking is a time-dependent phenomenon; the fact that cracks have not developed after a short period of time proves nothing. General Electric ("GE"), which conducted both the RF026 and the 2007 steam dryer inspections at VY, did not exclude the possibility of crack growth by fatigue. GE 21

stated: "The dryer unit end plates -arelocated in the dryer interior and are not subjected to any direct main steam line acoustic loading. However, continued growth by fatig ue cannot be ruled out." Exhibit NEC-JH_68 at "Evaluation of Steam Dryer Indications" attachment (emphasis added).

Q30. Mr. Lukens at A57 denied that GE made the statement that "continued growth by fatigue cannot be ruled out," and testified that the reference you cited for this statement, Exhibit NEC-JH_59, did not contain it. How do you respond?

.A30. Mr. Lukens misread my statement, which referred to GE's observations following the RF026 inspection. Due to a clerical error, Exhibit NEC-JH_59 included only part of the GE report; the full GE report is now provided as an Exhibit to this testimony. See, Exhibit NEC-JH_68. In any event, Mr. Lukens is the engineer responsible for the inspection of the dryer at VY; he should have been of aware of GE's conclusions, which are very material to the results of the inspection.

Q31. Mr. Lukens testified at A58 that all IGSCC cracks identified in the VY steam dryer to date are inactive. How do you respond?

A31. In stating that the IGSCC cracks are not active, Mr. Lukens essentially dismissed the possibility of continued growth of cracks by fatigue. He apparently did not recognize that IGSCC can provide sites for corrosion -attack which would in turn accelerate crack growth under cycling loading. The rate of crack propagation would depend on load intensities and duration.

/

Moreover, I cannot' agree with Mr. Lukens that the inspection photographs provided in Entergy's Condition Report, Exhibit NEC-JH_59 at 2-8, show that the cracks are inactive. Metallographic examinations would be required to demonstrate this, not remote camera photos.

Q32. Mr. Hoffman testifies at A59 that design basis loads ("DBA") cannot cause dryer failure. How do you respond?

22

A32. I disagree. If the dryer has been sufficiently weakened by cracks, there is no reason to believe that DBA loads could not fracture the dryer. Instead of making speculative statements, Mr. Hoffman should have provided calculations showing that even if some parts of the dryer had long and deep cracks, those parts would withstand DBA loads.

Q33. Mr. Hoffman testifies at A61 and A62 that it is not necessary to estimate and predict dryer stresses because "[c]onfirmation that stresses on the VY steam dryer remain within fatigue limits is provided daily by the fact that the dryer has been able to withstand without damage the increased loads imparted on it during power ascension and for the two years of operation since EPU was implemented." Do you agree?

A33. No, I do not agree that it is not necessary to estimate stresses because the dryer has thus far withstood the increase in steam velocities followed ihe uprate. Vibration fatigue is a time-related phenomenon; the fact that the dryer has not failed to date is not at all an indication that it will not fail in the future. Mr. Hoffman is speculating that the loads on the dryer cannot change.

Even a small increase in steam velocity can bring vortex shedding frequency closer to the natural frequency of the dryer, thereby inducing resonance vibrations and increasing the loads on the dryer.

Q34. Mr. Hoffman testified at A63 that the analytical tools used to estimate stress loads on the steam dryer during the power ascension phase of EPU implementation demonstrated that loads on the dryer would be below the endurance limit. Do you agree?

A34. No. Mr. Hoffman stated at A63 that the analytical tools demonstrated that the loads on

• thedryer would be acceptable. The analytical tools were based on small-scale experiments, small-scale tests (ACM) and questionable scaling laws, as was pointed out by the ACRS. See, Transcriptof Proceedings,NRC Advisory Committee on Reactor Safeguards, 5 2 8 1h Meeting (December 7, 2005) at 9, 12-14, 25, 29, 60.

Q35. Has Entergy provided information sufficient to demonstrate the validity of its steam dryer aging management program?

23

A35. No. Mr. Hoffman and Mr. Lukens at A21-A53 provided a very lengthy and detailed

'description of the inspection techniques and parameter monitoring at VY. Even though the entire dryer is not accessible to visual inspection, Mr. Hoffman and Mr. Lukens did'not provide a quantitative estimate of the probability of crack detection, POD. They should have provided this information.

/

Q36. Do you have any further comments regarding NEC'; Contention 3?

A36. 'Yes. Entergy provided an opinion that the dryer will not be the source of loose parts that could present a safety risk during normal operations and during design basis accidents. Entergy believes that the formation of cracks from flow-induced vibrations can be detected in time by periodic visual inspections and plant parameter monitoring; I do not share this opinion. Rather I am more inclined to agree with the researchers from the Pacific Northwest National Laboratory:

"Unlike the previously discussed mechanisms (corrosion). vibration fatigue does not lend itself to periodic in-service examinations (volumetric, surface, etc) as a means of managing this degradation mechanism." The main reason for this is: "Once a crack initiates failure quickly follows." Fredric A. Simonen and Stephen R. Gosselin, "Life Prediction and Monitoring of Nuclear Power Plant<Components for Service-Related Degradation" J. of Pressure Vessel Technology V. 123, Feb. 2001, P, 62., Exhibit NEC-JH_69 at 62.

'Q37. Please list any references to this testimony that were not filed as Exhibits to your direct testimony.

A37.

1. Efitergy Condition Report, CR-VTY-2007-02133, including all attachments.

Exhibit NEC-JH 68.

24

2. Fredric A. Simonen and Stephen R. Gosselin, "Life Prediction and Monitoring of Nuclear Power Plant Components for Service-Related Degradation", J. of Pressure Vessel Technology V. 123, Feb. 2001. Exhibit NEC-JH_69.

Q37. Does thisconclude your rebuttal testimony regarding NEC's Contention 3?

A37. Yes.

III. NEC CONTENTION 4

/

(flow-accelerated corrosion management plan)

Q38. In response to Entergy's Prefiled Testimony on NEC Contention 4, please summarize your view of Entergy's proposed Aging Management Program (AMP) for Flow Accelerated Corrosion at Vermont Yankee Nuclear,Power Station A38. The NEC position on Flow Accelerated Corrosion, FAC, is that Entergy does not haye a reliable plan to monitor FAC and therefore the public has no assurance that susceptible 'reactor components will be repaired and replaced in time to prevent pipe rupture or major leaks. Such damage to piping must be prevented not only during normal plant operation but also during design basic accidents (DBAs) in accordance with 10 CFR 50.49 (b) (2). The LRA must include

.an adequate plan to monitor FAC pursuant to 10 CFR 54.21 (a) (3).

The reason Entergy's FAC plan as described in the LRA is inadequate is because it is based on EPRI guidelines NSAC-202 L, which largely rely on an unproven computer code called CHECWORKS to predict corrosion rates and therefore the scope of the inspection. I evaluated the NSAC/CHECWORKS methodology and provided the results to the ASLB on April 28, 2008.

Exhibit NEC-JH_36. I concluded that 12-15 years would be required to benchmark CHECWORKS at VY at the uprate conditions and with a smaller inspection grid size. I also recommended a methodology that 'Wouldmore adequately inspect pipes for potential failures from FAC.

25 I"

I pointed out that several factors contribute to the inability of the NSAC/ CHECWORKS methodology to prevent pipe ruptures from unpredicted wall thinning: (a) incorrect local inspection procedures, i.e selection of grid size, (b) unscientific sampling of components, (c) inability to reliably predict corrosion rates between inspections, (d) no online instrumentation to monitor the potential for corrosion, and (e) lack of independent assessment by competent experts.

Q39. In your opinion, does Entergy's prefiled testimony appropriately address the issues raised in your assessment of Entergy's aging management program for FAC?

A39. No. Rather than provide a reply to the NEC and describe scientifically why NEC and Entergy differ regarding the various uncertainties in predicting wall-thinning rates, Entergy produced several documents that stated that CHECWORKS is .a reliable predictive tool.

For instance, Entergy submitted an EPRI document (E4-09), which is no more than a sales brochure; it provided the sale price of CHECWORKS and informed the reader that no plant that acquired CHECWORKS has experienced FAC failures in pipes larger than 2 inches. No comparison was made with the plants and components that were not included in the CHECWORKS program since it was introduced in 1987 and also no explanation was given as to why the pipe size was that significant. This brochure also did not tell the reader that FAC was defined in a manner that would exclude pipe failures from erosion/corrosion, droplet impingement and cavitations erosion.

Entergy's statement that no one was killed in plants that used CHECWORKS, and the fact that pipes larger than 2 inches did not rupture in such plants is certainly not a credible 26

demonstration that the use of CHECWORKS would satisfy 10 CFR 50.49 (b) (2) and 10 CFR 54.21 (a) (3).

Q40. Entergy witness Dr. Horowitz testifies that unanticipated piping failures that have occurred despite the widespread use of CHECWORKS are not an indicator of the relative efficacy of CHECWORKS. Do you agree?

N A40. No, I do not. CHECWORKS is a proprietary product of EPRI and Dr. Horowitz is EPRI's contractor; thus, it is understandable that Dr. Horowitz would zealously defend CHECWORKS. He fails, however, to credibly explain away CHECWORKS' failure to predict I

the hundreds of unanticipated FAC-related failures that occurred in PWRs and BWRs. Dr.

Horowitz testified (A52) that the problem was not with CHECWORKS and its predecessor J

programs, but rather the unpredicted failures occurred because of (a) improper use of CHECWORKS, (b) exclusion of components from the program, (c) modeling errors, (d) improper inspection, (e) poor communication, and (f) failures from erosion rather than FAC (A46). The fact that many components were not included in the CHECWORKS programs and that Dr. Horowitz selected a very narrow definition of FAC, or that CHECWORKS is susceptible to improper use provides no assurance to the public that pipe failures from wall thinning will be prevented and people and property will not be at risk. Even if, for the sake of argument, CHECWORKS has the potential to predict wall thinning with extreme accuracy but, as Dr.

Horowitz says, many components may be excluded from the program, and CHECWORKS is prone to user's errors, then CHECWORKS cannot be considered a reliable predictive FAC tool for purposes of assuring public health and safety. Dr Horowitz failed to state what percentage of the total susceptible area in a given plant is included in the CHECWORKS program during a typical outage.

.,J 27

Q41. Do you agree with Entergy's position regarding the effect of flow velocity on FAC?

A41. No, I do not. NEC's presentation of how FAC rates vary with flow velocity is significantly different from Entergy's. NEC's position is based on data from tests that were conducted by the Central Electricity Research Laboratories at Leatherhead. The data was discussed and presented on pages 4 and 20 of Exhibit NEC-JH_36, showing the dependence of measured corrosion rates on the mass transfer coefficient for carbon and mild steel. The dependence of the mass transfer coefficient on velocity was discussed in NEC-JH-_36 at 4. Also, the relation between corrosion and material composition was discussed on, pages 4 and 21.

Copper was not included in this discussion since it is not a common piping material in nuclear plants.

'According to Entergy's witness Dr. Horowitz, the data in CHECWORKS is based on references given in E-4-22 and E-4-23. The first paper presented data on the local variation of the mass transfer with velocity and the second paper presented data on the dependence of the corrosion rate of copper with the velocity in flowing hydrofluoric acid. These papers hardly support Entergy's position that the corrosion rate corresponds very weakly with the velocity and therefore the velocity change due to the power uprate is of no significance. Dr. Horowitz did not demonstrate that the mechanism of copper dissolution in acids is the same as the dissolution of iron in the LWR environment.

It is beyond NEC's scope to conduct an uncertainty study on the impact of the various assumptions that were incorporated in CHECWORKS.

As discussed in my assessment of Entergy's FAC program, Exhibit NEC-JH_36, the NRC has developed specific guidelines for how computer codes that are used for licensing bases 28

should be qualified. There is no indication that CHECWORKS has been thoroughly reviewed by the NRC or by a third party with no financial interest in the outcome of the review.

Dr. Horowitz provided no data that shows a comparison between CHECWORKS predictions and VY plant data prior to the power uprate. He stated-that 4.5 years will be sufficient to assure that CHECWORKS will predict FAC reliably at the 20% power uprate. Dr.

Horowitz provided no support whatsoever to this statement.

Q42. In your opinion, has Entergy satisfactorily addressed the major variables affecting the rates at which pipe thinning may occur?

A42. No, Entergy has failed to.either take into account numerous physical phenomena affecting FAC, or to credibly explain why these well-knovn physical phenomena should not be considered in aging management of plant piping.,

For example, despite overwhelming evidence to the contrary, Dr Horowitz denies that FAC is fundamentally a local phenomenon due to the variations of local turbulence in. curved pipes, nozzles,'tees, orifices, etc. See, Exhibits NEC -JH_53 at 48, 65 and NEC-JH_40 (It is common knowledge, for example, that the wall thinning on the extrados of elbows is considerably higher than on the intrados).

Further, Entergy's witness also denied (A47) that FAC varies with time and supported his claim with inadequate laboratory data because the test period was relatively very short. Data from longer tests, but still relatively short compared to plant life, show that corrosion rates generally vary with time. See, Exhibit'NEC-JH_53 at 58.

These factors are important because they determine the scope of the FAC inspection program. Dr., Horowitz found it sufficient to dismiss these issues by summarily stating without 29

supporting documentation (A42) that analytical work done by the industry and NSAC/CHECWORKS guidelines are adequate and sufficient and therefore a more thorough inspection with denser grids as discussed in my report, NEC-JH_36 at 15, is not required.

Q43. In your opinion, are there other factors affecting the prediction of pipe thinning that Entergy should have considered and yet failed to discuss?

A43. Yes, Entergy witness Dr. Horowitz did not address in a meaningful manner any of the following factors:

0 How the effects of flow disturbances due to discontinuities, including those that were created by local corrosion, are accounted for in CHECWORKS 0 How variation in local velocities in elbows, tees, orifices and nozzles are accounted for in grid size selection.

N How an empirical code such as'CHECWORKS, which is based on data scatter of

+60% and - 70%, can be considered a reliable predictive tool for corrosion rates.

M What is the scientific basis for component selection for the CHECWORKS program?

0 What fraction of the total FAC-susceptible area is inspected during atypical plant outage?

,K M Why was there no significant reduction in total pipe failures from FAC following the release of CHECWORKS to the industry in mid 1987?

Q44. In considering aging management of piping, should a distinction be drawn between piping failures due to leaks and piping failures due to ruptures?

30

A44. Not really. Apparently to diminish the significance of failures from local corrosion, Dr.

Horowitz makes a distinction (A47) between pipe failures due to leaks and failures from ruptures. It is absurd to make'such a distinction without relating the "rupture" and the "leak," to a particular accident scenario. As an extreme example, under certain accident scenarios the aggregate flow from many small leaks in a pipe can exceed the choked flow from a single ruptured pipe. In any event, the NRC has not yet adopted the "leak before break" scenario. If Dr. Horowitz is trying to justify the use of CHECWORKS because leaks from local corrosion and failures in piping under 2 inches in diameter are less important than ruptures from larger diameter pipes, he should cite the appropriate authorities that reached such conclusions, or he should present the differences between leaks and ruptures in terms of their contribution to the core damage frequency.

Q45. Do you agree with Entergy's witness at A5 that FAC nfay be defined by excluding corrosion where there is m abrasion of the protective oxide layer at A5?

A45. I do not think that this is apractical definition of FAC. This is a very narrow definition of FAC that has been introduced in the last 15 years or so. Prior to that time, FAC was commonly referred to as erosion/corrosion. According to Dr. Horowitz's definition, FAC is defined as a process where there is no abrasion of the protective oxide layer. As discussed in Exhibit NEC-RH_03 at 8 and 9, the shear at the wall as a result of the velocity gradient can, if not destroy, definitely damage the protective oxide film. Therefore, there is no theoretical justification for such a narrowing of definitions., Moreover, there is no practical way to determine whether a given failure was caused'by pure metal dissolution or in combination with oxide layer damage by shear- or cavitations-induced stresses. In areas where there is a large pressure drop, such as in discharge piping from pumps, both cavitations and FAC may cause 31

wall thinning. Since, according to Dr. Horowitz, CHECWORKS is limited to predicting wall thinning by dissolution, only that type of potential pipe failure will be detected.

Dr. Horowitz also implies at A5 that small leaks result from erosion, not from FAC. I don't believe that this has been shown to be the case. The need to prevent wall thinning and piping leaks is dictated by safety considerations and not by selective and narrow definitions.

Other causes of wall thinning (droplet impingement, cavitation, erosion, pitting) should not be excluded from inspection programs because CHECWORKS predictions of wall thinning do not account for such mechanisms.

Q46. At A34, Entergy's witness asserts that there is no need to calibrate CHECWORKS following the power uprate at VY. Did he provide support for this assertion?

A46. No. Dr. Horowitz provides no support for his assertion that there is no need to calibrate CHECWORKS following the power uprate at VY. As I have discussed in my report, Exhibit NEC-JH_36 at 4, the corrosion rate can vary by as much as the velocity to the 6th power.

Q47. At A38, Dr. Horowitz states that NEC is only concerned with CHECWORKS and not with the FAC program at VY. Is that a correct interpretation of NEC's position?

A47. No, it wis not. NEC is conceirned with the FAC program because its validity is based in large part on the use of CHECWORKS, which NEC considers unreliable. The scope of the FAC

\

program, mainly how many components are inspected, what is the grid size, and how often to inspect a given component depend on the ability to predict corrosion rates. Since Entergy identified CHECKWORKS as the only tool that predicts and selects components for inspection, obviously CHECKWORKS is a focus of attention. Entergy never provided any specific information about other tools that are used to detect wall thinning.

32

Q48. At A39, 40 and 41, Dr. Horowitz denies that 10-15 years would be required to calibrate CHECWORKS. Does he provide supporting data? And do you now agree with his position?

A48. Entergy's witness provides absolutely no data to support his position. Paraphrasing the EPRI guidelines NSAC 202L and pointing out that VY has been collecting FAC data since 1989 does not explain how an empirical code, which presumably was calibrated under one set of operating conditions, can reliably predict FAC under different conditions without recalibration.

Dr., Horowitz does not discuss how CHECWORKS meets the NRC requirements for using analytical codes in power plants. Such codes must be assessed and benchmarked against measured plant data. The benchmarking must be valid within the range in which the data was provided. Exhibit NEC-JH_35 at 190 I absolutely disagree with Entergy's witness. FAC in most cases is a slow process; the fact that some selected components have as yet shown no measurable wall thinning as a result of the uprate proves nothing. As pointed out in NEC -JH_36 at 15 and 16, this is the reason why 12 to 15 years would be required to monitor all the susceptible components to establish' confidence in the ability of predicting the scope of FAC inspection during refueling outages.

Contrary to commonly accepted engineering principles, Entergy's witness insists that there is no need to calibrate the code even though plant conditions have changed. Further, even though he does not characterize it as calibration, Dr. Horowitz recognized the need to increase the inspection scope by 50% to account for the power uprate. He did not disclose, however, what fraction of the total FAC-susceptible area in the VY plant the proposed increased monitoring would represent.

33

Q49. At A42, Mr. Fitzpatrick and Dr. Horowitz claim that CHECWORKS and EPRI guidelines and 30 years of research have eliminated the need to increase the scope of FAC inspection as recommended by NEC. Are they correct?

A49. No. Entergy's witnesses failed to point out the hundreds of pipe failures both small and large in the last 30 years, including the Surry accidents. They dismiss many as not relevant because CHECWORKS was either not available or was not properly used. They failed to mention that EPRI guidelines were published before the Surry and-the Trojan accidents. See, Erosion/Corrosion in Nuclear Steam Plant Piping: Causes and Inspection Program Guidelines, EPRI 3944s, April 1985.

Q50. Dr. Horowitz has complained at A39, A40 and A41 of his testimony that failures at San Onofre Unit 3, Millstone and Sequoyah were not included in the 16 years average described in Exhibit NEC-JH_36 at Table 2. How do you respond?

A50. Table 2 was not intended to cover all reactor accidents. It was focused primarily on major and risk-significant components and included both short exposure time and long exposure time failures. Contrary to Dr. Horowitz's statement, Sequoyah was included in Table 2. I agree with him that many more components could have been included in Table 2, however, I doubt that expanding the list would affect the conclusion that more than 15 years can pass before a major FAC-related failure would occur.

Q51., At A44, Dr. Horowitz appears to suggest that the oxygen concentration at VY did not change in 2003. Is he wrong? /

A51. Yes, as shown below he is wrong, and his statements are misleading. See, Exhibit NEC-JH_36 at 15. VY did reduce the oxygen content in the plant in 2003. Exhibit NEC-JH_1 8 at 3.2 states the date when the switch from NWC to HWC was made. Entergy's CUFen calculations at lower oxygen concentrations, which NEC's Contentions 2A and 2B address, were based on that 34

date. Plant data on oxygen concentrations show that, with the exception of the feedwater line, there was a significant, reduction in oxygen in the plant. See, Exhibit NEC-JH_06 at A2.

Furthermore, If Dr. Horowitz restricts his comment to the feedwater line only, he is misrepresenting NEC's position, which clearly indicated that discussion was not restricted to the feedwater line.

Q52. At A45, Dr. Horowitz stated that he does not agree to the following statement you made in your report, Exhibit NEC-JH 36 at 15: "The observation that CHECWORKS can bound plant data between 100-200 mils/year . . . without specifying how each variable separately effects corrosion, does not address the issue of how the corrosion rate at a given location would be affected when the velocity changes by 20% at a* given plant." How do you respond?

Even though the above is a key issue in NEC Contention 4, Dr. Horowitz finds it sufficient to provide a non-specific and non-quantitative reply. He completely ignores the lengthy discussion in my report, Exhibit NEC-JH_36,at 2-6.

Dr. Horowitz merely states at A45:

As discussed above, the correlations built into CHECWORKS are based on laboratdry experiments on modeled geometries, published correlations, and operating data from many nuclear units.

Dr. Horowitz did not provide any correlations, that are used in CHECWORKS. And the data that was published (See, Exhibit NEC-JH_36 at 24) shows clearly that CHECWORKS predictions are not consistent with plant observations.. Moreover, the predictions vary between + 60% and 35

70%. Further, the predictions do not indicate how the local corrosion for a given component would be affected by. changes in velocity.

Dr. Horowitz's reference E4-09 provides only a list of several plants with recent uprates above. 15% and a statement that there were no major piping failures in the above plants. I emphatically do not agree with Entergy's witness that this somehow constitutes a scientific proof that CHECWORKS can predict FAC rates following changes in plant operating conditions.

Again, he has neglected to indicate what fraction of the total piping would be included in the CHECWORKS program.

Q53. At A47, Dr. Horowitz states that you are incorrect that FAC is a non-linear phenomenon. Please respond.

A53. In my report, Exhibit NEC-JH_36 at 4 and 19, I provided an-explanation as to why FAC varies locally and may not be linear. It should also be noted that the time~scale for the nonlinearity was not specified in the model. Since FAC represents a slow process,/the time scale may be on the order of years, not hours.

Dr. Horowitz cites Exhibit E4-19, Figures 7-6, and E-4-08 Figures 3-6 and 3-7. These figures do not support his statement by any stretch of the imagination. As discussed in Exhibit NEC-JH_36 at 5, laboratory data introduce scaling issues and the test duration is limited. The tests in E4-19 are short duration tests (500-2000 hrs). Even if one accepts Dr. Horowitz's argument that 4.5 yearswould be sufficient to benchmark CHECWORKS, the cited tests

/

represent a time period which is only 1-5 % of the total time of interest. The tests were conducted on small mild steel specimens of unknown initial surface finish.

36

The extrapolation of the above results to real components (including plain carbon steel) that have been exposed to the reactor environment for 35 years under a range of operating conditions is ludicrous.

The tests in Figures E4-08, Figures 3-6 and 3-7, were conducted for an even shorter period of time (400-650 hrs ). They were conducted to test the effect of copper ions on corrosion, and provide no information whatsoever on the linearity of FAC. Furthermore the corrosion rates were determined by measuring very small changes in activity of the specimen.

They represent only the average corrosion rate at the surface of the entire specimen. This has nothing to do with the time-dependent phenomena discussed in my report, Exhibit NEC -JH_36 at 4 and 19.

At A47, Dr. Horowitz makes the following statement:

With respect to the allegedly local nature of FAC wear, although local FAC wear is occasionally seen - normally near a geometric discontinuity - such local wear usually results in only minor effects (e_, leaks).; The normal feature of FAC wear - widespread wear over an extended area- is what causes significant problems (e..g the need for pipe replacements or the occurrence of pipe ruptures).

Welds, entrance and exits to and from nozzles, elbows, and surface roughness, as discussed in Exhibit NEC -JH_36 at 4 and 1'9, are all discontinuities. I cannot fathom how Dr. Horowitz can imply that these are not important.

Dr. Horowitz also misinterprets the use of the word local. In the context of this discussion, "local" refers to pipe segments which can vary from a square inch or so to hundreds of square inches. It-also can refer to surface discontinuities.. Surfaces will exhibit a combination of uniform, smooth and rough areas. As already mentioned above, the corrosion in elbows is 37

p\

normally found on the extrados, whether or not it is uniform. The wall thinning is local with respect to the elbow and it can be approximately uniform within a given section of the component. When the corrosion is not linear with time and the corrosion attack can be highly local, it makes prediction of future rates and wall thickness measurements very difficult.

Dr. Horowitz is distracting from this issue by focusing on making distinctions between pipe ruptures and pipe leaks. His characterization of the failure at Surry is completely wrong.

Dr. Horowitz stated at A47: "By contrast, at Surry, there was not localized wall thinning," and "The global nature of the FAC damage is consistent with experience of FAC induced rupture."

Dr Horowitz is contradicted by a TVA, document authored by D. W. Wilson, Project Engineer at Sequoyah. Referring to the Surry accident, Mr. Wilson stated: "The rupture was caused by localized wall thinning at a pipe to elbow weld. The thinning was identified as erosion-corrosion." Exhibit NEC-JH-_70 at 2.

I personally have not conducted a detailed failure analysis, but I did notice the combination of uniform and non-uniform appearance of the elbow surfaces while visiting the Surry plant shortly after the accident in December 1986.

Dr. Horowitz appears to be confusing the nature of wall thinning with' pipe rupture or a pipe leak. Whether a pipe ruptures or develops a small leak would depend on the degree of wall thinning and the nature and intensity of the applied loads. Making a distinction between a pipe rupture or a large leak is rnot important unless one can demonstrate that a given leak will not lead to a catastrophic core melt. The NRC has not yet accepted the. concept of "leak before break."

The three ruptures that Dr. Horowitz described at A47 occurred at normal operating conditions.

A valid FAC program must also protect the pipes from design basis loads. It is apparent to me 38

that Dr. Horowitz, though he is undeniably very zealous about CHECWORKS, has not considered the many different safety issues which are associated with wall thinning.

Q54. At A48, Dr. Horowitz disputes your view that it is'the local velocity and not the calculated average velocity that controls local turbulence. Please respond.

A54. Dr. Horowitz misrepresents my view of this issue stated in Exhibit NEC-JH_36 at 3. It is incorrect for Dr. Horowitz to state that I have stated that a pressure drop across complex geometries would have required CFD type calculations because of my statement that wall thinning varies with the local characteristics of FAC. See,.Exhibits NEC -JH_53 at 48, 65 and NEC-JH_40. I never stated that pressure drop calculations would commonly require CFD type analysis. The analogy with pressure drop is not valid, because here one is interested in the pressure drop across the entire co'mponent, not in the local variation of the pressure drop, experimental Kc values are sufficient to determine pumping requirements. Failures due to FAC are local and require the local velocity for valid assessment. A simple proof of this point is the fact that surfaces on the outer diameter of bends wear faster than those on the inner diameter. As pointed out in Exhibit NEC-JH_36 at 3, the average velocity may remain the same but the local corrosion rate may increase due to local geometry changes.

Table 3-1 and Table 7-1 in E4-08 contain average mass transfer coefficients as discussed in NEC-JH_36 at 2, 3 and 4. These coefficients can be-obtained in any mass or heat. transfer handbook; they have little to do with the determination of the local variation of corrosion rates in various components. This only indicates that CHECWORKS can be used as a general screening tool, i.e. comparing various geometries with respect to their vulnerability to FAC damage, a fact which NEC never denied. Figure 7-2 only verifies NEC's contention that corrosion rates vary with location depending on the intensity of the local turbulence. The factor A in that figure 39

comes from EDF data and varies by an order of magnitude, depending on the component, with an RMS of 50%. A represents the total mass transfer coefficient, not the local variation of the mass transfer coefficient. The equation A =A + BxA is not referenced and its validity is not explained. It is apparently an attempt to account for local variations of turbulence under some unspecified condition. The above equation may be used for screening components but not to predict local corrosion rates as, for example, described in Exhibits NEC-JH_53 at 65 and NEC -

JH_36 at 3, where the increase in the local turbulence intensifies the rate of corrosion. If wall thinning was measured at Unit 1 at the Ohi power station according to an equation of the type shown above, it would not have predicted the intense local thinning at the end of the curved section of the pipe. See, Exhibit NEC -JH_53 at 65.

Q55. NEC-JH_36 at 3 explained in detail that the local mass transfer coefficients in curved pipes in turbulent flow are expected to vary as the velocity square because turbulent mixing is promoted by the centrifugal force which varies with the square of the velocity. Also as indicated in NEC-JH_40 at Eq 22, erosion by droplet impingement varies with the square of droplet velocity At A49, Dr, Horowitz disputes this observation. How do you respond?

A55. Dr. Horowitz provided no relevant data to support his statement in A49. The figures in E4-22 and 23 do not dispute the dependence of the mass transfer coefficient in fully developed turbulent flow straight tubes and curved pipes. They are completely irrelevant to the issue raised by Q49.

With regard to my observation that the mass transfer coefficient varies with the 0 . 8 th power, Dr. Horowitz appears to agree by saying that the mass transfer varies between 0.5 and 1.0. The 0.5 is related to laminar flow and my observation was addressed to turbulent flow.

Without providing any support, Dr. Horowitz makes the bald statement that the corrosion rate is 40

directly proportional to the mass transfer coefficient. In NEC-JH_36 at 4 and 20, 1 discussed and provided a considerable amount of data showing that the corrosion rate may vary as the cube of the mass transfer coefficient, and therefore as a power of 2.4 to 6 of the velocity.

Dr. Horowitz's unsupported statement that data from all sources shows that erosion rate varies less than linearly is-simply not true.

Q56. At A50, Dr. Horowitz states that "the successful use of CHECWORKS and it's [sic]

predecessor programs for more than 20 years provides additional support for the claim that CHECWORKS is an effective tool for inspection planning." Please respond.

A56. The hundreds of pipe failures during this period, as documented by NEC, certainly do not support that statement. See, Exhibit NEC-JH_36 at 8, 9 and 10.

Q57. At A56, Dr. Horowitz comments on your statement that Entergy believes that "the length and the highest velocities control corrosion." Dr. Horowitz asserts that this quote is lifted from ACRS transcripts. Is he correct?

A57. Dr. Horowitz is wrong. This statement was not taken from ACRS transcripts. It is not taken out of context, nor is it misunderstood. The statement was made by Entergy directly in reply to NECks Petition and not in a reply to the ACRS. See, Entergy's Answer to New England Coalition's Petition for Leave to Intervene, Request for Hearing, and Contentions (June 22, 2006) at 33.

Q58. Please list any references to this testimony that were not filed as Exhibits to your direct testimony.

A58.

1. Memorandum to H.L. Abercrombie, Site Director, Sequoyah Nuclear Plant from D.W. Wilson, Project Engineer, Sequoyah Nuclear Plant, "Sequoyah Nuclear Plant Units 1 and 2 - Preliminary Report on the Condensate-Feedwater Piping Inspection - Suspected Erosion-Corrosion Areas (January 27, 1987). Exhibit NEC-JH_70.

41

I also now submit two papers cited as references to my FAC report in support of NEC's Statement of Initial Position, Exhibit JH-NEC_36:

1. G.J. Bignold, et al, Paper 1, Water Chemnistry II, BNES, 1980. Exhibit NEC-J1H71.

2. I.S. Woolsey. et. al., "Paper 96. The influence of oxygen and hydrazine on the erosion-corrosion behavior and electrochemical potentials of carbon steel under boiler feedwater conditions. Exhibit NEC-JH_72.

Q59. Does that complete your rebuttal testimony?

A59. Yes.

lK 142

OG/02/20"8 1: 26 3017623511 NOVERFLO PAGE 01 I declare under penalty of perjury that the foregoing is true and oaTctrt.

,=;Z.e)a i*im Hopelife d, At , Maryland, this day of May, 2008 personally appeared Joram Hopenfeld, and having subscribed his name acknowledges his signature to be his free act and deed.

Before me:

Notary Phtblic My Commission Expires

NEC-JH_64 I~I~2 iiELECTRIC POWER~

IRESEARCH MNSTITUTE Materials. Reliability Program:

Guidelines for Addressing Fatigue Environmental Effects in a License Renewal Application (MRP-47, Revision 1),

Technical Report

Materials Reliability Program:

Guidelines for Addressing ,Fatigue Environmental Effects in a License Renewal Application (MRP-47 Revision 1) I 1012017 Final Report, September 2005 EPRI Project Manager J. Carey ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1395

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Copyright © 2005 Electric Power Research Institute, Inc. All rights reserved.

CITATIONS This report was prepared by Structural Integrity Associates, Inc.

6855 South Havana Street, Suite 350 Centennial, CO 80112 Authors:

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Materials Reliability Program: Guidelinesfor Addressing Fatigue Environmental Effects in a License Renewal Application (MR'P-47 Revision 1). EPRI, Palo Alto,CA: 2005. 1012017.

iii

REPORT

SUMMARY

For about the last 15 years, the effects of light water reactor environment on fatigue have been the subject of research in both the United States and abroad. Based on a risk study reported in

.NUREG/CR-6674, the NRC concluded that reactor water environmental effects were not a safety issue for a 60-year operating life, but that some limited assessment of its effect would be required for a license renewal extended operating period beyond 40 years. This guideline offers methods for addressing environmental fatigue in a license renewal submittal.

Background

Many utilities are currently embarking upon efforts to renew their operating licenses. One of the key areas of uncertainty in this process relates to fatigue of pressure boundary components.

Although the NRC has determined that fatigue is not a significant contributor to core damage frequency, they believe that the frequency of pipe leakage may increase significantly with operating time and have requested that license renewal applicants perform an assessment to determine the effects of reactor water coolant environment on fatigue, and, where appropriate, manage this effect during the license renewal period. As the license renewal application process progressed starting in 1998, several utilities addressed this request using different approaches. In more recent years, a unified approach has emerged that has obtained regulator approval and allowed utilities to satisfactorily address this issue and obtain a renewed operating license for 60 years of plant operation.

Objectives

-. To provide guidance for assessment and management of reactor coolant environmental effects To minimize theamount of plant-specific work necessary to comply with NRC requirements for addressing this issue in a license renewal application To provide "details of execution" for applying the environmental fatigue approach currently accepted by the NRC in the license renewal application process.

/

Approach The project team reviewed previous work by EPRI and utilities related to fatigue environmental effects and license renewal including reports on this subject created by EPRI, NRC, and NRC contractors. Recent license renewal applications, NRC Requests for Additional Information, and the commitments made by the past license renewal applicants provided insight into NRC expectations. After evaluation of all this information, the project team developed alternatives for addressing fatigue environmental effects. This revision provides guidelines based on industry experience, consensus, and insight gained from more than six years of experience with this issue and the license renewal approval process.

v

Results The report describes a fatigue environmental effect license renewal approach that can be applied by any license renewal applicant. It provides guidelines for performing environmental fatigue assessments using fatigue environmental factors from currently accepted Fen methodology.

EPRI Perspective Utilities have committed significant resources to license renewal activities related to fatigue.

Based on'intut from applicants to-date, NRC requirements for addressing fatigue environmental effects, continued to change for the first few applicants, but more recently have become more unified. These guidelines were developed to provide stability, refined guidance, and assurance of NRC acceptance and include an approach that may be taken to address fatigue environmental effects in a license renewal application. Use of the approach provided in this document should limit the amount of effort necessary by individual license renewal applicants in addressing this requirement and putting activities in place for the extended operating period to manage-reactor water environmental effects on fatigue.

Keywords Fatigue License Renewal Reactor Water Environmental Fatigue Effects vi

/

ABSTRACT For about the last 15 years, the effects of light water reactor environment on fatigue have been the subject of research in both the United States and abroad. The conclusions from this research are that the reactor water temperature and chemical composition (particularly oxygen content or ECP) can have a significant effect on the fatigue life of carbon, low alloy, and austenitic stainless steels. The degree of fatigue life reduction is a function of the tensile strain rate during a transient, the specific material, the temperature, and the water chemistry. The effects of other than moderate environment were not considered in the original development of the ASME Code Section III fatigue curves.

This issue has been studied by the Nuclear Regulatory Commission"(NRC) for many years. One of the major efforts was a program to evaluate the effects of reactor water environment for both early and late vintage plants designed by all U.S. vendors. The results of that study, published in NUREG/CR-6260, showed that there were a few high usage factor locations in all reactor types, and that the effects of reactor water environment could cause fatigue usage factors to exceed the-ASME Code-required fatigue usage limit of 1.0. On the other hand, it was demonstrated that usage factors at many locations could be shown acceptable by refined analysis and/or fatigue monitoring of actual plant transients.

Based on a risk study reported in NUREG/CR-6674, the NRC concluded that reactor water environmental effects were not a safety issue for a 60-year operating life, but that some limited assessment of its effect would be required for a license renewal extended operating period beyond 40 years. Thus, for all license renewal submittals to-date, there have been formal -

questions raised on the topic of environmental fatigue and, in all cases, utility commitments to address the environmental effects on fatigue in the extended operating period. Many plants have already performed these commitments.

/This guideline offers methods for addressing environmental fatigue in a license renewal submittal. It requires that a sampling of the most affected fatigue sensitive locations be identified for evaluation and tracking in the extended operating period. NUREG/CR-6260 locations are considered an appropriate sample for Fe, evaluation as long as none exceed the acceptance criteria with environmental effects considered. If this occurs, the sampling is to be extended to other locations. For these locations, evaluations similar to those conducted in NUREG/CR-6260 are required. In the extended operating period, fatigue monitoring is used for the sample of locations to show that ASME Code limits are not exceeded, If these limits are exceeded, corrective actions are identified for demonstrating acceptability for continued-operation.

vii

.Using the guidance provided herein, the amount of effort needed to justify individual license renewal submittals and respond to NRC questions should be minimized, and a more unified, consistert approach should be achieved throughout the industry. More importantly, this revision provides "details of execution" for applying the environmental fatigue approach currently accepted by the NRC in the license renewal application process.

viii

CONTENTS 1 INTRODUCTION .................................................................................................................... 1-1 1 .1 O bje c tiv e s ....................................................................................... ............................... 1-1 1.2 Compliance Responsibilities ........................................... 1-2 2 BACKGROUND .... ............................................................................................................... '2-1 2 .1 R ese a rc h R e su lts ............................................................................................................ 2 -1 2.2 License Renewal Environmental Fatigue Issue .............................................................. 2-2 2 .3 Industry/E P R I P rogram s ................................................................................................. 2-2 3 LICENSE RENEWAL APPROACH ........................................................................................ 3-1 3 .1 O v e rv iew ......................................................................................................................... 3 -1 3.2 Method for Evaluation of Environmental Effects ............................................. I............... 3-3 3.2.1 Identification of Locations for Assessment of, Environmental Effects ...................... 3-4 3.2.2 Fatigue Assessment Using Environmental Factors ................................................. 3-7 3.3 Alternate Fatigue Management in the License Renewal Period ................................... 3-10 3.4 Guidance-for Plants with B31.1- Piping Systems ........................................................... 3-10 3.5 Consideration of Industry Operating Experience ........................... I....... 3-11 4 GUIDANCE FOR PERFORMING ENVIRONMENTAL FATIGUE EVALUATIONS ............... 4-1 4.1 Environmental Fatigue Factor (Fen) Relationships ....................................................... 4-1 4.2 Guidelines for Application of the Fen Methodology .......................................................... 4-3 4.2.1 Contents of a Typical Fatigue Evaluation ................................................................. 4-4 4.2.1.1 "O ld" C alculation (Figure 4-1) ......................................................................... 4-5 4.2.1.2 "New" Calculation (Figures 4-2 through 4-4) .................................................... 4-7 4.2.2 T ransform ed Strain R ate, k * ................................................................................ 4-11 4.2.3 Transformed Sulfur Content, S* ........................................................................... 4-16 4.2.4 Transformed Temperature, T* ...................................................................... ....... 4-16 J4.2.5 Transformed Dissolved Oxygen, 0* ..................................................................... 4-19 ix

4.2.6 A dditional C onsiderations ...................................................................................... 4A23 4.2 .7 Sam ple C alculation ................................................................................................ 4-23 4.3 Issues Associated With Fen Methodology ................................. 4-25 5 C O N C LU S IO NS ..................................................................................................................... 5-1 6 R E FE R EN C ES ........................................................................................................................ 6-1 A SURVEY OF APPROACHES USED TO-DATE FOR ADDRESSING FATIGUE ENVIRONMENTAL EFFECTS IN THE EXTENDED OPERATING PERIOD ........................ A-1 2

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LIST OF FIGURES Figure 3-1 Overview of Fatigue Environmental Effects Assessment and Management ............ 3-4 Figure 3-2 Identification of Component Locations and Fatigue Environmental Effects A sse ssm e nt ................ I.................................................................................................... 3 -6 Figure 3-3 Fatigue Management if Environmental Assessment Conducted .............. 3-9 Figure 4-1 Example of "Old" Fatigue Calculation ..................................................................... 4-6 Figure 4-2 Example of "New" Fatigue Calculation - CUF Calculation ....................................... 4-8 Figure 4-3 Example of "New" Fatigue Calculation - Load Pair Definitions ................................. 4-9 Figure 4-4 Example of 'New" Fatigue Calculation - Transient Definitions .............. 4-10 Figure 4-5 Detailed and Integrated Strain Rate Calculation ............... .................... ......... 4-15 Figure 4-6 Fen Values as a Function of Temperature ............................................................... 4-18 Figure 4-7 Fen Values as a Function of DO Level .................................................................... 4-22 Figure 4-8 Sample Environmental Fatigue Calculation ............................ 4-25 Figure 4-9 Issue of T ransient Linking ....................................................................................... 4-25 xi

INTRODUCTION 1.1 Objectives The nuclear industry has discussed the issue of reactor water environmental fatigue effects with the U. S. Nuclear Regulatory Commission (NRC) staff for several years. All of the license renewal applicants to-date have been required to commit to an approach to evaluate the effects of reactor water environment on specific Class 1,reactor coolant system components for the license renewal term in order to obtain approval for a renewed license.

This report provides discussion of an approach that may be used for addressing reactor water environmental effects on fatigue of reactor coolant system components in the extended operating period (after 40 years). Specific guidance for calculating environmental fatigue usage factors for NUREG/CR-6260 [2] locations is provided using the methodology documented in NUREG/CR-6583 [3] and NUREG/CR-5704 [4]. This report does not provide guidance on addressing fatigue as a Time Limiting Aging Analysis (TLAA) per 10CFR54. The details of monitoring thermal fatigue for acceptance are contained in Reference [23].

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Thus; the objectives of this report are as follows:

1. To provide guidance for evaluating the effects of reactor water environmental effects on fatigue for license renewal applicants,

2. To provide specific guidance on the use of NUREG/CR-6583 for carbon and low alloy steels

[3] and in NUREG/CR-5704 for austenitic stainless steels [4] in plant specific evaluations of the effects of reactor water environmental effects on fatigue,

3. To provide separate guidance for pressurized water reactors (PWRs) and boiling water reactors (BWRs) to assist in the development of reasonable estimates for the significant parameters (e.g., oxygen, temperature, and strain rate) required by the environmental fatigue assessment methodology at evaluated locations,

4. To provide approaches for removing excess conservatism in existing fatigue analyses to offset the impact of environmental effects,

5. To provide alternatives for managing environmental effects using flaw tolerance evaluation and inspection,

6. To provide guidance that minimizes the amount of effort needed to justify individual license renewal submittals and respond to NRC questions, and promote a more unified, consistent approach throughout the industry, and

7. Incorporate "Lessons Learned" from ASME Code activities supported by the, MRP associated with this topic.

1-1

Introduction This guideline document includes appropriate logic to allow users to efficiently performi environmental fatigue calculations for a plant pursuing license renewal activities. The-logic is provided such that some components can be evaluated using simplified methods, whereas others can be evaluated using more complex methods.\

Finally, this document Mso summarizes the approaches for addressing fatigue environmental effects in the extended operating period used by those applicants that have already submitted the license renewal applications.

1.2 Compliance Responsibilities The Industry Guidelines contained in this-report are considered to be "Good Practice".

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BACKGROUND 2.1 Research Results NRC research in the area of reactor water environmental effects on fatigue began in the early 1990s. Based on testing both in Japan and in the U.S., fatigue life in a light water reactor (LWR) environment was determined to be adversely affected by certain water chemistries, strain amplitude, strain rate, temperature and material sulfur content (for ferritic steels). Whereas LWR pressure boundary components are in contact with the reactor water at elevated temperatures, the fatigue curves in Section III of the ASME Boiler and Pressure Vessel Code were based on testing in air, primarily at room temperature, adjusted by a structural factor in-part to compensate for temperature and "industrial" environments. In 1993, a set of "interim" fatigue curves for carbon, low alloy, and stainless steels were published in NUREG/CR-5999 [1] based on the results of research testing at that point in time.

To determine the effects of the environment in operating nuclear plants during the current 40-year licensing term and for an assumed 60-year extended period, Idaho National Engineering Laboratories (INEL) evaluated fatigue-sensitive component locations, and documented their results in NUREG/CR-6260 [2]. Using information from existing reactor component stress reports, supplemented by additional evaluations, cumulative fatigue usage factors (CUFs) were calculated for plants designed by all four nuclear steam supply system (NSSS) vendors utilizing the interim fatigue curves provided in NUREG/CR-5999 [1]. The results showed that CUFs would exceed 1.0 at several-locations, although the CUFs at many of these were shown to be less than 1.0 if excessive conseryatisms were removed from the evaluations.

Continued research led to changes to the fatigue curves utilized in deriving the results presented in NUREG/CR-6260 [2]. The latest proposed environmental fatigue correlations are presented in NUREG/CR-6583 [3] for carbon and low alloy steels and in NUREG/CR-5704 [4] for austenitic stainless steels. These approaches do not use the revised fatigue curve approach originally defined in NUREG/CR-5999, but'instead employ a. selective environmental fatigue multiplier, or Fe., approach that is defined as follows:

Nar Fen =-air N water 2

where:, F environmental fatigue multiplier N. fatigue life (number of cycles) in air, at room temperature, N ..... fatigue life (number of cycles) in water (environment), at temperature 2-1

Background

The fatigue usage derived from air curves is multiplied by F., to obtain the fatigue usage in the associated environment.

More recently, an evaluation was conducted to assess the implications of LWR environments on reducing component fatiguefor a 60-year plant life. This study, based on the information in NUREG/CR-6260 [2] and documented in NUREG/CR-6674 [5], concluded that the environmental effects of reactor water on fatigue curves had an insignificant contribution to core damage frequency. However, the frequency of pipe leakage was shown to increase in some cases.

2.2 License Renewal Environmental Fatigue Issue The environmental fatigue issue for license renewal reached the current disposition via the closeout of Generic Safety Issue 190 (GSI-190) [6] in December 1999. In a memorandum from NRC-RES to NRC-NRR [7], it was concluded that environmental effects would have a negligible impact on core damage frequency, and as such, no generic regulatory action was required. However, since NUREG/CR-6674 [5] indicated that reactor coolant environmental fatigue effects would result in an increased frequency of pipe leakage, the NRC required'that utilities applying for license renewal must address the effects of reactor water environments on fatigue usage in selected examples of affected components on a plant specific basis.

2.3 Industry/EPRI Programs Following the issuance of NUREG/CR-6260 [2], EPRI performed several studies to quantitatively address the issue of environmental fatigue during the license renewal period.

The initial efforts were focused on developing a simplified method for addressing environmental fatigue effects and evaluating more recent research results. The calculations reported in NUREG/CR-6260 [2] were based on the interim fatigue design curves given in NUREG/CR--

5999 [1]. The conservative approach in NUREG/CR-6260 [2] and NUREG/CR-5999 [1] over-penalized the component fatigue analysis, since later research identified that a combination of environmental conditions is required before reactor water environmental effects become pronounced. The strain rate must be sufficiently low and the strain range mus't be sufficiently high to cause repeated rupture of the protective oxide layers that protect the exposed surfaces of reactor components. Temperature, dissolved oxygen content, metal sulfur content, and water flow rate are examples of additional variables to be considered.

In order to take these parameters into consideration, EPRI and GE jointly developed a method, commonly called the Fen approach [8], which permits reactor water environmental effects to be applied selectively, as justified by evaluating the combination of effects that contribute to increased fatigue susceptibility.

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Background

The F " approach was used in several EPRI projects to evaluate fatigue-sensitive component locations in four types of nuclear power plants: an early-vintage Combustion Engineering (CE)

PWR [9], an early-vintage Westinghouse PWR [10], and both late-vintage [LI] and early-vintage

[12] General Electric (GE) BWRs. Component locations similar to those evaluated in NUREG/CR-6260 [2] were examined in these generic studies.

The NRC staff has not accepted the studies performed by EPRI [13], primarily because the environmental fatigue effects were based on data that was developed prior to the issuance of later reports by Argonne National Laboratory (ANL) [3, 4]. The following issues were raised in a letter from NRC to the Nuclear Energy Institute [13]:

" The environmental fatigue correction factors developed in the EPRI studies were not based on the latest ANL test report.

• The environmental factors developed in the EPRI studies were not based on a comparison of environmental data at temperature to air data at room temperature.

• The NRC did not agree with the use of the reduction factors (Z-factors) of four (for carbon steel) and two (for stainless steel) to account for moderate environmental effects (i.e., Feffectiv Fen/Z-factor). Instead, the NRC staff believed that the maximum factors that could be used were three (for carbon steel) and 1.5 (for stainless steel).

" There was disagreement on the strain thresholds that were used.

• The NRC staff did not agree that credit could be taken for the cladding in omitting consideration of environmental effects for the underlying carbon steel/low alloy steel materials, unless fatigue in the cladding was specifically addressed.

• The staff agreed with the use of a weighted average strain rate for computing environmental effects only if the maximum temperature of the transient was used.

Based on NRC review of more recent Japanese and ANL data, NRC believes that no credit should be given for inherent margins with regard to moderate environmental effects [14], i.e., the above factor of 4 (EPRI)/3 (NRC) for carbon and low alloy steels, and 2/1.5 for stainless steels should not exceed 1.0.

The Pressure Vessel Research Council (PVRC) Steering Committee on Cyclic Life and Environmental Effects (CLEE) has reviewed published environmental fatigue test data and the Fo, methodology. Basedon this review, the most recent findings by ANL have been incorporated into the equations for the environmental factors. More importantly, it was concluded that the environmental factors could be reduced, by factors of 3.0 for carbon/low-alloy steel and 1.5 for stainless steel, to credit moderate environmental effects included in the current ASME Code fatigue design curves. The PVRC recommendations have been forwarded to the Board of Nuclear Codes and Standards (BNCS) [15]. The recommended evaluation procedure is published in Welding Research Council (WRC) Bulletin No. 487 [18]. WRC-487 includes evaluations based on recent data that would support reduction factors of 3.0 for carbon/low-alloy -

steel and 1.5 for stainless steel.

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Background===

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In conjunction with the PVRC efforts, the MRP reviewed all published industry fatigue data and documented their review of the data and recommended assessment methodologies [19]. Based on those findings, in 2003, the industry pursued a formal response t6 the NRC regarding the above areas of disagreement. for carbon and low alloy steels [20]. The NRC staff ruled against this response in January 2004 [21] citing that an adequate technical basis was not provided to support several of the assumptions used in the industry's proposal. As a result, EPRI.has chosen to work with the license renewal applicants on an industry guideline that defines evaluation techniques that plants can use to satisfactorily achieve resolutions to the issues. These prototype resolutions are formulated for use with Fe, expressions whether from NRC, NUREG, PVRC or other sources, with discussion provided for the NUREG methodology since that methodology is currently accepted for use by license renewal applicants. The industry is pursuing longer-term application of the PVRC rules through ASME Code changes.

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3 LICENSE RENEWAL APPROACH 3.1 Overview This document describes how the technical issues associated with reactor water fatigue environmental effects evaluation may be addressed, and guidelines are provided on how to perform environmental fatigue evaluations using the methodologies documented in NUREG/CR-6583 [3] and NUREG/CR-5704 [4]. To assess the effects of reactor water environment on fatigue life, a limited number of components (including those in NUREG/CR-6260 [2] for the appropriate vintage/vendor plant) are to be assessed considering the effects of recent environmental fatigue data. As explained below, NUREG/CR-6260 locations are considered an appropriate sample for Fen evaluation as long as none exceed the acceptance criteria with environmental effects considered. If this occurs, the sampling is to be extended to other locations. These component locations serve as the leading indicators to assess the significance of environmental effects. For this limited number of components, the effects of the environment on fatigue life must be addressed and adequately managed in the extended operating period.

The process chosen to address environmental effects by the first few applicants for license renewal varied. After a series of requests for additional information, the process that the NRC accepted for Calvert Cliffs and Oconee involved an analytical approach coupled with future planned refinements in their plant fatigue monitoring. Since that time, there has been acceptance of the approaches used by other applicants, and some applicants have committed to perform evaluation only just before entering into the license renewal period (i.e., prior to. the end of 40 years). Appendix A provides the results of an industry survey of license renewal applicants to-date describing the varied approaches that have been used'.

In many cases, the commitment to perform evaluation later by some of the license renewal applicants has been based on uncertainty and lack of consensus on this topic throughout the industry, and reflects a,"wait-and-see" attitude and an avoidance of expending resources now on an issue that may change later. Therefore, it is the intent of this report to develop guidelines for aging management of reactor water fatigue effects for license renewal, so that an acceptable and more unified approach for addressing this issue will be clearly documented for future license renewal applicants.

These guidelines provide a process to address environmental effects in the License Renewal Application, and provide specific guidance on the use of currently accepted environmental fatigue evaluation methodologies. Where necessary, these guidelines are consistent with the Thermal Fatigue Licensing Basis Monitoring Guidelines [23], based on today's knowledge and industry experience. The elements of this approach may change in the future as more information becomes available. Attributes of the fatigue management activity are as follows:

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License Renewal Approach

1. SCOPE The scope is discussed in.detail in Section 2.5.2 of Reference [23]. NUREG/CR-6260 locations will be captured and thus automatically included by the activity steps discussed therein.

2. PREVENTIVE ACTIONS Cracking due to thermal fatigue of locations specifically designed to preclude such cracking is prevented by assuring that the thermal fatigue licensing basis remains valid for the period of extended operation. The actions taken in Thermal Fatigue Licensing Basis Monitoring are based on reliance on the standards established in ASME Section III and ASME Section XI.

3. PARAMETERS MONITORED OR INSPECTED Monitored parameters are defined and discussed in detail in Sections 2.5.2 and 2.6 of Reference [23].

4. DETECTION OF AGING EFFECTS The only detectable aging effects of fatigue are the presence of cracks. These cracks may initiate earlier in life and grow to a detectable size sometime after the CUF exceeds 1.0. The Inservice Inspection Plan as governed by ASME Section XI administers a set of actions relative to the inspection for, detection of, and disposition of crack like indications. This guideline is a sister guideline to the Thermal Fatigue Licensing Basis Monitoring Guideline but is not a part of it.

The Thermal Fatigue Licensing Basis Monitoring Guideline tracks the margin allotted to the point of CUF = 1 (or to a lesser threshold point) as a way of tracking the life expended prior to the onset of structurally relevant fatigue cracking. Refer to Sections 2.5.2 and 2.6 of Reference [23] for a discussion of the parameters monitored for this purpose.

5. MONITORING & TRENDING Sections 2.5.2 and 2.6 of Reference [2.3] provide a discussion of the parameters monitored and the trending of those parameters as the component fatigue life is expended.

6. ACCEPTANCE CRITERIA Sections 2.5.2 and 2.6 of Reference [23] provide a discussion of the parameters monitored, the establishment of acceptance criteria for those parameters, and the trending of those parameters as the component fatigue life is expended.

7. CORRECTIVE ACTION Section 2.6.3 of Reference [23] provides a detailed discussion of the application of the corrective action requirements.

8. CONFIRMATION PROCESS The confirmation process is part of the corrective action program.

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License Renewal Approach

9. ADMINISTRATIVE CONTROLS The Thermal Fatigue Licensing Basis Monitoring Guideline actions are implemented by plant work processes.

10. OPERATING EXPERIENCE Refer to Sections 1.1 and 2.5.2.3 of Reference [23] for a discussion of how operating experience becomes part of the Thermal Fatigue Licensing Basis Monitoring Guideline implementation.

3.2 Method for Evaluation of Environmental Effects There are several methods.that have been published to assess the effects of reactor water environment on fatigue for each specific location to be considered. In this document, guidance is provided for performing evaluations in accordance with NUREG/CR-6583 [3] for carbon and low alloy steels and NUREG/CR-5704 [4] for austenitic stainless steels, since these are the currently accepted methodologies for evaluating environmental fatigue effects. Other methods that have been published, including those currently being used in Japan, are documented in References [18] and [22].

Figure 3-1 is a flowchart that shows an overview of the assessment approach.

• The first step is to identify the locations to be used in the assessment. This step is discussed in Section 3.2.1

• The second step is to perform an assessment of the effects of environmental fatigue on the locations identified in.Step 1. This includes an assessment of the actual expected fatigue usage factor including the influence of environmental effects. Inherent conservatisms in design transients may be removed to arrive at realistic CUFs that include environmental effects. This approach is most applicable to locations where the design transients significantly envelope actual operating conditions in the plant. Further discussion is provided in Section 3.2.2. Specific guidance on performing such evaluation is provided in Section 4.0.

• The bottom of Figure 3-1 indicates that fatigue management occurs after the evaluation from Step 2 is performed for each location. This may be as simple as counting the accumulated cycles and showing that they remain less than or equal to' the number of cycles utilized in the assessment performed in Step 2. On the other hand, it may not be possible to show continued acceptance throughout the extended operating period such that additional actions are required. Such options are discussed in Section 3.3. Refer also to Reference [23] for a discussion of cycle counting.

3-3

License Renewal Approach IDENTIFY LOCATIONS PERFORM ENVIRONMENTAL FATIGUE USAGE ASSESSMENT I

FATIGUE MANAGEMENT IN EXTENDED OPERATING PERIOD 04.71 Figure 3-1 Overview of Fatigue Environmental Effects Assessment and Management 3.2.1 Identification of Locations for Assessment of Environmental Effects A sampling of locations is chosen for the assessment of environmental effects. The purpose of identifying this set of locations is to focus the environmental assessment on just a few components that will serve as leading indicators of fatigue reactor water environmental effects.

Figure 3-2 shows an overview of the approach identified for selecting and evaluating locations.

For both PWR and BWR plants, the locations chosen in NUREG/CR-6260 [2] were deemed to be representative of locations with relatively high usage factors for all plants. Although the locations may not have been those with the highest values of fatigue usage reported for the plants evaluated, they were considered representative enough that the effects of LWR environment on fatigue could be assessed.

The locations evaluated in NUREG/CR-6260 [2] for the appropriate vendor/vintage plant should be evaluated on a plant-unique basis. For cases where acceptable fatigue results are demonstrated for these locations for 60 years of plant operation including environmental effects, additional evaluations or locations need not be considered. However, plant-unique evaluations may show that some of the NUREG/CR-6260 [2] locations do not remain within allowable limits for 60 f years of plant operation when environmental effects are considered. In this situation, plant specific evaluations should expand the sampling of locations accordingly to include other locations where high usage factors might be a concern.

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License Renewal Approach In original stress reports, usage factors may have been reported in many cases that are unrealistically high, but met the ASME Code requirement for allowable CUF. In these cases, revised analysis may be conducted to derive a more realistic usage factor or to show that the revised usage factor is significantly less than reported.

If necessary, in identifying the set of locations for the expanded environmental assessment, it is important that a diverse set of locations be chosen with respect to component loading (including thermal transients), geometry, materials, and reactor water environment. If high usage factors are presented for a number of locations that are similar in geometry, material, loading conditions, and environment, the location with the highest expected CUF, considering typical environmental fatigue multipliers, should be chosen as theo bounding location to use in the environmental fatigue assessment. Similar to the approach taken in NUREG/CR-6260 [2], the final set of locations chosen for expanded environmental assessment should include several different types of locations that are expected to have the highest CUFs and should be those most adversely affected by environmental effects. The basis of location choice should be described in the individual plant license renewal application.

In conclusion, the following steps should be taken to identify the specific locations that are to be considered in the environmental assessment:

0 Identify the locations evaluated in NUREG/CR-6260 [2] for the appropriate vintage/vendor plant.

a Perform a plant-unique environmental fatigue assessment for the NUREG/CR-6260 locations.

• If the CUF results for all locations above are less than or equal to the allowable (typically 1.0) for the 60-year operating life, the environmental assessment may be considered complete; additional evaluations or'locations need not be considered.

• If the CUF results for any locations above are greater than the allowable for the 60-year operating life, expand the locations evaluated, considering the following:

- Identify all Class 1 piping systems and major components. For the reactor pressure vessel, there may be multiple locations to consider.

- For each system or component, identify the highest usage factor locations. By reasons of geometric discontinuities or local transient severity, there will generally be a few locations that have the highest usage factors when considering environmental effects.

From the list of locations that results from the above steps, choose a set of locations that are a representative sampling of locations with the highest expected usage factors when considering environmental effects. Considerations for excluding locations can include:

(1) identification of excess conservatism in the transient grouping or other aspects of the design fatigue analysis, or (2) locations that have similar loading conditions, geometry, material, and reactor water environment compared to another selected location.

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License Renewal Approach SELECT NUREG/CR-6260 j LOCATIbNS FOR APPROPRIATE PLANT PERFORM PLANT-UNIQUE ENVIRONMENTAL FATIGUE EVALUATIONS FOR 60 YEARS

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SELECT OTHER APPROPRIATE HIGH USAGE FACTOR LOCATIONS

,'RE-PERFORM PLANT-UNIQUE ASSESSMENT FOR ALL LOCATIONS Figure 3-2 Identification of Component Locations and Fatigue Environmental Effects Assessment 3-6

License Renewal Approach 3.2.2 FatigueAssessment Using EnvironmentalFactors In performing an assessment of environmental fatigue effects, factors to account for environmental effects are incorporated into an updated fatigue evaluation for each selected location using the F.. approach documented in NUREG/CR-6583 [3] for carbon and low alloy steels and NUREG/CR-5704 [4] for austenitic stainless steels. Excess conservatism in the loading definitions, number of cycles, and the fatigue analyses may be considered. Figure 3-3 shows the approach for performing the assessment and managing fatigue in the extended operating period.

Determination of Existing Licensing Basis Existing plant records must be reviewed to determine the cyclic loading specification (transient definition and number of cycles) and stress analysis for the location in question. Review of the analysis may or may not show that excess conservatism exisis. Reference [23] provides guidance on reviewing the original design basis, the operating basis, and additions imposed by the regulatory oversight process, to determine the fatigue licensing basis events for which the component is required to be evaluated.

Consideration of Increased Cycles for Extended Period As a part of the license renewal application process, the applicant must update the projected cycles to account for 60 years of plant operation. The first possible outcome is that the number, of expected cycles in the extended operating period will remain at or below those projected for the initial 40-year plant life. In this case, the governing fatigue analyses will not require modification to account for the extended period of operation.

The second possibility is that more cycles are projected to occur fdr 60 years of plant operation than were postulated for the first 40 years. In this case, an applicant must address the increased cycle counts. One possible solution is to perform a revised fatigue analysis to confirm that the increased number of cycles will still result in a CUF less than or equal to the allowable. A second possibility is to determine the number of cycles at which the CUF would be expected to reach the allowable. This cycle quantity then becomes the allowable against which the actual operation is tracked. Section 3.3 discusses options to be employed if this lower allowable is projected to be exceeded.

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Fatigue Assessment Fatigue assessment includes the determination of CUF considering environmental effects. This may be accomplished conservatively using information from design documentation and bounding F factors from NUREG/CR-6583 [3] and NUREG/CR-5704 [4], or it may require a more extensive approach (as discussed in Section 4.0).

A revised fatigue analysis may or may not be required. Possible reasons for updating the fatigue analysis could include:

• Excess conservatism in original fatigue analysis with respect to modeling, transient definition, transient grouping and/or use of an early edition of the ASME Code.

3-7

r License Renewal Approach

" For piping, use of an ASME Code Edition prior to 1979 Summer Addenda, which included the AT, term in Equation (10) of NB-3650. Use of a later code reduces the need to apply conservative elastic-plastic penalty factors.

• Re-analysis may be needed to determine strain rate time histories possibly not reported in existing component analyses, such that bounding environmental multipliers (i.e., very low or "saturated" strain rates) would not have to be used.

A simplified revised fatigue analysis may be performed using results from the existing fatigue analysis, if sufficient detail is available. Alternatively, a new complete analysis could be conducted to remove additional conservatisms. Such an'evaluation would not necessarily need the full pedigree of a certified ASME Code Section III analysis (i.e., Certified Design Specification, etc.), but it should utilize all of the characteristic methods from Section III for computing CUF., In the environmental fatigue assessment, the environmental fatigue usage may be calculated using the following steps:

• For each load set pair in the fatigue analysis, determine an environmental factor Fen. This factor should be developed using the equations in NUREG/CR-6583 [3] or NUREG/CR-5704 [4]. (Section 4.0 provides specific guidance on performing an F., evaluation)

• The environmental partial fatigue usage for each load set pair is then determined by multiplying the original partial usage factor by F... In no case shall the F,, be less than 1.0.

• The usage factor is the sum of the partial usage factors calculated with consideration of environmental effects.

Fatigue Management Approach As shown in Figure 3-3, the primiary fatigue management approaches for the extended operating period consist of tracking either the CUF or number of accumulated cycles.

• For cycle counting, an updated allowable number of cycles may be needed if the fatigue assessment determined the CUF to be larger than allowable. One approach is to derive a reduced number of cycles that would limit the CUF to less than or equal to the allowable value (typically 1.0). On the other hand, if the assessed CUF was shown to be less than or equal to the allowable, the allowable number of cycles may remain as assumed in the evaluation, or increased appropriately. As long as the number of cycles in the extended operating period remains within this allowed number of cy-6les, no further action is required.

• For CUF tracking, one approach would be to utilize fatigue monitoring that accounts for the actual cyclic operating conditions for each location. This approach would track the CUF due to the actual cycle, accumulation, and would take credit for the combined effects of all transients. Environmental factors would have to be factored into the monitoring approach or applied to the CUF results of such monitoring. No further action is required as long as the computed usage factor remains less than or equal to the allowable value.

Prior to such time that the CUF is projected to exceed the allowable value, or the number of-actual cycles is projected to exceed the allowable number of cycles, action must be taken such that the allowable limits will not be exceeded. If the cyclic or fatigue limits are expected to be exceeded during the license renewal period, further approaches to fatigue management would be required prior to reaching the limit, as described in Section 3.3. Further details on guidelines for thermal fatigue monitoring and compliance/mitigation options are provided in Reference [23].

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License Renewal Approach Figure 3-3 Fatigue Management if Environmental Assessment Conducted 3-9

License Renewal Approach 3.3 Alternate Fatigue Management in the License Renewal Period As identified in Section 3.2, and discussed in detail in Reference [23], results from cycle counting or fatigue monitoring may predict that established limi'ts are exceeded during the extended operating period. If this occurs, there are several alternative approaches which may be used to justify continued operationvwith the affected component in service without having to perform repair or replacement, as follows:

• Reanalysis

• Partial Cycle Counting

• Fatigue Monitoring

• Flaw Tolerance Evaluation and Inspection

• Modified Plant Operations

• Evaluation of Similar Components In addition, the fatigue management program may need to be expanded if plant-unique or industry experience shows that fatigue limits are exceeded or if cracking is discovered, due to either anticipated or unanticipated transients. Refer to Reference [23] for a comprehensive discussion of these items.

3.4 Guidance for Plants with B31.1 Piping Systems Many plants that were designed in the 1960s had piping systrems that were designed in accordance with the rules of the ANSI B31.1 Power Piping Code. This Code did not require an explicit fatigue analysis. Howeve~r, the effects of thermal expansion cycles were included. If the number of equivalent full range thermal expansion cycles was greater than 7,000, the allowable range of thermal expansion stress was reduced. There was no consideration of stresses due to through-wall thermal gradients, axial temperature gradients, or bi-metallic welds.

Although ANSI B3 1.1 and ASME Code,Section III, Class 1 piping rules are fundamentally different, experience in operating plants has shown that piping systems designed to B3 1.1 are adequate. An evaluation of fatigue-sensitive B31.1 piping systems by EPRI [17] showed that there were only very limited locations in piping systems that exhibited high usage factors. In each case, these locations could be easily identified. It was concluded that high ,usage factors occurred only at locations that experienced significant thermal transients such as step temperature changes. In addition, the locations with high usage factors were always at a structural or material discontinuity, such as pipe-to-valve or pipe-to-nozzle transition welds. The report also noted that the design features of B3 1.1 plants are essentially no different than those in more modem plants designed to ASME Code,Section III, Class 1.

The high usage factor locations evaluated in NUREG/CR-6260 [2] were primarily associated with piping system discontinuities and occurred due to severe transients, except for PWR surge lines where a high number of stratification transients contributed to high usage factors.

3-10

License Renewal Approach The operation of B3 1.1 plants is also not different from that of plants designed to ASME Code,Section III, Class 1. All have limitations on heatup/cooldown rates as required by ASME Code, Sections III and'XI, and 10CFR50 Appendix G. The NSSS vendors have also provided continued feedback to plant operators to reduce the thermal fatigue challenges to components based on industry experience. Thus, the approach taken by an applicant with ANSI B31.1 piping systems need not be significantly different than that taken-for a more modern plant:

" The locations of NUREG/CR-6260 [2] for the appropriate vintage/vendor plant are selected.

For systems without specified design transients, a set of transients for tracking in the extended operating period must be established.

" Evaluations shall be undertaken to establish the usage factors at each of the selected locations. This may be based on similarities in geometry, materials, and transient cycles relative to other similarly designed plants. In addition, the information provided in NUREG/CR-6260 [2] may be used. Alternately, an ASME Code,Section III, Class I' analysis can be conducted. Such an evaluation would not necessarily need the full pedigree of a certified ASME Code,Section III analysis (i.e., Certified Design Specification, etc.), but it should iutilize all of the characteristic methods from Section III for computing CUF. Such an analysis would be used to establish the baseline fatigue usage without environmental effects for the plant.

" Using this information, the approach previously described for the ASME Code,Section III, Class 1 plants can be used to evaluate and manage fatigue environmental effects.

3.5 Consideration of Industry Operating Experience Consistent with current practice, industry experience with fatigue cracking will continue to be reviewed. The assessment of any fatigue cracking in the extended operating period will consider the effects of environment as a potential contributor. Monitoring of industry experience must consider fatigue cracking for both anticipated and unanticipated transients. An MRP integrated fatigue management guideline is currently under preparation that will consider all aspects of fatigue management, including consideration of industry -experience. See Reference [24].

3-11

4 GUIDANCE FOR PERFORMING ENVIRONMENTAL FATIGUE EVALUATIONS This section provides guidance for performing plant specific environmental fatigue evaluations for selected locations. The intent is to unify the process used by applicants to address environmental effects in the License Renewal Application, and provide specific guidance on the use of currently accepted environmental fatigue evaluation methodologies.

There are several methods that have been published to assess the effects of reactor, water environment on fatigue for each specific location to be considered. The currently accepted methodologies for evaluating environmental fatigue effects are documented in NUREG/CR-6583

[3]for carbon and low alloy steels and NUREG/CR-5704 [4] for austenitic stainless steels.

Although other methods have been developed and published, guidance is only provided for using NUREG/CR-6583 [3] and NUREG/CR-5704 [4]. However, all methods currently published are similar in terms of variables and applicability (i.e., they all use an Fee factor apprioach), so the guidance'that follows has general applicability to all methods. For reference, the other published methods, including those currently being used in Japan, are documerited in References [18] and

[22].

4.1 , Environmental Fatigue Factor (Fen) Relationships An environmental correction factor (F..) is defined as the ratio of fatigue usage with environmental effects divided by fatigue usage in air, or allowable cycles to fatigue crack initiation in air divided, by allowable cycles with water reactor environmental effects'. Fe, equations are provided in the latest ANL reports for carbon and low alloy steel [3] and stainless steel [4].

From NUREG/CR-5704 [4], the F. relative to room-temperature air for Types 304 and 316 stainless steel is given by the following expression:

F,.= exp(0.935 - T 0*)

The constants for transformed temperature (T*), transformed strain rate (i ), and transformed dissolved oxygen (O*) in the above expression are defined as follows:

"Fatigue crack initiation" is an investigator determined quantity, often related to a 25% load drop in a load-controlled laboratory fatigue test. This usually corresponds to significant crack depths, typically of the order of 25% of the specimen thickness for the deepest crack.

4-1

Guidancefor Perfonning Environmental Fatigue Evaluations T* = 0 (T < 2000C)

T*= 1 (T 2:. 20000)

T = metal service temperature, 0C S= 0 (t> 0.4%/sec)

"= e n(i"/0.4) (0.0004 _ *0.4%/sec)

"= f n(0.0004/0.4) < 0.0004% /sec)

, = strain rate, %/sec O = 0.260 (DO < 0.05 ppm)

O =0.172 (DO 0.05 ppm)

DO. = dissolved oxygen From NUREG/CR-6583 [3], the environmental correction factors relative to room-temperature 2

air for carbon steel and alloy steel are given by the following expressions For carbon steel: Fen = exp(0.585 -,0.00124 T - 0.101S* T* O' t *)

Substituting T = 25°C to yield an F - relative to room temperature air, the above equation becomes:

F,,' = exp(0.554.- 0.101S* TV O )

For low alloy steel: Fe. = exp(0.929 - 0.00124 T - 0.101S* T* O* 5)

Substituting T = 25°C to yield an F., relative to room temperature air, the above equation becomes:

\ FF,, = exp(O.898 - 0.101S* T*O' )

The transformed sulfur content (S ), transformed temperature (T), transformed dissolved oxygen (0), and transformed strain rate (i *) in the above expressions are defined as follows:

- It has been noted that several past license renewal applicants have substituted the maximum operating temperature for T in the second term of the F_, expressions (i.e., the" 0.00124 T" term) to represent the metal temperature.

Since all ASME Code fatigue applications throughout the industry are based on relating room temperature air data to service temperature data in water, T = 25°C should be used in the F,,, expressions for the "- 0.00124 T' term, rather than service temperature, as shown above.

4-2

Guidancefor Perfonning Environmental Fatigue Evaluations S* = S (0 < S_< 0.015 wt. %)

S* = 0.015 (S > 0.015 wt. %)

S = weight percent sulfur T* = 0 (T < 150°C)

T* = T - 150 (150 _<T_< 350°C)

T = metal service temperature, °C 0* = 0 (DO < 0.05 ppm) 0* = f n (DO/0.04) (0.05 ppm _< DO *0.5 ppm) 0* = e n (12.5) (DO > 0.5 ppm)

DO = dissolved oxygen

• 0 ( 1-/>1%/s) 6*= £n (6' (0.001 "1%/s) n (0.001) (6<0.001 %/s)

= strain rate, %/sec 4.2 Guidelines for Application of the Fen Methodology This section provides guidelines for performing environmental fatigue evaluations.

As introduced in Section 2.1, F s are determined and used to adjust the CUF previously determined using the ASME Code air curves. Bounding Fo, values may be determined or, where necessary, individual F., values are computed for each load pair in a detailed fatigue calculation.

The environmental fatigue is then determined as U-n = (U)x(Fo.), where U is the original incremental fatigue usage for each load pair, and U.,v is the environmentally assisted incremental fatigue usage factor. The total environmental CUF is computed as the sum of all U_ values for all load pairs.

Based on industry practice and recommendations available from some of the published Fe_

methods, there are three increasingly refined approaches used to compute the Fens:

Average strain rate r

" Detailed strain rate

• Integrated strain rate Common to each of these approaches is that the Fe. is computed for the load pair over the increasing (tensile) portion of the paired stress range only. In other words, the relevant stress range is determined first by assuming that the transient with the maximum compressive stress (or minimum tensile stress) occurs first in time, followed by the transient with the maximum tensile stress. The relevant stress range for Fe- computation is then from the maximum compressive stress (or minimum 'tensile stress) to the maximum tensile stress. Further details are given in the discussions that follow.

4-3

Guidancefor Performing EnvironmentalFatigueEvaluations A separate section follows for each parameter utilized in the F., expressions, that is transformed sulfur content (S*), transformed temperature (T*), transformed dissolved oxygen (0), and transformed strain rate (C *). For the transformed strain rate, temperature, and oxygen parameters, the three approaches are discussed. Transformed sulfur does not Vary over the three approaches. A single approach should be utilized for all of the transformed parameters in a single load-pair Fen determination, although different approaches may be utilized for different load-pair F,,s.

First, the typical content of a fatigue calculation is presented.

4.2.1 Contents of a Typical Fatigue Evaluation This section provides the content of a typical fatigue calculation. Whereas fatigue calculations have varied over the years, their basic content is the same. With the advent of computer technology, the calculations havre basically maintained the same content, but computations have become more refined and exhaustive. For example, 30 years ago'it was computationally difficult for a stress analyst to evaluate 100 different transients in a fatigue calculation. Therefore, the analyst would have grouped the transients into as few as one transient grouping and performed as few incremental fatigue calculations as possible. With today's computer technology and desire to show more margin, it is relatively easy for the modem-day analyst to evaluate all 100 incremental fatigue calculations for this same problem. Also, older technology would have likely utilized conservative shell interaction hand solutions for computing stress, whereas today finite element techniques are commonly deployed. This improvement in technology would not have changed the basic inputs to the fatigue calculation (i.e., stress), but it would have typically yielded significantly more representative input values.

The discussion here is limited to the general content of most typical fatigue calculations.

Discussions of removing excess conservatisms from the input (stress) values of thee calculations are not included, as it is assumed that those techniques are generally well understood by engineers performing these assessments throughout the industry.

Two typical fatigue calculations are shown in Figures 4-1 through 4-4. Figure 4-1 reflects an "old" calculation, i.e., one that is typical from a stress report from a plant designed in the 1960s.

Figures 4-2 through 4-4 reflect a "new" calculation, i.e., one that is typical from a 1990s vintage stress report. A description of the content of these two calculations is provided below.

The same basic content is readily apparent in both CUF calculations shown in Figures 4-1 through 4-4. However, it is also apparent that much more detail is present in Figures 4-2; through 4-4 for the "new" calculation compared to Figure 4-1. for the "old" calculation. Therefore, with respect to applying F., methodology to a CUF calculation, the guidance provided in the following sections equally applies to both vintages of calculations. The main difference is in assumptions that need to be made for the F,, transformed variables due to a lack of detail backing up the calculations in the stress report. Guidance for these assumptions is described in Sections 4.2.2 through 4.2.5, with appropriate reference to the calculations shown in Figures 4-1 through 4-4.

4-4

Guidancefor Performing Environmental Fatigue Evaluations 4.2.1.1 "Old" Calculation (Figure 4-1)

The following describes the basic contents of the CUF calculation shown in Figure 4-1. Note that this calculation is an NB-3200-style (vessel) CUF calculation. Reference is made to the heading and the first li'ne in the table shown at the bottom of Figure 4-1.

SMAX = maximum stress intensity for transient pair (ksi). For this example, it is seen that it represents the tensile stress for Transient "h" in the stress histogram above the CUF calculation table.

SMIN = minimum stress intensity for transient pair (ksi). For this example, it is seen. that it represents the compressive stress for Transient "in" in the stress histogram above the CUF calculation table.

SALT = alternating stress intensity (ksi). This is computed as 0. 5 (SMAX - SM N). It is noteworthy that K. and Young's Modulus corrections are not included in this

,calculation due to the early ASME Code edition used for the evaluation.

n number of applied cycles for transient pair. For this example, it is seen that this value represents the limiting number of occurrences for the paired transients (i.e.,

Transients "h" and "m"), which is 5 cycles from the stress histogram above the CUF calculation table. The occurrences of Transient "in" are now exhausted, and 5 cycles of Transient "h" remain for use in the remaining CUF calculation. --

N allowable number of cycles from the applicable ASME Code fatigue curve for the material under consideration for SALT. From the "*" note, ASME Code Figure N-415(a) applies (1960s ASME Code edition).

u incremental CUF for the load pair, computed as n/N.

UOV'ERALL total CUJF for this location for the design life of the component, computed as Zu.

4-5

Guidancefor Performing Environmental Fatigue Evaluations Figure 4-1 Example of "Old" Fatigue Calculation 4-6

Guidancefor Performing Environmental Fatigue Evaluations 4.2.1.2 "New" Calculation (Figures 4-2 through 4-4)

The following describes the basic contents of the CUF calculation shown in Figure 4-2, Note that this calculation is an NB-3600-style (piping) CUF calculation. References are also made to Figures 4-3 and 4-4 where necessary.

(Note: Near the top of the table shown in Figure 4-2, the maximum load case information is reported, i.e., the two lines beginning with "GELBOW" and "0.512" - the descriptions that follow apply to the information below these lines.)

Load Range = paired load cases, as defined in Load Case definitions (see Figure 4-3).

Equation 10 Momen t moment (ft-lbf), computed in accordance with Equation (10) of ASME Code,Section III, NB-3600.

Equation 10 Stress stress intensity (psi), computed in accordance with Equation (10) of ASME Code,Section III, NB-3600.

Equation 11 Momen t = moment (ft-lbf), computed in accordance/ with Equation (11) of ASME Code,Section III, NB-3600.

Equation 11 Stress stress intensity (psi), computed in accordance with Equation (11) of ASME Code,Section III, NB-3600.

Equation 12 Momen t moment (ft-lbf), computed in accordance with Equation (12) of ASME Code,Section III, NB-3600.

Equation 12 Stress stress intensity (psi), computed in accordance with Equation (12):of ASME Code,Section III, NB-3600.

Equation 13 Moment = moment (ft-lbf), computed in accordance with Equation (13) of ASME Code, Section 1II, NB-3600.

Equation 13 Stress stress intensity (psi), computed in accordance with Equation (13) of ASME Code,Section III, NB-3600.

Equation 14 KE - elastic-plastic strain concentration factor, K., computed in accordance with ASME Code,Section I.I, NB-3600.

Equation,14 Stress = alternating stress intensity (psi), computed in accordance with Equation (14)of ASME.Code,Section III, NB-3600.

Cycles Actual = number of applied cycles for the transient pair. For this example, the first load pair represents thermal Load Cases 24 and 36, coupled with dynamic Load Case 56 and (E)arthquake. From Figure 4-3, Load Case 24 represents Daily Power Reduction, Load Case 36 represents Vessel Flooding, and Load Case 56 represents OBE/SRV 4-7

Guidancefor Performing Environmental FatigueEvaluations dynamic loading. From the transient definitions (similar to those shown in Figure 4-4), the number of applied cycles for each load case is obtained. The fatigue analysis uses the limiting number of cycles for all of these loads, which is 10 cycles.

Cycles Allow allowable number of cycles from the applicable ASME Code fatigue curve for the material under consideration for "Equation 14 Stress".

Usage Factor = incremental CUF for the load pair, computed as "Cycles Actual"/"Cycles Allow".

The total CUF for this location for the design life of the component, computed as Zu, is shown at the top of the table in the summary portion (i.e., 0.6512).

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,Example of "New" Fatigue Calculation - CUF Calculation f

4-8

Guidancefor Performing EnvironmentalFatigue Evaluations LOADCASE NUMIBER DESCRIPrBS LOADCASE XOMBED DESCRIPTIBON o UpSet NOjo: Conditioy) (Run 004)

I PT FLUID TRANSIENTTIME HISTORY (31-PMP-TRIP) 2 OBEI- OZE IERTIA ..... ROUPINGBY ST*DSDSS 41 THERM27- LOSS OF P0 PUMP:{(UP) (20-1..) 420-573-4B5 3 SSEI SSE INEIA ..... OUPINGBY S SRSS 42 THERM28- PIPE RUPTURE: (27-1.2) 420-259-70 4 SR (1V,2V, SVCO2V) .. ::..... :GROUPING BY BID SRSS 43 THENM29- STA*T-UP:{DH) (30A-3..) 486-70 5 DRV (16VSRVCOI6V) ......... GROUPI BY D ST RSS 44 THERM30- START-UP:{SB) (3B-3) E86-180 6 COCE- CONDEN$.OSCILL& CHUGGING ........ GROUPINGBY SOD SRS 45 THEM 31- 5)31-DOWN INErD : ID}O (LB-3) 395-149 7 PS- POOL SWELL ............... GROPING BY STD SBSS 49 THEE 32- LOSS OF FWP:{D}) (20-13104) 4E5-70 SAPmSB ANNULUSPEDBSEITB m.S.B... GROUPING BY sBO 5s50 E 4s THEM 33. T00DS 2 WITH -0 SPSI B APRC- ANNULS PRESSURIZATIONR.C., .... GOUPING BY STD SRS3 THE9M 34- THOSE 00 WITH P-1516 PSI LB APFWB- ANNLUS PRESUR17ATION P.W.BE....OGROUING BY STD SDSB THERE) 3D. 040DB Is WITH 9-1105 PSI Li DL- DEADWEDIGT ANALYSIS:TLOAD3,( FSH - CLDSET LOAD) 51 xBY DIR. ODB ANCHOR VTS ......... CASES 12-13BY ODDS 12 X-DIR OBE ANCHOBHOTS OBm. D.D EARTHQBARUE ANCHOR ES.... CA.SS 12-13+14 BY DOSS 13 Y-DIR OBE ANCHORKVMT 52 DRY- (DBRV M30) . . . C... 4+5 BY MAXIMUM VALUE 14 Z-DIR ObE ANCHORM3490 53 VS(SRV,7) .............. CASES 02.0 BY DOSS Ls THENN I* ORMALOPEPATIBG: (12) P0 @ 420/620/420 F DPV 0 552/528/S21 54 ORSS(0BEI,)CC). EDS(OBEI,SRV,DT).. CASES -2+52-1 BY SSS 1B TKEM 2: TRD DOLL COLD: ()4-I..) PPG 0 70/70/70 F RPV 552/552/45( 55 OBET- A*S(OBED ) ..... CASES 2.51 BY ADS. S50 17 THERM3- LT-UP,LEAM TEST: (3A-I..)70-100 56 DSRS(OBET,OCCU)- RBSS(ADS(OBEI+BBEA),SRV.FT)..CASESD5D53BY SR55 1B TH0ERM 4: HYRBOTE: (2A) 100-18-100 51 SRSS)OBEB.0T)......... CASES 0.3 BY SASS (FOD 9C0 CARD0)N.Y) 19 TOHERM B- BARTUDP:{UP} (3i-2..) ODD*-B6 FrT PLUID TRANSIENTTIM BBSTYOY(3 PUMP-TRIP) .... (FOR

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4-9

Guidancefor Performing Environmental Fatigue EvalIuations

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.1 .*-*-* 41-0 ~  % ArmestRC4C . I L' 2T -1,5.0 7,1,0 ,.Alflt s'Sl~t xfsx- ('-iiwi')

6.13? oteot Acy11(5 sSIWAE £FS 1'I%0. A0- %7DATED 2,40-BA4 A4Jn.

Figure 4-4 Example of "New" Fatigue Calculation - Transient Definitions 4-10

Guidancefor Performing Environmental Fatigue Evaluations 4.2.2 Transformed Strain Rate, *

• The transformed strain rate, * *, is required by both the carbon and low alloy steel Fon expressions documented in NUREG/CR-6583 [3], and the stainless steel Fen expression documented in NUREG/CR-5704 [4], and is defined as follows:

For carbon/low alloy steels (NUREG/CR-6583 [3]):

(> 1%/s)

' = n ((0.001 s 1%/s)

• =.e n (0.001) ( <0.001 %/s) strain rate,,%/sec For stainless steels (NUREG/CR-5704 [4]):

"= 0 (> 0.4%/sec)

= f n(t/0.4) (0.0004*eE"< 0.4%/sec) f=n(0.0004/0.4) ( < 0.0004% /sec)

= strain rate, %/sec The above expressions are straightforward to apply if the strain rate, i, is known. This can be relatively straightforward for design transients where definitive ramp rates and temperature differentials are provided. It is much more difficult for actual transients obtained from actual plant data or fatigue monitoring systems. In particular, how two transients that occur separately in time are "linked" together (as shown in Figure 4-9) can have a significant influence on strain rate calculations depending upon the method used.

Section 4.3 discusses other issues associated with calculating the strain rate when applying the F., expressions. Solving those other issues is beyond the scope of this report, so guidance is provided in this section to address only the above three methods of computing strain rate.

Consistent with some of the calculations performed in NUREG/CR-6260 [2], for cases where the magnitudes of the portions of the stress range due to heatup and cooldown are unknown (i.e.,

only the total stress intensity range is known), or fof cases where the stress histories are not available, one-half of the alternating stress intensity may be used to compute strain rate. This is done in the sample problem shown in Section 4.2.7, but it requires that some form of time history information be available for the transient to justify strain rates greater than the slowest saturated strain rate. Parametric studies could also be used to justify time assumptions.

4 4-11

Guidancefor Performing Environmental Fatigue Evaluations Discussion for each of the three Average, Detailed, and Integrated Strain Rate approaches follows.

Approach #1: Average Strain Rate The Average Strain Rate approach is simple in that it is based on "connecting the valley with the peak with a straight line and computing the slope." Referring to Figure 4-9, this represents the slope of a line drawn from the lowest stress point of the heatup (maximum compressive) event (i.e., left side of Figure 4-9), to the highest stress point of the cooldown (maximum tensile) event (i.e., right side of Figure 4-9). But, as shown in the area between the two events in Figure 4-9, linking of the two transients is not necessarily straightforward. There are two issues associated with the proper linking of the two events:

" For the maximum compressive stress transient (i.e., left side of Figure 4-9), the return (tensile) side of the transient is important for the strain rate calculation. An estimate of the time until steady state conditions are reached is needed.

" The ending stress for the maximum compressive stress transient (i.e., left side of Figure 4-9) may be different than the beginning stress for the maximum tensile stress transient (i.e., right side of Figure 4-9). This difference causes a discontinuity in the linking process.

The following guidance is provided for each of the above issues:

" For steady state conditions associated with the return (tensile) side of the maximum compressive stress transient, the time for the stress to reach at least 90% of the steady state stress value can be used. This involves a steady state stress solution that includes a time-based solution, which is readily available in most stress analyses, and is readily achievable with the use of all modern-day stress programs.

• For stress discontinuities that exist between the ending stress for the maximum compressive stress transient and the beginning stress for the maximum tensile stress transient, the transients can be linked with a vertical line between the two stress points (i.e., no elapsed time).

Under the above assumptions, the Average Strain Rate iscomputed as:

= 100AG/(AtE)

'where: e average strain rate, %/sec Ac = total stress intensity range

= stress difference between the highest stress point of the maximum tensile stress event (i.e., right side of Figure 4-9) and the lowest stress point of the maximum compressive stress event (i.e., left side of Figure 4-9), psi At = time between peak and valley, sec 4-12

Guidancefor Performing Environmental Fatigue Evaluations time lapse from the event start to the algebraic highest stress point of the maximum tensile stress event (i.e., right side of Figure 4-9) plus the time lapse from the algebraic lowest stress point of the maximum compressive stress event (i.e., left side of Figure 4-9), to the time for the stress to reach at least 90% of the steady state stress value, sec.

E Young's Modulus, psi, normally taken froim the governing fatigue curve used for the fatigue evaluation.

Approach #2: DetailedStrain Rate The Detailed Strain Rate approach is similar to the average approach discussed above, except that a Neighted strain rate is obtained based on strain-based integration over the increasing (tensile) portion of the paired stress range. Referring to Figure 4-9, this represents the integrated slope of strain response from the algebraic lowest stress point of the maximum compressive stress event to the algebraic highest stress point of the maximum tensile stress event, weighted by strain. Similar to the average approach discussed above, linking of the two transients in not necessarily straightforward. However, the two issues associated with the proper linking of the two events that are identified above are less pronounced because of the integration process.

Nevertheless, aspects of these issues remain, so the following guidance is provided for each of those issues:

• For steady state conditions associated with the return (tensile) side of the maximum compressive stress transient, the time for the stress to reach at least 90% of the steady state stress value can be used. This involves a steady state stress solution, which is readily available in most stress analyses, and is readily achievable with the use of all modern 7 day stress programs.

• For stress discontinuities that exist between the ending stress for the maximum compressive stress transient and the beginning stress for the maximum tensile stress transient, the discontinuity can be ignored.

Under the above assumptions and referring to Figure 4-5, the Detailed Strain Rate is computed as:

100 Ac, AE At SAc, where: c = detailed strain rate, %/sec Ai= change in strain at Point i, in/in (C51-- j,,)/E G = stress intensity at Point i, psi i_,= stress intensity at Point i-1, psi At = change in time at Point i, sec

= t - ti.I E = Young's Modulus, psi, normally taken from the governing fatigue curve used for the fatigue evaluation.

4-13

Guidancefor Performing EnvironmentalFatigue Evaluations The summation is over the range from Point (3) to (4) and the range from Point (1) to (2). In the figure, Points (1) and (4) are assumed coincident. Point (4) is actually taken as the point where the stress returns to at least 90% of the steady state stress value. The strain discontinuity between this point and Point (1) is accounted for by omitting this increment from the total strain range in the denominator.

If two tensile transients are being ranged, the summation ranges from the algebraic minimum of, the two Point (1)s to the algebraic maximum of the two Point (2)s. If two compressive transients, are being ranged, the summation ranges from the algebraic minimum of the two Point (3)s to the algebraic maximum of the two Point (4)s. If a tensile transient is being ranged with itself (its

'zero' state), the summation ranges from Point (1) to Point (2). If a compressive transient is being ranged with itself (its 'zero' state), the summation ranges from,Point (3) to Point (4) with Point (4) again taken where the stress returns to at least 90% of the steady state stress value.

Approach #3: Integrated Strain Rate The Integrated Strain Rate approach is similar to the detailed approach discussed above, except that an Fen factor is computed at multiple points over the increasing (tensile) portion of the paired strain range, and an overall F. is integrated over the entire tensile portion of the strain range (i.e.,

from the algebraic lowest stress point of the maximum compressive stress event to the algebraic highest stress point of the maximum tensile stress event in Figure 4-9). Thus, this process is more specifically an "integrated F., approach", where strain rate is computed as a part of the process. Similar to the two approaches discussed above, linking of the two transients remains an issue with this method. However, similar to the detailed approach, the two issues associated with the proper linking of the two events are less pronounced because of the integration process. The following guidance is provided for each of those issues:

" For steady state conditions associated with the return (tensile) side of the maximum compressive stress transient, the time for the stress to reach at least 90% of the steady state stress value can be used. This involves a steady state stress solution, which is readily available in most stress analyses, and is readily achievable with the use of all modem-day stress programs.

• For stress discontinuities that exist between the ending stress for the maximum compressive stress transient and the beginning stress for the maximum tensile stress transient, the discontinuity can be ignored.

Under the above assumptions and referring to Figure 4-5, the Integrated Strain Rate F.. is computed as:

Z Fen,iAei where: F,,, F o computed at Point i, based on t 100Ac!/At and transformed parameters (T). and (0) computed using the respective Integrated Strain Rate S

approaches for each, discussed below.

A~i = change in strain at Point i, in/in 4-14

Guidancefor Performing Environmental FatigueEvaluations stress intensity at Point i, psi stress intensity at Point i-1, psi At change in time at Point i, sec

= t-t E Young's Modulus, psi, normally taken from the governing fatigue curve used for the fatigue evaluation.

The summation is over the range from Point (3) to (4) and the range from Point (1) to (2). In the figure, Points (1) and (4) aire assumed coincident. Point (4) is actually taken as the point where the stress returns to at least 90% of the steady state stress value. The strain discontinuity between this point and Point (1) is accounted for by omitting this increment from the total strain range in the denominator.

If two tensile transients are being ranged, the summation ranges from the algebraic minimum of the two Point (1)s to the algebraic maximum of the two Point (2)s. If two compressive transients are being ranged, the summation ranges from the algebraic minimum of the two Point (3)s to. the algebraic maximum of the two Point (4)s. If a tensile transient is being ranged with itself (its

'zero' state), the summation ranges from Point (1) to Point (2). If a compressive transient is being ranged with itself (its 'zero' state), the summation ranges from Point,(3) to Point (4) with Point (4) again taken where the stress returns to at least 90% of the steady state stress value.

L (D

e= (El C (Ef 6) e-tsn Transient A Tmrel9TaminA Refer to the discussion above for Approaches

1. 2 (Detailed Strain Rate) and #3 (Integrated IMminmu Strain Rate) for instances where Point (4) does not coincide with Point (1).

07 72 Transient B Figure 4-5 Detailed and Integrated Strain Rate Calculation 4-15

Guidancefor Performing Environmental FatigueEvaluations 4.2.3 Transformed Sulfur Content, S*

The transformed sulfur content, S*, is required, only by the carbon and low alloy steel Fen expressions documented in NUREG/CR-6583 [3], and is defined as follows:

S*=S (0 < S*< 0.015 wt. %)

S* = 0.015' (S > 0.015 wt. %)

S = weight percent sulfur There are no ambiguities associated with computing S*, as it is a function of the material sulfur content for the location under consideration. Normally, sulfur content would be obtained from Certified Material Test Reports (CMTRs) that are usually readily available. However, due to the secondary effect of this variable in the Fe. expressions, most analyses to-date have assumed high sulfur content (i.e., S* = 0.015) for simplicity.

4.2.4 Transformed Temperature, T*

The transformed temperature, T*, is required by both the carbon and low alloy steel Fee expressions documented in NUREG/CR-6583 [3], and the stainless steel Fe. expression documented in NUREG/CR-5704 [4], and is defined as follows:

For carbon/low alloy steels (NUREG/CR-6583 [3]):-

T* = 0 (T < 150 0 C)

T* = T - 150 (150 *< T* 350°C)

T = metal service temperature, 0C For stainless steels (NUREG/CR-5704 [4]): ,

T* = 0 (T < 200'C)

T*= 1 (T >_.2000C)

T = metal service temperature, °C The above expressions are straightforward to apply if the metal service temperature, T, is known.

As discussed in Section 4.3, there are other issues associated with temperature when applying the Fe, expressions. Generally, the issue is, "what temperature should be used for the general transient pairing shown in Figure 4-9?" The answer to this question is dependent upon the refinement on the evaluation used to compute the Fen factor. As discussed above at the start of Section 4.2, there are three increasingly refined approaches used to compute the Fen factor:

Average, Detailed, and Integrated Strain Rate.

4-16

Guidancefor Performing EnvironmentalFatigueEvaluations The following recommendations are made for determining the temperature, T, for each of the above three approaches:

Aypproach #1: F,_ FactorCalculatedBased on Average Strain Rate Calculation For this approach, a constant temperature that is the maximum of the fluid temperatures of both paired transients over the'time period of increasing tensile stress should be used. Referring to Figure 4-9, this would include the maximum temperature that occurs during any of the following time periods:

• For the maximum compressive stress transient (i.e., left side of Figure 4-9), beginning at the time of algebraic minimum stress until the end of the transient.

For the maximum tensile stress transient (i.e., right side of Figure 4-9), beginning at the start of the transient until the time of algebraic maximum stress.

Fluid temperature is an acceptable substitute for the above specified metal temperature in that fluid temperature is more readily available in CUF calculations, as it is a required input with respect to transient definitions. This is true for both older-vintage and modern-day evaluations.

Since the maximum fluid temperature envelopes any metal temperature, this is conservative.

Approach #2: F Factor CalculatedBased on DetailedStrain Rate For this approach, the maximum fluid temperature of both paired transients over the time period of increasing tensile stress should be used (i.e., same as Approach #1 above).

Approach #3: F Factor CalculatedBased on Integrated Strain Rate For this approach, F- is computed in an integrated fashion at multiple points between the transient pair stress valley and peak. For this case, the maximum metal temperature of both local time points considered over the period of increasing tensile stress should be used. Referring to Figure 4-5, this represents the maximum of Points i and i-1, or T = MAXIMUM(T,, T,-,). Metal temperature is more appropriate and avoids potential excess conservatism that would result from using fluid temperature in a heating evenit and inappropriate omission of effects in a cooling event.

For all three approaches described above, a conservative, simplified, and bounding evaluation would be to use the maximum operating temperature for the component location being evaluated.

Note that it is not obvious that the use of maximum temperature in the Foo expressions is bounding (due to subtraction of the temperature terms), but routine application of the expressions has demonstrated that the use of the maximum temperature is bounding in all of the Fe, expressions. This is also shown in Figure 4-6, which shows F , values as a function of temperature.

4-17

Guidancefor Performing Environmental Fatigue Evaluations Stainless Steel Fen 18.0 T 16.0 Low 02 + Lowz

, Low 02 + Int.

1 - - Low 02+Hight 14.0 - High 02 +'Low

- - - High 02 + Int.

9 n . ...... High 02 + High i 0/

1'0.0 L-8.0 6.0 4.0 2.0 0.0 275 325 375 425 475 525 575 Temperature, 'F Carbon Steel Fen 160

- High 02 - Low t High 02 - Int. t

-- High 02 + High t 120 t-Int.02 + Lowt

- - - Int. 02 + Int. t 100*

---

Int. 02 + Hight LOw02 + LOwL 80 60-40 20-150 200 250 300 350 400 450 500 550 600 650 Temperature, *F Figure 4-6 Fen Values as a Function of Temperature 4-18

Guidancefor Performing Environmental Fatigue Evaluations 4.2.5 TransformedDissolved Oxygen, 0*

The transformed oxygen, 0*, is required by both the carbon and low alloy steel Fe, expressions documented in NUREG/CR-6583 [3], and the stainless steel F., expression documented in NUREG/CR-5704,[4], and is defined as follows:

For carbon/low alloy steels (NUREG/CR-6583 [3]):

O* = 0 (DO < 0.05 ppm) 0* = t n (DO/0.04) (0.05 ppm _DO _ 0.5 ppm) 0* = g n (12.5) (DO > 0.5-ppm)

DO = dissolved oxygen For stainless steels (NUREG/CR-5704 [4]):

O = 0.260 (DO < 0.05 ppm)

O = 0.172 (DO Ž_0.05 ppm)

DO = dissolved oxygen The above expressions are straightforward to apply if the dissolved oxygen level, DO, is known.

Although DO measurements are normally available through routine chemistry measurements, they are typically very limited with respect to frequency of collection and locations collected in the reactor coolant system (RCS). Therefore, there 'are several difficulties associated with determining the DO that is appropriate for use in the F., expressions:

• The DO level is not known at the component location being evaluated. For example, it is the DO directly at the surface of the component that is required, e.g., for a BWR component exposed to saturated steam, the (much lower) DO in the condensate film is really what is applicable to an environmental fatigue analysis, not the much higher DO content of the steam itself.

• The DO level is not known at all times during a transient (i.e., perhaps'DO data is only collected once per day as opposed to confinuously during a transient).

As discussed in Section 4.3, there are other issues associated with DO ,when applying the Fen expressions. Solving those other issues is beyond the scope of this report, so guidance is provided in this section to address only the above two issues and answering the question, "what DO level should be used for the general transient pairing shown in Figure 4-9?" As with T*, the answer to this question is dependent upon the refinement on the evaluation used to 'compute the F_, factor. Section 4.2 contains the definitions and details for each of these three approaches.

The following_ recommendations are made for determining the dissolved oxygen, DO, for each of the three approaches:

4-19

Guidancefor Performing Environmental FatigueEvaluations Approach #1: F Factor CalculatedBased on Average Strain Rate Calculation For this approach, the maximum DO level (for carbon and low alloy steels), or the minimum DO level (for stainless steels) of both paired transients over the time period of increasing tensile stress should be used. Referring to Figure 4-9, this would include the maximum (or minimum)

DO level that occurs during any of the following time periods:

" For the maximum compressive stress transient (i.e., left side of Figure 4-9), beginning at the time of algebraic minimum stress until the end of the transient.

• For the maximum tensile stress transient (-i.e., right side of Figure 4-9), beginning at the start of the-transient until the time of algebraic maximum stress.

\.

Approach #2: F Factor CalculatedBased on Detailed Strain Rate For this approach, the maximum DO level (for carbon and low alloy steels), or the minimum DO level (for stainless steels) of both paired transients over, the time period of increasing tensile stress should be used (i.e., same as Approach #1 above).

Approach #3:. F FactorCalculated Based on Integrated Strain Rate For this approach, F-n is computed in an integrated fashion at multiple points between the transient pair stress valley and peak. For this case, the maximum DO level (for carbon and low alloy steels), or the minimum DO level (for stainless steels) of both local points considered over the time period of increasing tensile stress should be used. Referring to Figure 4-5, this represents the maximum of Points i and i-1 (DO = MAXIMUM[DO, DOJ]) for carbon and low alloy steels, or the minimum of Points i and i-i (DO MINIMUM[DO, DO,]) for stainless steels.

For all three approaches described above, the following guidance is provided for establishing the DO level:

" In rare cases, DO level measurements are available at or near the component location being evaluated via plant instrumentation. For this case, the plant data is used directly for DO.

" In the majority of cases, DO level measurements are available at periodic intervals during plant operation. These measurements are routinely made remotely from the component location of interest. In some cases, the remote reading may be valid for application at the component location. For these cases, "typical" values can normally be determined based on consultation with the plant chemistry personnel. The typical values should be used with a brief write-up describing the basis for the values. Consideration should be given for variations in the DO level, i.e., consideration of bounding values, as described below, should be factored into the estimates.

• For cases where DO levels have changed over the course of plant operation (i.e., implementation of HWC after plant startup), a time-based average DO level is recommended, based on expected DO levels, as follows:

4-20

Guidancefor Performing Environmental FatigueEvaluations DO = DO 1 Time, + DO 2 Time 2 + DO 3 Time 3 +

Time1 + Time 2 + Time 3 +

where: DO time-averaged DO level DO[ average DO level for time period Time, Time, time period #1 where DO level was relatively constant DO 2 average DO level for time period Time 2 Time 2 = time period #2 where DO level was relatively constant DO 3 = average DO level for time period Time 3 Time 3 time period #3 where DO level was relatively constant etc.

Thus, for a case where a BWR operated 20 years under NWC (typical DO = 200 ppb), 10 years with 50% HWC availability (typical DO = 5 ppb), and is projected to complete operation to 60 years with 95% HWC availability, the following DO level is calculated:

'DO =(200x20) + (200x0.5x10) + (5x0.5x10) + (5x30) = 86.25 ppb (20+10+30)

Alternatively, F., factors could be computed for each time period and an overall Fen factor calculated based on the weighted average, as follows:

Fn,2o0 ppb x20.-+ IF,,211 ppb x 0.5 x 10 + Fn,5 ppb x 0.5 x 10 +

+ Fe,5xppb x30 e, =(20+10+30)

Another alternative method involves assigning a DO value to each logged transient according to the date it occurred. This is more involved than the above in that the range pair table would need to be apportioned into subsets over the past and future history of the unit and the incremental U-s re-calculated: An approximation of this would be to do a simple apportioning of the range pair U-s according to an assumed linear distribution of the occurrences, n, over the past and future historical DO values.

Similar to that described for T*, a simplified, conservative and bounding evaluation would be to use the maximum DO level (for carbon and low alloy steels), or the minimum DO level (for stainless steels) for the component location being evaluated. Note that it is not obvious that the use of these maximum or minimum DO levels in the F_ expressions is bounding (due to subtraction of the oxygen terms), but routine application of the expressions has demonstrated that the use of the maximum DO level is bounding in all of the F., expressions for carbon and low alloy steels, and the minimum DO level is bounding in all of the F., expressions for stainless steels. This is also shown in Figure 4-7 which shows F_, values as a function of DO level.

4-21

Guidancefor Performing Environmental Fatigue Evaluations Stainless Steel Fen 18.0 High T + Low E 16.0 High T + Int.

- - High T + HighE Low T + Low 14.0 ! - - -- Low T + Int. i Low T + High -----

C 12.0 10.0*

8.0k I

6,0 4.0k 2.0 J 0'0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.10 Dissolved Oxygen, ppm Carbon Steel Fen 160 140 1

120 100

" 80 60 40 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 Dissolved Oxygen, ppm Figure 4-7 Fe,, Values as a Function of DO Level 4-22

Guidancefor Performing Environmental Fatigue Evaluations 4.2.6 Additional Considerations The following additional considerations are provided for the above guidance:

Dynamic Loading: For load pairs in a CUF calculation that are based on seismic or other dynamic loading, Fe, = 1.0 for the dynamic portion of the strain for the load pair in question.

This is based on the premise that the cycling due to dynamic loading occurs too quickly for environmental effects to be significant. The remaining portion of the strain range should be treated the same as discussed elsewhere in this guideline.

• Thermal Stratification Loading: For load pairs in a CUF calculation that are based solely on thermal stratification loading, the strain rate can generally be taken as the minimum strain rate that produces the maximum environmental effect. Alternatively, the strain rate effects can be determined as for any other cycle pair.

• Pressure and Moment Loading: The stresses for all load pairs in a CUF calculation typically contain stresses due to pressure and moment loading (i.e., non-thermal loads). All of the /

laboratory testing that forms the basis for the F expressions was conducted with alternating strain as a result of mechanical loadings, which would be analogous to pressure and moment loadings. Thus, the Fes, as determined herein, should be applied to the strain ranges for cyclic pressure and moment the same as for rapid thermal effects. The effects should be considered appropriately in the Detailed and Integrated' Strain Rate approaches if the available stress histories account for different rates of strain for cyclic pressure and moment strains.

K: The stresses for some load pairs in a CUF calculation can contain the effect of K. The K, factor causes a higher strain, thus increasing the strain rate that would be computed for affected load pair, which in turn lowers the Fe, factor. The strain rate should instead be based on a stress history for the load pair with Ke effects removed.

4.2.7 Sample Calculation As a demonstration of the guidance provided in Sections 4.2.2 through 4.2.5, a sample problem is provided here based on the "old" fatigue calculation shown in Figure 4-1. The completed environmental fatigue calculation is shown in Figure 4-8.

In the upper portion of Figure 4-8, the original design CUF calculation is reproduced, yielding a total CUF of 0.0067. The only additional information in this step is the total stress intensity range, SR, is computed (= Smax - Smin).

Then, environmental fatigue effects are evaluated'using two approaches. Each of these approaches is described below.

Case #1: Bounding F_ Multiplier For this case, since the design CUF is so low, a conservative (but very simple) approach is taken.

The maximum possible Fe, multiplier is determined and applied to the CUF result. Using the rules for low alloy steel documented in Section 4.1, the maximum Fen multiplier is computed as 2.45. The environmental fatigue usage factor, U,,,, is then computed as CUF x Fon = 0.0164.

)

',, 4-23

Guidancefor PerformingEnvironmentalFatigue Evaluations Case #2. Compute F Multipliers For Each Load Pair For this case, a more refined approach is taken compared to the first approach. Fo, multipliers are computed for each load pair. Using the rules -for low alloy steel documented in Section 4.1, the overall Fon multiplier is also 2.45 for this approach, since the F., does not vary with temperature due to the low DO. The environmental fatigue usage factor, U, . for this case is also computed as 0.0164.

The following descriptions are provided for the calculations for Load Pair #1:

Salt alternating stress intensity from design CUF calculation, psi t time for tensile portion of stress range in load pair, sec. Obtained from stress report from the tensile portions of both transients = 3 seconds.

Strain Rate computed using the Average Strain Rate approach as 100(Salt/2)/(Et) 100(58.77/2)/(30,000x3) = 0.03265%/sec MAX T maximum fluid temperature for tensile portion of stress range, 'F. Obtained from stress report from the tensile portions of both transients 550°F.

T* = T-150 since T> 150'C (550'F = 287.8'C) = 287.8 - 150 = 137.8 0* 0 since DO < 0.05 ppm (5 ppb = 0.005 ppm) c-dot* In(Strain Rate) since 0.001 < Strain Rate 11%/sec. ln(0.03265) = -3.422 Fe-, = exp(0.898- 0.101S*T*O*e-dot*

exp(0.898 - 0.101x0.015x137.8xOx-3.422) exp(0.898) 2.45 4-24 4-24

(

Guidancefor Performing EnvironmentalFatigue Evaluations Design Basis CUF: 00067

Reference:

Design Basis CUF Calculation Shown in Figure 4-2 Material: SA-336 (Low alloy steel)

Young's Modulus, E = 3.00E+07 psi DO Level = 5 ppb (always)

Transformed sulfur content. S" = 0.015 (assume maximum)

Smax Smin SR Salt n N U 41.12 -7641 117.53 58.77 5 1,860 0.0027 41.12 -3.55 44.67 22.34 5 40,020 0.0001 32.33 -2.69 ! 35.02 17.51 40 95,650 0.0004 30.12 -2.69 32.81 16.41 460 133,000 0.0035 25.05 11.74 13.31 6.66 400 >le8 0,0000 Note: Abovestress are inksi, Total CUF = 0.0067 (Design CUFis reproducedl)

Approach #1: Use a Bounding F_ Multiplier Low Alloy Steel: Fen.= exp(0.898 - 0.101S*T*O**v*)

Reference:

NUREG/CR-6583 For a DO = 5 ppb = 0.005 ppm, O* = 0, 8

Therefore, Fen is constant vs. T = exp(0.89 ) = 2.45:

Maximum F., = 2.45 U... CUF*F., = 0.0164 (< 1.0so acceptable!)

Approach #2: Compute F_, Multipliers for Each Load Pair; t Strain Rate MAXT Salt )sec) (%/sec) (°F) T 0

0. s-dot* F.n n N U*F,,

58.77 3 3.26E-02 550 137.8 0.00 -3.422 2.45 5 1.860 0.0066 22,34 15 2.48E-03 450 82.2 0.00 -5.999 2.45 5 40,020 0.0003 17.51 100 2.92E-04 325 12.8 0.00 -6.908 2.45 40 95,650 0.0010 16.41 1000 2.73E-05 250 0.0 0.00 -6.908 2.45 460 133,000 0.0085 6.66 300 3.7011-05 150 0.0 0.00 -6.908 2.45 400 >1e6 0.0000 Note: Above stress are in ksi. Total = U... = 0.0164 Overall F., = Uv1CUF = 2.46

(< 1.0 so acceptable!l Figure 4-8 Sample Environmental Fatigue Calculation 4.3 Issues Associated With Fen Methodology J As a result of industry application of the F_, relationships summarized in Section 4.1, there have been several issues identified associated with practical application of the methodology to typical

-industry fatigue evaluation problems. These issues have led to application of a variety of different solutions applied-by analysts depending upon the analyst or the level of detail available in the existing fatigue evaluations. This varied approach has led to non-consistent application of the Fen approach between plants, and some amount of confusion amongst the industry.

This guideline document is formulated based on the current "state of the art" with respect to. the F,, methodology. In many respects, the current state of the technology with respect to the Fe, methodology is incomplete or lacking in detail and specificity. Recommendations are made in this guideline where needed to fill in these missing details. Further work should focus on the issues associated with areas where the technology is lacking. Some of the issue areas that are associated with the F ,, methodology are summarized below ("10" indicates where this guideline provides recommendations):

4-25

Guidancefor Performing Environmental Fatigue Evaluations Issues of Test vs. Application

• There must be more communication between the people performing tests and those who must perform the analysis. This is one driving force behind the biannual series of "Fatigue Reactor Components" conferences that were started by EPRI in 2000. The proceedings of the most recent 2004,meeting (to be published 2005) contain several papers that address this specific issue.

• Testing for environmental effects has resulted in some rules foranalysis that are not consistent with real component transient response:

- Testing involves constant load/unload cycling, while real transients are separated in time,,

involve various stress magnitudes and non-constant rise times.

- Hold time at an intermediate stress level or random load magnitude cycling has notbeen adequately considered in environmental testing, although some work outside the U.S. has addressed these issues.

- The "real world" is different than laboratory tests, i.e., loading rates are random as opposed to carefully controlled ("ramped" or "saw-toothed") loads applied in the laboratory.

• Strain hardening effects may affect the results of fatigue testing at high cycles.

" May also need more nickel alloy data.

Issues of Analysis and Evaluation

" "Linking" of transients pairs is not 5traight-forward and can lead to significant differences in results (refer to Figure 4-9):

- How do you treat cases where the starting and ending stress points are not equal?

- What rate of change do you assume for the discontinuity between transients?

/

- What is strain rate?

[D This guideline makes recommendations in' Section 4.2.2 for addressing this issue.

Work is also ongoing within the EPRI BWRVIP program to investigate alternative approaches to this issue with regard to ASME Section XI calculations [25].

• Some have qiiestioned the adequacy of Miner's Rule for fatigue analysis and that perhaps design fatigue curves should have a factor to account for this.

- On the other hand, methods such as Rainflow Cycle Counting will generally show that the use of Miner's Rule with ASME Code analysis is conservative.

" For the purpose of component analysis for environmental effects, perhaps special stress indices and analytical methods need to be. developed to distinguish between inside (fluid exposed) surfaces and external (air exposed) surfaces.

• Effect of elastic-plastic correction factor (K.) on strain rate.

- To neglect is conservative - how to eliminate conservatism?

0 This guideline makes recommendations in Section 4.2.6 for addressing Ke.

4-26

Guidancefor Performing Environmental FatigueEvaluations 0 The Fo, formulations for stainless steel are based on the NUREG author's own mean stainless steel S-N curve in air, which is different than the ASME mean S-N curve over the high cycle portion of the curve. Therefore, inconsistencies are present in the application of the F_,

methods since these studies. (and most applications of F,, being performed throughout the industry) apply F,, factors to fatigue results that use the ASME S-N curve.

Analysis Issues: Different Loadings How are stratification loads addressed?

10 This guideline makes recommendations in Section 4.2.6 for addressing stratification loads.

How are seismic loads addressed?

10 This guideline makes recommendations in Section 4.2.6 for addressing seismic and other dynamic loads.

How are pressure and moment loads addressed?

10 This guideline makes recommendations in Section 4.2.6 for addressing cyclic pressure and moment strains.

Analysis Issues: Oxygen

• Environmerital fatigue is typically linked to dissolved oxygen. As previously mentioned, this involves inappropriate over-simplification and. ignores the key role of other water chemistry parameters such as conductivity (or more correctly, level of dissolved anionic impurities) and pH. Even with regard just to dissolved oxygen, however:

- Experts say oxygen is not the correct parameter - should be electrochemical potential (ECP), which is affected by the overall balance of oxidants and reductants in the water, as well as by temperature, flow, surface condition, etc. ECP, rather than dissolved oxygen, is the control parameter used in BWR water chemistry guidelines in the context of stress corrosion cracking mitigation.

- Hydrogen water chemistry (HWC) may produce much different results, as the oxygen level is significantly lowered for HWC operation (for some locations).

What oxygen level to use?

• Time history during transients not generally available.

• Value at component location not generally available.

• What about different periods of operation, i.e., NWC for first 15 years, then intermittent HWC, then reliable HWC?

• If time historyis available-

• Maximum or minimum of transient?

• Maximum or minimum local?, i.e., MAX(D01 , DO.)

• Maximum or minimum between peak and valley?

R1 This guideline makes recommendations in Section 4.2.5 for addressing varying historical oxygen levels.

4-27

Guidancefor Performing Environmental Fatigue Evaluations Analysis Issues. Temperature Temperature:

- What temperature to use?

• Metal? (not generally available)

• Fluid?

• Maximum of transient?

• Maximum local?, i.e., MAX(Ti, Ti_,)

• Maximum between peak and valley?

I] This guideline makes recommendations in Section 4.2.4 for addressing temperature.

Analysis Issues: Defining Design Loads

• The strain range (and therefore the CUF) decreases as an imposed temperature change is applied over a longer time period. The longer time period results in a slower strain rate and, all other things being equal, the slower strain rate produces a larger Fe.. Therefore, a challenge presents itself with respect to defining a set of transients (and their associated temperature ramp rates) that are bounding for design purposes: Component-specific preliminary studies have shown that the Fen-adjusted CUF for a variation of temperature ramp rates reaches a maximum when the temperature variation is on the order of 1,000°F/hour or higher [26]. Further investigations are expected to show that it will be possible to define design transients in a manner that will determine the maximum Fo -adjusted CUF as the temperature ramp rate (and thus the strain rate) is varied in a narrow range from approximately 1,000°F/hour (or other component-specific rates) to infinite rates. These efforts mirror similar work on crack growth in reactor components through corrosion fatigue

[25], and it is expected that such efforts will demonstrate that the issue of defining a transient with a range of ramp rates, extracting the strain rates, performing the design, and monitoring for compliance are all very manageable when utilizing the F_ approach for design.

As noted, several of the issues identified above were addressed earlier in this report. Those recommendations are intended to serve as a guide for performing environmental fatigue evaluations. The remaining issues that are not addressed in this report are beyond the scope of the work associated with this report at the current point in time, and some are impossible to resolve with information currently available. An example would be the issue of using ECP/conductivity as a more appropriate parameter for assessing environmental effects. All current F,, methodologies are based on measured dissolved oxygen, as that was the only water chemistry parameter recorded during laboratory testing. The remaining non-addressed issues represent the limitations on the current state of the art. As further industry work is completed to address some of the remaining issues summarized above, refinements or additions to these*

guidelines may be made to further define and enhance plant specific evaluations. Therefore, these guidelines can be thought of as an "instruction manual" for performing plant specific environmental fatigue evaluations based on the current state of technology and information available. Resolution of the remaining non-addressed issues is not-needed in order for license renewal applicants to satisfy the current regulatory requirements of addressing reactor water environmental effects.

4-28

Guidancefor Performing Environmental FatigueEvaluations 4D WDD ToMe C.-O.d) 5.000 M.D 2DOD M1OD. aD .D =llD Ti..

ae .. hd Figur'e 4-9, Issue of Transient Linking 4-29

5 CONCLUSIONS This report has provided guidance that may be used by individual license renewal applicants to address the environmental effects on fatigue in a license renewal application. The approaches documented in this report are geared to allow individual utilities to determine the optimum approach for their plants, allowing different approaches to be taken for different locations.

The overall approach taken for license renewal is to select a sampling of locations that might be affected by reactor water environmental effects. NUREG/CR-6260 locations are considered an, appropriate sample for Fen evaluation as long as none exceed the acceptance criteria with environmental effects considered. If this occurs, the sampling is to be extended to other locations.

An assessment of the chosen locations is undertaken: (1) to show that there is sufficient conservatism in the design basis transients to cover environmental effects, or (2) or to derive an expected fatigue usage factor including environmental effects. Then, either through tracking of reactor transient cycles or accumulated fatigue usage, utilities can determine if further steps must be taken to adequately manage fatigue environmental effects in the extended operating period.

Different methods are outlined for managing fatigue in the extended license renewal period should fatigue limits be exceeded. These include component re-analysis, fatigue monitoring, partial cycle counting, etc. Flaw tolerance evaluation as outlined in ASME Code,Section XI, Nonmandatory Appendix L, coupled with component inspection verifying the absence of flaws, is also included, although further work is underway by the Code to satisfy past regulatory concerns. Component repair/replacement is also a possibility, but this option is typically reserved to instances where other more economical approaches"cannot show acceptable results.

Consistent with current'ASME Code,Section XI philosophy for conducting additional examinations when flaws are found in service, the recommendations in this guideline include expansion of the number of locations tracked if fatigue limits are exceeded in the extended operating period. In addition, utilities will/continue to monitor operating plant fatigue experience, especially with respect to cracking that might indicate a strong contribution from fatigue environmental effects.

Guidance for performing plant specific environmental fatigue evaluations for selected locations is provided. The intent is to unify the process used by applicants to address environmental effects in the License Renewal Application, and provide specific guidance on the use of currently accepted environmental fatigue evaluation methodologies. The guidance provided by this report is considered to be "Good Practice".

Using the guidance. provided in this report, the amount of effort needed to justify individual license renewal submittals and respond to NRC questions should be minimized,.and a more unified, consistent approach throughout the industry should be achieved.

5-1

REFERENCES

1. NUREG/CR-5999 (ANL-93/3), "Interim Fatigue Design Curves for Carbon, Low-Alloy, and

-* Austenitic Stainless Steels in LWR Environments," April 1993.,

2. NUREG/CR-6260 (INEL-95/0045), "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components,":March 1995.

3. NUREG/CR-6583 (ANL-97/18), "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," March 1998.

4. NUREG/CR-5704 (ANL-98/3 1), "Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels," April 1999.

5. NUREG/CR-6674 (PNNL-13227), "Fatigue Analysis of Components for 60-Year Plant Life," June 2000.

6. U. S. Nuclear Regulatory Commission, Generic Safety Issue 190, "Fatigue Evaluation of Metal Components for 60-Year Plant Life."

7. Memorandum, Ashok C. Thadani, Director, Office of Nuclear Regulatory Research, to William D. Travers, Executive Director for Operations, Closeout of Generic Safety Issue 190, "Fatigue Evaluation of Metal Components for 60 Year Plant Life," U. S. Nuclear Regulatory Commission, Washington, DC, December 26, 1999.

.8. _ "An Environmental Factor Approach to Account for ReactorWater Effects in Light Water Reactor Pressure Vessel and Piping FatigueEvaluations," TR-105759, EPRI, Palo Alto, CA, December 1995.

9. "Evaluation of Thermal Fatigue Effects on Systems Requiring Aging Management Review for License Renewal for the Calvert Cliffs Nuclear Power Plant," TR-107515, EPRI, Palo Alto, CA, January 1998.

10. "Evaluation of Environmental Fatigue Effects for a Westinghouse Nuclear Power Plant," TR-110043, EPRI, Palo Alto, CA, April 1998.

11. "Evaluation of Environmental Thermal Fatigue Effects on Selected Components in a Boiling Water Reactor Plant," TR-110356, EPRI, Palo Alto, CA, April 1998.

12. "Environmental Fatigue Evaluations of Representative BWR Components," TR-107943, EPRI, Palo Alto, CA, May 1998.

13. Letter from Chris Grimes (NRC) to Doug Walters (NEI), "Request for Additional Information on the Industries Evaluation of Fatigue Effects for License Renewal,"

August 6, 1999.

14. Kalinousky, D., and Muscara, J., "Fatigue of Reactor Components: NRC Activities,"

Presented at EPRI International Fatigue Conference, Napa, California,, August 2000.

6-1

References

15. Letter from Greg Hollinger (PVR) to J. H. Ferguson, Chairman Board of Nuclear Codes and Standards, October 31, 1999.

16. Mehta, H. S., "An Update on the Consideration of Reactor Water Effects in Code Fatigue Initiation Evaluations for Pressure Vessels and Piping,"/PVP-Volume 410-2, pp. 45-5 1, American Society of Mechanical Engineers, 2000.

17. "Fatigue Comparison of Piping Designed to ANSI B31.1 and ASME Section IIl, Class I Rules," TR-102901, EPRI, Palo Alto, CA, December 1993.

18. Welding Research Council, Inc. Bulletin 487, "PVRC's Position on Environmental Effects on Fatigue Life in LWR Applications," W. Alan Van Der Sluys, December 2003.

19. "Materials Reliability Program (MRP): Evaluation of Fatigue Data Including Reactor Water Environmental Effects (MRP-49)," TR-1003079, EPRI, Palo Alto CA, December 2001.

20. Letter from Alexander Marion (NEI) to P. T. Kuo (NRC), "Revision 1 to Interim Staff Guidance (ISG)- I1: Environmental Assisted Fatigue for Carbon/Low Alloy Steel," October 3, 2003.

21. Letter from Pao-Tsin Kuo (NRC-NRR) to Fred A. Emerson (NEI), "Evaluation of Proposed Interim Staff Guidance (ISG)- 11: Recommendations for Fatigue Environmental' Effects in a License Renewal Application," January 21, 2004.

22. "Guidelines for Environmental Fatigue Evaluation for LWR Component," Thermal and Nuclear Power Engineering Society (TENPES), June 2002 (Translated into English in November 2002).

23. "Materials Reliability Program (MRP): Thermal Fatigue Licensing Basis Monitoring Guideline (MRP-149)," TR-1012018, EPRI, Palo Alto CA, September 2005.

24. "Materials Reliability Program (MRP): Integrated Fatigue Management Guideline (MRP-148),"

TR-101 1957, EPRI, Palo Alto CA, September 2005.

25. S. Ranganath and J. Hickling, "Development of a Possible Bounding Corrosion Fatigue Crack Growth Relationship for Low Alloy Steel Pressure Vessel Materials in BWR Environments," 3rd International EPRI Conference on Fatigue of Reactor Components, Seville, Spain, October 2004.

26. Assessment of Environmental Fatigue (F o)Approaches, PVP2005-71636, G.L. Stevens, J.J. Carey, J.M. Davis, A.F.

Deardorff,

Proceedings of PVP2005: 2005 ASME Pressure Vessels and Piping Division Conference, July 17-21, 2005, Denver, Colorado USA (in preparation).

)

6-2

A SURVEY OF APPROACHES USED TO-DATE FOR ADDRESSING FATIGUE ENVIRONMENTAL EFFECTS IN THE EXTENDED OPERATING PERIOD This appendix summarizes the approaches for addressing fatigue environmental effects in the extended operating period used by those applicants that have already submitted the license renewal application.

k_1 Plant License Renewal Approach Extended Operating Period Commitment Calvert Environmental fatigue calculations will Continue to monitor fatigue usage Cliffs be performed for NUREG/CR-6260 locations using NUREG/CR-6583 and Component with a CUF > 1.0 will be added to the NUREG/CR-5704 Fen rules - fatigue monitoring system Develop Class 1 fatigue analysis for the B31.1 piping locations /

Oconee Concluded that the effects of fatigue Update allowable cycles for remaining three are adequately managed for the locations (all SS) based on EAF adjusted CUF extended period with EAF to be using NUREG/CR-5704 but with a Z-factor of 1.5 40 addressed prior to Year Continue to monitor fatigue usage via cycle/severity Based on 4 EPRI studiesand counting/comparison Oconee confirmatory research Participate with EPRI in additional confirmatory NUREG/CR-6260 RPV locations research on this issue accepted via NRC staffSER for BAW-2251 A ANO-1 Performed environmental fatigue Continue to monitor fatigue usage, and do one of calculations for NUREG/CR-6260 the following for the components where CUF > 1.0:

locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules d refinement of the fatigue analysis in an attempt to lower the CUF to < 1.0 The EAF for the'RPV components r specified in NUREG/CR-6260 were repair of affected locations determined to be acceptable for the replacement of affected components period of extended operation I_

management of the effects of fatigue during the For the piping components, the surge period of extended operation using a program that line and HPI nozzles and safe ends will be reviewed and approved by the staff through had CUF > 1.0. These components the RI-ISI program are included in the RI-ISI program.

A-I

Survey of Approaches Used to-Date for Addressing Fatigue Environmental Effects in the Extended Operating Period L Plant License Renewal Approach Extended Operating Period Commitment Hatch Performed environmental fatigue Continue to monitor fatigue usage, perform a calculations for NUREG/CR-6260 refined analysis for feedwater piping and locations using NUREG/CR-6583 and recirculation nozzles before Year 40 NUREG/CR-5704 Een rules Assumed HWC conditions Used 60-year projections of actual cycles and actual fatigue usage to-date (higher than 40-year design basis in some cases)

Environmental CUF < 1.0 for 60 years at all locations except reactor recirculation nozzles and feedwater piping Turkey Performed environmental fatigue Continue to monitor fatigue usage, aging Point calculations for NUREG/CR-6260 management for surge line locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Revised NUREG/CR-6260 calculations to incorporate power uprate and NUREG/CR-6583 and -

5704 methods Used 60-year projections of actual2 cycles (same as design basis)

Environmental CUF < 1.0 for 60 years at all locations except surge line hot leg nozzle North Performed environmental fatigue Continue to monitor fatigue usage, aging Anna/Surry calculations for NUREG/CR-6260 management for surge line locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Scaled plant-specific results based on results in NUREG/CR-6260 Used 60-year projections of actual cycles (same as design basis)

Environmental CUF < 1.0 for 60 years at all locations except surge line elbow Peach Did not perform environmental fatigue Continue to monitor fatigue usage, perform Bottom' calculations for NUREG/CR-6260 environmental fatigue calculation before Year 40 locations Committed to do so before Year 40 A-2

/

Survey of Approaches Used to-Date for Addressing Fatigue Environmental Effects in the Extended Operating Period Plant License Renewal Approach Extended Operating Period Commitment 4 +

St. Lucie Performed environmental fatigue Continue to monitor fatigue usage, aging calculations for NUREG/CR-6260 management for surge line locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Refined several Class 1 fatigue analyses to offset Fen impact Used 60-year projections of actual cycles (same as design basis)

Environmental CUF < 1.0 for 60 years at all locations except surge I line elbow i i Ft. Calhoun Performed environmental fatigue Continue to monitor fatigue usage calculations for NUREG/CR-6260 locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Revised NUREG/CR-6260 calculations to incorporate NUREG/CR-6583 and -5704 methods Used 60-year projections of actual cycles (same as design basis)

Refined surge line Class 1 fatigue analysis to offset Fen impact

-Note from OPPD: The refined surge line analysis has already been completed because of pressurizerreplacement andpower uprate activities, so the surge line had to be reanalyzed for other reasons and wasn't done for License Renewal alone.

Otherwise, it probably would still be a pending action.

Environmental CUF < 1.0 for 60 years at all locations A-3

Survey of Approaches Used to-Date for Addressing Fatigue Environmental Effects in the Extended Operating Period Plant License Renewal Approach Extended Operating Period Commitment McGuire/ Committed to perform environmental Perform environmental fatigue analysis before the Catawba fatigue analysis based on NUREG/CR-) end of the 40th year of plant operation 6583 .for carbon and low-alloy steels and on NUREG/CR-5704 for austenitic Choose sample locations from those in stainless steels NUREG/CR-6260 and other locations expected to have high EAF adjusted CUF, to ensure that no plant location will have an EAF-adjusted CUF that exceeds 1.0 in actual operation Determine the EAF adjusted CUF using defined transients and/or assumed occurrences which bound or coincide with realistic expectations for an evaluation period Continue to monitor fatigue usage via cycle/severity counting/comparison using EAF adjusted allowable cycles or'via tracking EAF C. adjusted CUF Robinson Performed environmental fatigue Continue to monitor fatigue usage, aging calculations for NUREG/CR-6260 management for surge line locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Revised number of load/unload events to show acceptability Used 60-year projections of actual cycles (same as design basis)

Environmental CUF < 1.0 for 60 years at all locations except surge line Ginna Performed environmental fatigue Continue to monitor fatigue usage calculations for NUREG/CR-6260 locations using NUREG/CR-6583 and Prior to the end of the current license period, the NUREG/CR-5704 Fen rules pressurizer surge nozzle will be inspected The EAF for all components specified in NUEG/CR-6260 were determined to be acceptable for the period of extended operation, with the exception of the pressurizer surge line Plant specific Fen factors for the piping locations, based on the ASME Class 1 fatigue analysis done in NUREG/CR-6260, were applied to Ginna-specific design basis fatigue usage to determine ther environmental fatigue values A-4

Survey of Approaches Used to-Datefor Addressing FatigueEnvironmental Effects in the Extended Operating Period Plant License Renewal Approach Extended Operating Period Commitment Summer The thermal fatigue management assess EAF before the end of the current licensing program will be revised by the end of period the current licensing term to base future projections on 60 years of operation and to account for EAF Dresden/ Did not perform environmental fatigue Continue to monitor fatigue usage, perform Quad Cities calculations for NUREG/CR-6260 envirornmental fatigue calculation before Year 40 locations Committed to do so before Year 40 Farley Performed environmental fatigue, Continue to monitor fatigue usage calculations for NUREG/CR-6260 locations using NUREG/CR-6583 and Prior to the end of the current license period, the NUREG/CR-5704 Fen rules charging and RHR locations will be addressed further Used existing Class 1 fatigue analysis for all NUREG/CR-6260 locations, except surge line and BIT tee to RHR/SI piping Developed Class 1 fatigue analysis for surge line using stress-based fatigue software Used actual fatigue usage to date (based on available stress-based data) and design number of cycles for the surge line Developed Class 1 fatigue analysis for BIT tee to RHR/SI piping using Summer 1979 ASME piping rules The EAF for all components specified in NUREG/CR-6260 were determined to be acceptable for the period of extended operation with the exception of the charging nozzle and RHR locations ANO-2 Performed environmental fatigue Continue to monitor fatigue usage, and do one of calculations for NUREG/CR-6260 the following for the components where CUF > 1.0:

locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules refinement of the fatigue analysis in an attempt to lower the CUF to < 1.0 Environmental CUF < 1.0 for 60 years for all RPV locations repair of affected locations For the pressurizer surge line, replacement of affIcted components charging nozzle and shutdown management of the effects of fatigue during the cooling line CUF > 1.0, safety period of extended operation using a program that injection nozzle< 1.0 will be reviewed and approved by the staff through the RI-ISI program A-5

Survey of Approaches Used to-Datefor Addressing Fatigue Environmental Effects in the Extended Operating Period Plant License Renewal Approach Extended Operating Period Commitment Cook Performed environmental fatigue Continue to monitor fatigue usage calculations for NUREG/CR-6260 locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Developed Class 1 fatigue analysis for three B31.1 piping locations Used 60-year projections of actual cycles and actual fatigue usage to-date (higher than 40-year design basis in some cases)

Environmental CUF < 1.0 for 60 years at 5 of 6 locations. The environmental CUF was greater than 1.0 for the pressurizer surge line.

Browns Performed environmental fatigue Continue to monitor fatigue usage, perform Ferry calculations for NUREG/CR-6260 /analysis for piping locations locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Refined several Class 1 fatigue analyses to offset Fen impact Separate oxygen values computed for HWC and NWC conditions, applied based upon historical and projected system availability.

Used 60-year projections of actual cycles and actual fatigue usage to-date (higher than 40-year design basis in some cases)

Environmental CUF < 1.0 for 60 years for all RPV locations, piping locations > 1.0 TVA is developing Class 1 fatigue analysis for piping locations A-6

Survey of Approaches Used to-Datefor Addressing FatigueEnvironmental Effects in the Extended Operating Period Plant License Renewal Approach Extended Operating Period Commitment Point Performed environmental fatigue Continue to monitor fatigue usage Beach calculations for NUREG/CR-6260 locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules The EAF for all components specified in NUEG/CR-6260 were determined to be acceptable for the period of extended operation

-J Fatigue monitoring software used to calculate spray line usage Used plant operating data to analyze fatigue for piping locations since design CUF values were not available Brunswick Performed environmental fatigue Continue to monitor fatigue usage calculations for NUREG/CR-6260 locations using NUREG/CR-6583 and NUREG/CR-5704 Fen rules Refined several Class 1 fatigue analyses to offset Fen impact Developed Class 1 fatigue analysis for two B31.1 piping locations Separate oxygen values computed for HWC and NWC conditions, applied based upon historical and projected system availability.

Used 60-year projections of actual cycles and actual fatigue usage to-date (higher than 40-year design basis in some cases)

Environmental CUF < 1.0 for 60 years at all locations A-7

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NEC-JH 65 R&D Status Report NUCLEAR POWER-DIVISION John J. Taylor, Director BWR WATER CHEMISTRY component to which they are applied. For and shutdowns oxygen concentration varies Many of the stress corrosion problems in example, induction heating stress improve- with temperature (Figure 1). The important boiling water reactors (BWRs) result from the ment affects cracking in the pipe weld to question of which temperature-oxygen com-presenceof a very small amount of dissolved which it is applied: it does not affect any binations facilitate IGSCC has been an-oxygen in the reactor water Radiolysis in other weld. Only the water chemistry reme- swered in part under EPRI research (RP1332 the reactor core continually decomposes a dies have the potential of protecting the and RPT115). The shaded IGSCC danger small amount of the very pure water used in whole system. zone in the figure represents those combi-BWRs into free oxygen and hydrogen. Most The water in a BWR is similar in purity to nations.

of the gas is stripped from the water by the laboratory distilled water. It is converted into Reducing oxygen levels during reactor steam, leaving only trace amounts of oxygen steam by reactor core heat, condensed into startups and shutdowns by deaeration has and hydrogen dissolved in the reactorwater. liquid again after passing through'the tur- been highly publicized in the BWR industry.

Although the amount of dissolved oxygen is bine, and reconverted into steam on re- Although helpful during transients, this rem-only about 200 ppb, it is sufficient to facilitate entering the core. This process is repeated edy does little, if anything, to reduce pipe stress corrosion cracking. Hydrogen water continuously. cracking during steady-state conditions chemistry can reduce dissolved oxygen to During reactor operation, radiolysis in the (RP1332-2, RPT1 12-1, RPT1 15-3, RPT1 15-4).

a level that will no longer facilitate stress reactor core continually decomposes a small Deaeration does not affect oxygen levels corrosion. amount of water to form free oxygen antl during steady-state operating conditions, hydrogen. Most of the oxygen and hydrogen- which definitely facilitate IGSCC. The amount Pipe cracking in BWRs first came to the atten- is stripped from the water by the steam and' of time spent at steady state is about .140 tion of U.S. electric utilities in 1974. This issubsequently removed from the water cir- times greater than the amount of time spent problem has resulted in costly repairs and cuit by special equipment in the condenser. in startups. Therefore, to reduce IGSCC fur-lost operating time. The potential serious- However, about 200 ppb oxygen and 12 ppb ther, it is necessary to change water chem-ness of the problem was recently emphasized hydrogen remain -dissolved in the water in istry during steady-state conditions.

I by the discovery of cracks in large-diameter the core when the reactor is at the steady-(26-in; 660-mm) recirculation piping at a state full-power operating temperature Hydrogen water chemistry domestic BWR. These cracks necessitated (288°C; 550°F). During reactor startups In hydrogen water chemistry, small amounts replacement of the complete recirculation of hydrogen gas are added to the reactor piping system and will cost 12 to 18 months feedwater. In the reactor core the added of operating time. hydrogen recombines with oxygen and other Earlier EPRI reports (EPRI Journal, Sep- radiolysis products to suppress the net tember 1981, p. 6; November 1981, p. 18) Table 1 amount of oxygen produced at the steady-have helped familiarize the industry with the CAUSES AND REMEDIES FOR state temperature (Figure 1).

various factors involved in pipe cracking. In BWR PIPE CRACKING Although hydrogen water chemistry ex-most cases, cracks have resulted from inter- periments were conducted over 20 years granular stress corrosion cracking (IGSCC). Cause Remedy ago in several early Norwegian and U.S.

This status report describes how changing test reactors, the concept was not further reactor water chemistry can help prevent Stress Induction heating stress developed until 1979, when the Swedish util-improvement IGSCC. ities and ASEA-Atom conducted a short

. Three conditions must be present simulta- Heat sink welding eight-hour test of hydrogen water chemistry neously for IGSGC to occur: stress, a sensi- Last-pass heat sink welding at Oskarshamn-2 and demonstrated that hy-tized microstructure, and an environment drogen water chemistry was economically (water chemistry and temperature) that will Sensitization Solution heat treatment feasible. In 1981 the Swedes conducted a facilitate cracking. Theoretically, no pipe will Corrosion-resistant cladding second test at Oskarshamn-2 for four days, ever crack if any one factor is completely and obtained detailed water chemistry mea-Alternative materials eliminated. Eight pipe-cracking remedies surements. These tests showed that hydro-have been developed: three that affect gen water chemistry lowered the)oxygen Environment Hydrogen water chemistry stress, three that affect sensitization, and concentration to levels that would no longer Impurity control two that affect environment (Table 1). By be expected to facilitate stress corrosion.

their very rAature, all the stress and sensiti- However, no actual in-reactor corrosion tests zation remedies are limited to the specific were performed. In June 1982 DOE funded 52 EPRI JOURNAL January/February 1983.

i

~itimi I I liki ,tilt'toil Iotiit~i~tetihe jiniililiI~tll(lInt Illail Itioilllfil IItM UO litMll III 18111dI#ItII11d-11MYU8bI hu - OLdM* h1yOll0UH11 Willlil (Ill If'iltlllly {fl(lillJ-Iitity WiVaior.'I ht it Intapolnla nore it nihrptnoor tornpornturo-oxygon comblnntlona Ihlt lirvo boon monaured tnios there Is not enoulh dissolved oxygn oporoling l3WRs during startup, shutdow~n, normal seandy state, and hiydrogen water chemistry steady stale.

to react with the N-16 to form NOT, the N-16 combines with the hydrogen toform ammo-nia, NH3 . Ammonia is a volatile gas and is 10 therefore removed, from the water by the steam. The N-16 is a very unstable isotope and decays with a half-life of 7.11 s, giving off high-energy gamma rays. Because more N-16 ends up in the steam when hydrogen water chemistry is used, the steam lines and steam turbine will emit more gamma radia-tion than when normal BWR water chemistry

• * ". is used. At Dresden-2; the amount of N-16 I

gamma radiation increased by a factor of 5 during the hydrogen water chemistry test.

The turbine is heavily shielded and therefore

• Normal the increase in N-16 did not significantly steady increase the radiation dose rate to plant

• state personnel. In general, the N-16 side effect

0) ,*

• was manageable during the tests at Dresden-

/ 2. When maintenance crews had to enter an 0.1 I- area where N-16 radiation was high, the hy-drogen injection was stopped, and N-16 radiation levels quickly returned to normal.

Hydrogen water After the maintenance crew left the area, the chemistry hydrogen injection was resumed.

steady state The major uncertainties about hydrogen water chemistry revolve around the possibil-ity of long-term negative side effects. The 0.011 two most important concerns are the hydro-0 50 100 150 200 250 300 gen embrittlemernt of the nuclear fuel clad-I Temperature ('C) ding and the redistribution of corrosion products (radiation buildup) within the plant.

Although the best technical judgment avail-able indicates that the possibility of either of these effects becoming unmanageable is a 30-day hydrogen water chemistry experi- To achieve an oxygen level of 20 ppb extremely remote, there is no data base on ment at Commonwealth Edison Co.'s Dres- during the Dresden-2 test, it was necessary which to build firm conclusions. At least one den-2 plant. During this experiment, EPRI to add 1.5 ppm hydrogen to the feedwater fuel cycle witlhydrogen water chemistry will sponsored in-reactor stress corrosion tests and to use pure oxygen in the off-gas system be required before a recommendation can that helped confirm hydrogen water chem- instead of air. The total cost of both hydro- be made to theutilities. EPRI is developing a istry as a powerful antidote for stress corro- gen and ooxygen was less than $1000/day. long=term in-reactor test program to address sion problems (RP1930-2). A $1 million EPRI If a BWR had a 70% capacity factor and a these major uncertainties.

- laboratory research project on ;hydrogen remaining lifetime of 20 years, the total water chemistry, which has been in progress would be about $5 million. Equipment instal- Control of Impurities for two years, supports this conclusion lation would cost an additional $1 million. Although reactor water contains impurities (RP1930-1). In contrast, replacement of a complete re-< in small amounts (at the ppm or ppb levels),

' The combined results of the in-reactor circulation piping system is estimated to cost BWRs generally operate with high-purity and laboratory IGSCC tests show that the on the order of $500 million, including the water. For example, NRC guidelines spec-oxygen level must be suppressed to 20 ppb cost of replacement power. ify that reactor water chloride (CI) con-to eliminate IGSCC completely. For example, Although the stress corrosion benefits centration be kept below 0.2 ppm and the during the Dresden-2 test, a severely sensi- from hydrogen water chemistryare expected conductivity below 1 pS/cm during plant tized sample of stainless steel was tested to be very high, at least one negative side6 operation. A solution containing 1 ppm of under extreme stress and strain, and abso- effect exists. The amount of the radioactive sodium chloride (NaCI) would have a con-.

lutely no IGSCC was detected. In laboratory isotope nitrogen-16 (N-16) in the steam will ductivity of about 2 pS/cm and a Cl concen-tests on full-scale pipes the growth rates of increase. The N-16 is formed in the reactor tration of 0.6 ppm. Therefore, 1 ppm of NaCI preexisting cracks have been slowed by a" core by the nuclear reaction: oxygen-16 + would exceed the NRC specifications. The factor of 10 as a result of hydrogen water neutron -- nitrogen-16 + proton. Under- results of EPRI research projects have shown chemistry. If no cracks are present before normal water chemistry conditions the N-16 that maintaining water purity may be just hydrogen treatment of water, no new cracks reacts with dissolved oxygen to form nitrate 'as important as controlling oxygen levels are expected to start. (NOi-), which is soluble in the reactor water. (RP1563-2, RPT115-3, RPT115-6). Impuri-EPRI JOURNAL January/February 1983- 53

ties increase the size of the IGSCt danger maintenance or repair work during an outage rates for MSIVs and require the periodic test-zone. attributed to another system or component. ing of each valve to verify that this require-In accelerated laboratory IGSCC tests as Thus, although the valve could be consid- ment is met.

little as 1 ppm of certain impurities eradi- ered a contributing cause of the outage, this Work was initiated in early 1979 with At-cated hydrogen water chemistry benefits. is not reflected in the reported data. wood and Morrill Co., Inc., a manufacturer To benefit from hydrogen water chemistry, Nuclear plant data collection and evalua- of MSIVs, and General Electric Co., the utilities will have to control both oxygen tion systems originally had many shortcom- nuclear steam supply system contractor for levels and conductivity. Reactor water with ings. As a result of improvements in these BWR plants, to develop a comprehensive only 20 ppb oxygen and a conductivity in the systems, data quantity and usefulness have test program on MSIV seal leakage perfor-vicinity of 0.2 PS/cm may eliminate any pos- been increased. Other existing sources of manceý (RP1243-1, RP1389-1). The goals sibility of IGSCC. EPRI has recently stepped information remain to be assimilated, how- were first to identify the factors that affect up its research to understand the role of ever, to achieve a comprehensive view' of the valves' capability to meet the seat leak-impurities in an effort to produce cost-effec- the problem. EPRIs limiting-factors analysis age criteria imposed by the local leak rate tive water cthemistry guidelines. Projecl, studies, the findings of which are published test (LLRT) and then to identify and'verify Manager: Michael Fox in four reports (NP-1136 through NP-1139), the effectiveness of corrective actions for provide further insight into the causes and improving Valve leakage performance.

the magnitude of nuclear plant availability The program evaluated the effects of such VALVE RESEARCH Iosses~attributable to valves. factors as local residual stresses from valve The primary goal of valve researchIn EPRI's On the basis of the efforts described above, installation welding; forces and moments Nuclear Power Division is to reduce the two areas were selected for initial EPRI R&D applieýl by the connecting pipe; mechanical amount of plant unavailabilityattributableto attention: the seat leakage performance of cycling; thermal cycling; excessive wear valves in LWR power plants. These R&D main steam isolation valve'S (MSIVs) in BWRs and corrosion of critical valve surfaces; activitiesseek to improve valve maintenance and valve stem packing improvements for and poorly controlled maintenance prac-practices and valve performance and reli- both PWR and BWR-application. tices. Of the factors investigated, corrosion ability and thus reduce the cost of producing Figure 2 presents a cutaway view of a rep- of the valve seating surface (or changes in electricity. EPRI's initial effort in this Area resentative MSIV with the valve bonnet and the friction coefficient) and inadequate main-was an assessment ofindustry valve prob- the actuator removed. Two identical MSIVs tenance practices were found to be the most lems conducted in the mid 1970s (NP-241). are installed in series in each BWR steam significbrnt contributors to the seat leaka'ge It was found that nuclearplant unavailability line. Technical specifications for BWR plants problem. Program results are reported in attributed to valves, valve actuators, and establish maximum allowable seat leakage NP-2381 and NP-2454.

associated control circuits representedap-proximately three forced outages per plant per year,with an average outage duration of about two days. The value of such unavail-ability is significant. A study reportedin the June 1982 EPRI Journal (p. 18) indicates that a 1% availability improvement in base-load coal and nuclear generatingunits com-bined would representsavings of $2.2 billion nationwideover the seven-year study period.

In the initial assessment of industry valve,,

problems, which. was conducted by MPR Associates, Inc., the concept of key valves evolved. These are valves, whose :malfunc-tion can result in a forced plant outage, a power reduction, or an extension of a planned outage. It is basically to these valves Poppel -

that the EPRI research effort is directed. main seal Steam inlet The study concluded that only 'a small percentage (5-10%) of the total valve popu-lation in a nuclear power plant is applied in such a way that failure would result in a forcedoutage. It should be noted that these key valves are not necessarily safety-related valves. No major differences were found be-tween PWRs and BWRs regarding the causes (seat leakage, stem Ilakage, actuator mal-function) of valve-related shutdowns.

The study also concluded that forced out-ages attributable to valves are underreported because of an umbrella or shadowing ef- Figuie 2 BWR main steam isolation valve. EPRI has sponsored a test program to determine the factors that fect-situations where a valve requires affect valve seat leakage performance and to evaluate ways to Improve this performance.

(54 EPRI JOURNAL January/Februiary 1983'

A NEC-JH 66.7-AK Fatigue Crack Propagation Rates for Notched 304 Stainless Steel Specimens In Elevated A Temperature Water Fatigue crack propagation(FCP),rolesfor 304 stainless steel (304 SS) were determoined in 24YC and 288RC air and 288'C water with 20-60 cc 112/kg 1lO using double-edged Gary L. Wire notch (DEN) sp.ecimens. Tests perjfrniedat iati:hed loading conditions in air and water provided a direct comparison oi'the relative crack grawth rates over a wide range o/test William J. Mills conditions. Crack growth rates of 304 .5 in water were about 12 tines the air rate Jor both short cracks (0.03-0.25 min) and long cracks up to 4.06 mm beyond the notch, Bl.,i, i Behis. Inc1

. which are consistent with conventional deep crack tests. Phe large environinental degra-West M itt. PA15122-0079 dation fr)r 304 .S crack growth is consistent i ith the strong reduction ofafitigue life in high hydrogen water: Further.verv similairenvirotniental e4Pets wete.repoited in fatigue crack grioth tests in hydrtiogen water chemistiy (HWC). Prior to the recent tests reported bv Wire and Mills I I I nd Evaos and Wire (21, most literature data in high hydrogeni water showed only/ a mild en virtonnental effctifar 304 SS, of order 2.5 tiaes air olr less.

Howevet; the tests were predominantvl perfritied at high cyclic struss intenisities or high fIrequencies where environmental c/ffects ore sinall. The enrviroinienitalcf/.ci in /a iv oxygen el environments at lhw stress intensity depends stongl/y oin both the stress ratio, R, and the load rise time, T, . Fractographicexaminations were peifJiried oii specieteiis tested in both air and water, to understand the operative cracking ntec/hsntisiis associared with' environmental e./Pets, hi 28'° iw'titt; the fracqture suwfaces were t crisjply faceted with a crystallograp/hic appearance, and showied striations under hig/h magnificatlioi ihe cleai'age-like facets suggest dial hydrogen embrittlenient is the primary catse qf acceler-ated cracking.. [1)O1: 10. 1115/1. 1767859]

- I Introduction The double-edge notched uniaxial specimen provides two sies for crack initiation. It provides an advantage over compact tension Fatigue crack propagation data for.Type 304 stainless steel (304 specimeens in that it can be tested in both tension-tension and SS) were obtained in air and an elevated temperature aqueouw tensiion-compression loading conditions. Tests were performed un-environrnent. The data were developed fromn instrumented t.atigue der load control in fully reversed (R ... I) and tension-iension tests on double-edged notched (DEN) fatigue specimens with two

• different notch root radii p of 0.38 and 1.52 rmn, reported by Wire loading (R=0). Alignment was achieved by manually adjusting et al. [3]. The fatigue tests were primarily designed to determine the pull rod to minimize bending stresses, which were monitored the effect (if notch radius on fatigue crack initiation but also pro- by strain gages attached to the specimen (Fig. I). Once a satisfac-

• vide fatigue crack growth data for bothshallow and long cracks.

tory alignment was achieved, the strain gages were removed and Direct comparison of crack growth rates obtained in air and water the FPD leads were attached. For the tests in water, the assembly under identical loading, conditions and for equivalent crack sizes was then enclosed in art autoclave, which was filled with water demonstrates that 304 SS experiences a large environmental ef- and heated to 288"C. Deacrated water containiing 20 to 60 cc feet, and the, detailed analysis below shows that this trend was H2 /kg H2 0 was used in this study. The room temperature pH was supported by all tests. 10.1 to 10.3. and the oxygen concentration was less than 20 ppb.1,)/

The specimen was cycled until crack initiation was detected.*

based ott the electrical potential drop reading corresponding to "

crack growth if 0.13 nam. Following an interim visual inspection,*,,

2 Experimnental cycling was continued to obtain crack extension data.

The DEN specimens (Fig. 1) were machined from a 127 min The crack growth rate.da/dN was calculated using the~secant diaameter bar forging with an L-C orientation per ASTM E1823, method applied to the average extension curves, as discussed by with yield and ultimate strength of 288 and 546 MPa. The chemi- Wire [1]. Crack growth rates were obtained at extensions as low

.cal composition of the 304 SS material is provided in [1]. The as 0.013 mm in order to investigate possible short crack effects.

microstructure consists of nonscnsitized grains with a grain size of For conventional deep cracks. rates were calculated over larger ASTM 2. increments of crack extension.

Load-controlled cyclic fatigue tests were performed in air at For shallow cracks, of depth L

.L &.L*,I t i 9 10- 10 1 D-9 10's . 1o'? i Do 10-6 Air Rat*, rm/dn Air rate, mm/s Fig. 4 304 SS DEN crack growth rates in water vs air. Trend shows decroased ER at high air rate. Air rates are calculated Fig. 6 Comparison of DEN to CT data in H1WC Large environ-directly from control tests Mental effect. extend to low air rates Fig, 4, verify .that the environmental effect continues unabated to erature average about 14 times the air rate, vety similar to DEN a crack growth of 17 nim, as reported by Evans and Wire [2]. For data. Indeed, crack growth rates in HWC at fnpquencies between 4 304 SS CT data, the baseline crack growth rate ini air, (da/dN),ir, 1.67X 10-2 and 5.56X 10 Hz are identical to those obtained in this study. The fact that the stainless steel studied by Prater was (K was determined via [8] for the appropriate test conditions (i.e., AK, R, and temperature), It is also noted that the agreement be- sensitized does not appear to be important, as trie cracking mode tween short crack and long crack results indicates that there is no was transgranular. Gordon ct al. [17] indicated that the fatigue "chemical" enhancement of crack growth of short cracks, such as crack growth rates in HWC water were the same for solution reported by Gal.gloff [14) for high strength steel in a NaCi solu- annealed and sensitized 304 SS, and Jewett et. al. (t18 reported tion. very similar rates in these materials as well as welds. A review of fatigue crack propagation of austenitjc stainless A comparison of crack growth data trends from DEN tests and steels was performed recently by Shack and Kassner [15]. Data selected conventional compact tension test data in HWC is pro-from surface crack tests performed in low oxygen "hydrogen Wa- vided in Fig. 6. The DEN and CT data are in good agreement in ter chemistry" (HWC) environments by Prater et al. [ 16] are com- the intermediate growth rate regimes where both specimen types pared with DEN data in Fig. 5. HWC is BWR water chemistry were evaluated., Moreover, the data by Ljunberg [19] show even with hydrogen added to control the electrochemical potential. The greater enhancement in the low crack growth rate regime. These literature tests on surface crack specimens tested in HWC water results provide further support for the observation that environ-confirm that the large environmental effects shown here have been mental effects tend to increase in thellower stress intensity regime observed previously. Overall, the surface crack tests from the lit- where crack growth rates In air are reduced. The tests by Andresen and Campbell [20] show. evidence for a transition to reduced environmental effects at htgh equivalent air rates, and more limited data by Gordon et al. [17] are consistent i1-0 with such an effect. It is noteworthy that the DEN data agree qualitatively with HWC data in Fig, 6, including evidence of a transition to substantially lower environmental cffects at equiva-lent air rates above l0-9 am/s,. The hydrogen level for the HWC test data in' Figs. 5 and 6 is 150 ppb ox less, much less than several ppm in the current DEN tests and in PWR water, Although the corrosion potential in HWC is typically about 0.3 V S4E higher than that in water with higher hydrogen used in the present tests, accoiding to Oilman [21], the I 3 overall crack growth rate response in the two environments ap-pears to be similar. 10-8 3-A Effects of Stress Ratio, Stress Intensity,, and Rise Time. Evans and Wire (2) performed a series of teals on a l.9T CT specimen (thickness=24.-1 mm) of the same heat and water con-I0"9 ditions used in the DEN tests. The CT tests. showed that large environmental effects occurred in conventional, deeply cracked compact tension specimens with high hydrogcm levels and the 10-"s 10"1 10.7 10-M 10' attendant lower potential. Results from the DEN tests and the compact tension tests by Evans and Wire (2002) arie shown in Fig, Air rale, mrnan

7. For DEN data represented in Figs- 7-8, the full cyclic stress tin *i Cnatnnnrisfn of DEN to surface crack data. e lurface range and crack extensions increments of 0.32 man or larger were employed, crack data tested In HWC [I1)

AUGUST 2004, Vol. 126 / 321 Journal of Pressure Vessel Technology 1- ii I. _j

Data Normalized to R10. T,=l 50s o PWR,Brnaro et at Tr-7.*s*, *0.05 0 PWR-Bernord et al Tr-4508, R=0.05 AA- U1, t=U./,Ito .S, CT, R-0,?,Trý.60a 0 A CT, R--.7,Tl=sOOs ,

S E 10-3 -0 CT, R=C.8a, Ty-5;s 0 I, 0 CT, R=0.03, Tr-60a CT, R0.0.63, TrsSOOs AlkCurve, R=O 0 0 I 10-' 0 0 1 -Z 1O-S C. , T 10 10 AK, hlPs-r'n AK, MP--m Fig- 7 304 SS crack growth rates In water at 288 *0. Rise time Fig. 9 Normalized 304 SS CT FCP Dats at Low Potential. Nor-(T,) is In seconds malization: (1-R)-, Tr-3' to R-0,T,-150 a This formulation indicates a strong role of T, and R, consistent The reaults in Fig. 7 indicate a strong effect of both Tr and R. with results described above in low oxygen water, It is noted that The environmental effects can be rationalized in terms of a com- the present crack growth rates are simila.r to those reported by bitled mean stress effect on closure or R ratio and a rise time or Itatani et Al. t25] in BWR water in the few cases where data are freqxency effect, consistent with the literature. Bamford [221 available at similar T,., R, and AKX Figure 8 shows that the crack noted larger environmental effects at higher R ratios. He incorpo- growth rates in Fig. 7 can be reasonably well normalized by T 5' rated an effective AKoff = Kr 5,(l -,R), which shifted the high R and 1/0 -R)) . Hence, the form of the correlation developed by data more ,in line with low R data. Cullen [23) reported strongly Itatani et al, for tension-tension appears to be promising for increased FCP rates for cast stainless steel at higher R in PWR tenlsionl-compression. Further, the present rise time and stress ratio water. The data by Brnard et al. (241 on Z3 CND17-12, similar to R ratio dependence are consistent with all but the very high R ,._Al6 SS, showed a&clear rise time effect in PWR Water. Recently, a (0.95) .BWR water data utilized by ItatanJi t al. [25], figure 9 correlation for FCP of austenitic stainless steels in BWR water shows that normalization in Fig. 8 worked successfully on data was developed by [tatani et al. (25]. The correlation was of the from compact tension tests at high R by Evans and Wire [2) and foarm at low R by Bernard et al. [24]. Both data sets include long rise da/dN=A(AK)'*TI,(l -R)P times (450-500 s) where environmental',effects are substantial. with m--3,0, The plot shows that ER reduces to about 2x at large AK. While ný0,5, aidand p=2.12 the selected parameters values correlate these limited data sets, (4) much rore data would be required to obtain- a definitive correlation. .4 Characterization of Fatigue Crack Propagation Data Normalized to R.0. t,=--* 0 K rCurve. R*O o Normalized Waler Daot Mechanisms Fracture surface features for specimens tested in air and water I 100 :. were evaluated to correlate operative cracking mechanisms with environmental cracking behavior, The fracture surface appearace for specimens tested in room temperature air was found to be dependent on loading conlditions. A faceted Morphology (Fig. 10(a)) was observed at crack growth rates less than I ><10i- 4 rb-cycle. vast fields of well-defined striations were gen-4 Mc erated between I X lo-4 and I X l0-3 mn/cycle, and a combina-tion of fatigue striations and dimples (Fig. 10(b)) was observed above I x 10-3 mm/cycle. The nature of striated fracture surfaces it the intermediate and high crack growth rate regimes resembles that typically observed in FCC materials, but the facets formed at 10-6 low crack growth rates are rather untique, as discussed below, Evidence of rubbing and fretting (Fig. 11) due to repeated contact between mating fracture surfaces was observed in specimens to tested under fully reversed cyclic loading conditions. MPa-M' 0 mAK, Facets generated at low crack growth rates had an irregular appearance that was associated with a quasi-cleavage mechanism Mal 9 Nonrmali~a ,I CLc Cr0 n--- . , .* .... . . wr L2 va axV. Nrrmalzalon:; inat was operative tor both shajlow and deep cracks, as long as 31 to R=O, T,-15O crack growth rates were less than I X IO4 mnilcycje. Because 322 / VoL 126, AUGUST 2004 Trensactlons of the ASME / N, V 4 Fig. 11 Repeated contact between crack surfaces Rub marks at low AK levelt in 2880C air. (b) (R=-1). (a) Fig. 10 Fractographs of 304 SS tested In 24CC air. (a) Irregular rounded by severely rubbed regions (240C air). Striations sur-quaai-cleavage facets at da/dN=ex1 0-5 mrnlcycle. Arrow notes tailed twin boundary. (b) Striations and dimples' de-2 at 1 X10- mn/cycle son of Figs. 12(a) and 12(b) shows that the high temperature facets had more of a cyatallographic nature with 304 SS is a metastable alloy at room temperature, some evidence of the material river patterns, in contrast with the Irregular directly ahead of an advancing crack undergoes facets generated in a strain-induced room temperature air. The lack of quasi-cleavage transformation to ix' martensite. Therefore, that 2880 C is above the critical temperature facets indicates cracks propagate through martensite, which results in a quasi-cleavage induces a martensite transformation (i.e., where cold working that resembles the quasi-cleavage fracture morphology M 0 temperature). Based martensitic steels. Fetritescope measurements surface appearance in on the composition of 304 SS, the MD temperature showed that all fa- with 30% cold work is on the order of associated tigue fracture surfaces generated at room 1000 C (Lacombe [29]). temperature contained Indeed, Ferritescope measurements a' martensite, with the amount of martensite showed no detectable increasing at higher a'-martensite on fatigue fracture surfaces stress intensity factor levels due to larger plastic zone sizes. generated at 288 0 C. The morphology of the quasi-cleavage At crack growth rates slightly above 1 X facets was consistent 1O-4 mm/cycle, facets with the fracture surface appearance for formed in 288'C air were poorly defined 304 SS (Gao et al. [263) and parallel fracture and high purity Fel gCr- I21Ni SS (Wei markings associated with slip offsets were ct al. [27]) tested in room often superimposed on temperature air, 3,5% NaCI solutions them, The transition to poorly defined facets and hydrogen, Strain- is believed to be induced a' martensite formed ahead associated with a transition from heterogeneous-to-homogeneous of fatigue cracks in both slip. Fracture surfaces generated in 288M0 water alloys, wyhich caused a quasi-cleavage mechanism- were remarkably Unlike 304 SS, different than those generated in air. Facers 316 SS fatigue tested in room temperature formed in water had a air (Mills (28]) exhib- crystallographic appearance with well-defined ited more conventional, cleavage-like facets. Because 316 SS is a more stable alloy due to its higher nickel shown in Fig. 12(c). The sharp, cleavage-like river patterns, as transformation does not occur at room content, a' martensite mcdiately adjacent to machined notches and facets formed im-temperature; hence, it ex- well away from the hibits classic, cleavage-likc faceted growth notches, indicating that the same faceted as cracks propagate growth mechanism was through stable austenite, operative for shallow and long cracks. Moreover, well-defined In the low crack growth rate regime, crystallographic facets persisted over the localized cracking along annealing twin' 304 SS also exhibited growth rates generated in this program, entire range of crack boundaries, but no evi- including crack growth dence of intergranular cracking. Localized rates as high as 8 X 10- m4m/cycle where separation along favor- fracture surfaces gener-ably oriented twin boundaries produced ated in air exhibited poorly defined facets fiat, featureless facets that and vast fields of fa-appear as dark islands, surrounded by tigue striations. There was no evidence of quasi-cleavage facets. Gao either intergranular et al. [263 and Wei et al. [27) also reported cracking or annealing twin boundary cracking twin boundary track- Although fracture surfaces generated in 288'C in 288'C water ing in 304 SS and high purity Fe-ISCr-l2Ni water exhibited 0 SS, crisp cleavage-like facets, high magnification Facets formed in 288 C air had a different took on a more conventional cleavage-like morphology, as they vealed the presence of fatigue striations (Fig. of facet faces re- ' appearance. Coinpari- 13). At crack growth rates from I X 10-4 to 3 X 10-4 mn/cycle, parallel fracture mark-Journal of Pressure Vessel Technology AUGUST 2004, Vol. 126 / 323 VO DG 01N3dBiON 89 :ST 8R3/i/B Fig. 13 Fractographs of 304 SS fatigue tested, In 288'C water, (a) Highly angular faets persist to 3X10-4 mm cycle. (b) High magnification of (a) shows fatigue siriations suparimposed an facet faces occurred irk the most susceptible regions, which left ligaments in the wake of t!he advancing crack front. As the overall crack con-tinued to extend, local stress intensities within the more resistant ligaments increased to the point where cracking reinitiated and propagated across the ligaments. As a result, local cracking direc-tions within these ligaments were often* normal to the overall cracking direction, The rapid crack advance in the more suscep-tible regions is believed to be a significant contributor to the en-vironmental acceleration observed in high temperature water. Spe-Fig. 12 Feactographe ol 304 SS fatigue tested In (a) 24"C air cifically, this rapid cracking not ondy increased the overall crack showing Irregular facets (b) 2880C air showing cleavage-like length, it increased local stress and provided alternate paths for facets (c), 2886C water with crystallographic facets that are reinitiating local cracks along the more resistant ligaments. sharp. cleavage-like, and highly angular. The role of active path dissolution versus hydrogen embrittle-mrent in causing accelerated cracking of stainless steel in high temperature water remains an issue because of the coupled nature, utg. on the facets were very straight, but their spacing was iden- of these processes, as clectrocliemical, reactions near the crack tip tical to macroscopic crack growth rates indicating that they were involve both anodic dissolution of the metal and a cathodic reac-fatigue striations, At growth rates above 3 X l0-4 mtn/cyvIe, stria- tion that produces hydrogen. The presence of well-defined crys-tions had a ductile or wavy appearance, as shown in Fig- 13(b). tallographic features indicates the absence of significant metal dis-Pacet and striation orientations on fracture surfaces generated in solution, thereby suggesting that slip/dissolution, is not the 288'C water revealed that local cracking directions were often primary cause of accelerated cracking, This observation is consis-Ivery different from the overall cracking direction. Although facets tent with) findings by Chopra and Stnith [10] that crack growth were usually aligned in the cracking direction, some were aligned rtes for 304 SS are greater in low dissolved oxygen water then in :a: normal to the macroscopic cracking direction (Figs. 12(c) and high dissolved oxygen water. This observation cannot be recon-I'1(a)). Likewise, most striations were oriented normal to overall ciled with a slip/dissolution mechanism. .kivg direction, but in some rgions striationus had different The presence of sharp, crystallographic facets suggests that a tateons and in sorne cases were even parallel to the macro- hydrogen embrittlement mechanism is responsible for accelerated scopic cracking direction, These observations indicate that crack cracking in 288'C water. This is supported by fractograpbic find-advance in water involved a very Oneven ptocess, as crackling first 324 I Vol. 126, AUGUST 2004 ings by Haoninen and Hakarainen [30) where hydrogen-Transactions of the ASME L. 06/01/2008 19:59 3017623511 NOVERFLO PAGE 05 precharged 304 SS exhibited cleavage-like facets without any de- Much of literature data in hydrogenated water chemistry shows tectable a' martensite formation. The facet morphology for the an apparently mild environmental effect for 304 SS. with an ER ot hydrogen-precharged specimens is very similar to that observed in 2.55 or less. However, based on the current test results, larger 2880 C water, thereby implicating hydrogen in promoting acceler- environmental effects occur in hydrogenated water in the low AK ated cracking in high temperature water, Moreover, Gao et al. [26] regime at long rise times and high K-ratio conditions. 'and We6 et RI. [273 demonstrated that a hydrogen ewbrittlement The high' crack growth rates in 2880 C deacrated water were mechanism was responsible for accelerated fatigue crack growth associated with a faceted growth mechanism. The highly angular, rates in stainless steel alloys tested in room temperature aqueous cleavage-like appearance of the facets suggests that a hydrogen civirommfnts- Although ca martensite formation occurred in.these embrittler-ent mechanism was the primary cause of accelerated specimens, Gao and Wei determined that this transformation did cracking in this environment, not have a critical role in controlling crack growth ratesand it was not a prerequisite for hydrogen embrittlement. Acknowledgment Although hydrogen embrittlernt is believed to. be the primary cause of environmental cracking in 2881C water, it is possible that This work was performed under U.S. Department of Energy oxide film formation at the crack tip also affects cracking behavior Contract with Bechtel Bettis, Inc. The authors wish to acknowl-by restricting slip reversals during the unloading portion of fatigue edge the efforts of H. K. Shen, A. I. Bradfield, J. T- Kandra, and J. cycles. The importance of oxide film formation in affecting frac- I. Chasko in performance of these experiments. ture surface morphology is apparent when comparing fracture sur-faces generated in air and vacuum. Fatigue fracture surfaces gen- References cl,'"u naLscli p osseVa ctya*tL lC*i;t'ala.J JI't'-IZ' WL t111)0e [1] Wire, G. L-., and Mills, W. J_2001, "Fatigue Crack Prpagation From Notched generated in vacuum had a nondes'cript, nonfaceted appearance Specirmens of 304 Stainless Sfeel in An Elevated Temperature Aqueous Envi-0 (Wire [1]). Apparently, the thin oxide film that forms in 24 C air ronroent," PVF-Vol. 439, Pre*uure Verjet and Piping Co*es and Srandap,.- serves as a dislocation barrier that impedes slip reversals during 2002, PvP-2002-1232, ASME, New York, pp. 151-164. -,unloading cycles. Hence, damage uetend to be concentrated along [2) Evans, W. M,. and Wire, G. L.. 2001, "Fatijuo Crack Propagation Behavior of 304 StaIn Steol From Compact Tlbnsion Specimens in An Eltvated,Tcm. 'particular slip bands, and eventually local separation along these pera(ure Aqueous Environment," P'VP-Vol. 439. Priesure Vessel and Pipslg slip bands produces crystallographic facets, In vacuum, the ab-. Codes and Jtundurds.2002, PVP2002-1226. ASME. New York, pp. 91-98. sence of an oxide 'film promotes more effective slip reversals that (3) Wire, G. L., L.ax, T.R.. and Kandra, J.T,, 1999, 'Mean Stresi and Environ, minimizes local damage along any particular slip band. As a re- mental Effects on Fatigue In Type 304 Stajnless Steel," Probabillstlk aad yEnvironnental Aspects of Fracture and Fatigue,PYP-VoI. 306, ASME, New suit, crystallographic facets do not develop n vacuum. Oxide film I York, pp. 213-225. formation in water is also expected to restrict slip reversals and (4) Schijvc. 1.. 1982. "The Stress tIteosirty Factor of Small Cracks at Notches," promote facet formation and higher crack growth rates; however. Fatiguc Fract. Eng, Mater, Stret., 5(1), pp. 77-90. the degree of acceleration is expected to by much less than that t [5] Toda, H., Paris, P.C., and lr-,in$.G. R., 2000, The Sross Analysis of Cryeks Handbook, ASME. associated w'ith hydrogen embrittlement. (6,j Yarnanoto. Y.. Semi, Y,, and Aon K., 1974. "Stress Intcnsity Factors of Cracks In summary, it is unlikely that slip/dissolution is a primary Emanoating Prom Semi-Elliptical Side Nt)tcbes in Plates." tnt. J. Fract.. 10(4). cause of environmental cracking in 288VC hydrogenated water p.593. because of the presence of crisp crystallographic features and an (7) Newman, 1. C., 1992, "Fracture Mecbanicrs Parameters for the Small Fatigue Cracks," Smoll Crao'k Test Methado, ASTM STP 1149, pp, 6-33. increase in crack growth rates with decreasing dissolved oxygen [(] lames, L- A.. and Jones. D. F..1985. "Fatigue Crack Growth Corrtlatibns Aor levels (Chopra and Smith, t10]), The" cleavage-like facets on the Auacnitic Stainles Ste4ls it) Air," Prudictive Captbfllrtes ft Envft~rnrnntully fracture surface, which are very similar to facets found in Ascisred Craeklng, PVP Vol. 99, pp. 363-;414. hydrogen-precharged 304 SS (Hanninen and Hakaraine* [30]), [~] Lalur, P, Sehitoglu, H., and McClung, R, C., 3986,A'Mechasie0 -A.spcctst'f Stall Crack Girowth From Notcha.f-the Role of Crack Closure," The Behavior suggest that hydrogen embrittlement is the primary cause of ac- of Short Fatigue C7rauk, EGF Pub. I, K, J. Miller and E. R. de los Rio., rcdh., celerated cracking in high temperature water. It is also likely that Mechanical E~ngineerig Publications, London. pp. 369-386. the formation of crack tip oxides restricted slip reversals which ['01 Chopra, 0. K.. and Smith. J. L., 1995, "Eatimation of Fatigue Strain-Life this Curves For Ausmtnitic Stainless Steels in Light Water Reactor Fnvironments." also contributed to increased crack growth rates, although this Fa ,tilronmeatalFactors, and New Materlsb, PVP Vol. 374, ASME_ effect is expected to be much smaller effect than that associated New York. pp. 249-239. with hydrogen embrittlement, (It') Scott, P. M., 1988, "A Review of Eavl'orassal Elfeta on Preasure Vcral Integrity," Proc'edings of the Third Envimnnental Dtgradatioanif Morerials in Nuclear Power Systems- Wafer Reactors. TMvS. pp. 15-29. 5 Summary and Conclusions (12) Shoji, T.. Takahasi. H.. Suzuki, MJ and Kondo. T,. I981, "A New Parometer -for Characteriina Corrosion Fatigue Crack Growth," ASME J. Eng. Mater. 29 0 Instrumented corrosion fatigue tests on 3045S DEN specimens Technol., 103. pp,. 0-3 4, provided fatigue crack growth rate data in ' and 288 Cxair and [)31 LCAx, T. R., t999, "Statislical Modols of Mean Stress and Water Eavieonment 288 0 C water over a wide range of crack growth 24 rates. Results in Effects on t'h. Fatigue Uchavior of 304 Stainless Steal," Praisabilistic a*d cEnvironmentalAspects, of Fracture and Fatigiue, PVP Vol. 386, ASME. New air and water ait the saone mechanical parameters allowed direct York. pp 229-239, assessment of environmental effects, avoiding any concerns for (141Gaogloff, P. P.. 3913, "Crack Size Efforts an the Chermical Driving Force for data variability due to materials, test technique, and dýta correla- fl Aqueous Corrosion Fatigue." Metall. TYans, A, lclA, pp. 953-969. Shack, W. J.. and Kassner, T. F, 1994, "'Review or Environmentral Effelct on )[15 dion. Crack growth rates in water are about 12X times the air rate V1'atiue Crack Growth of Au.senlrle Stainless Steels,", NUREGfCR-6176. at low speeds where the environmental effects are largest. The ANL-94/l. large envirnmental degradation in crack growth is consistent (16) Prt(or., '. A.. Catlin, W. R.. and Coffin, L. P., 1985, "Effect of t4ydrogen with the strong reduction of fatigue life in commercial PWR wa- Additions to Water on the Corrosion Fatigue Behavior of Nuclea Structural ter. Further, very similar crack growth rate data were reported in Mvaterials," Ptoceedines of the Sec6nd h!remationol Symposium on Environ-mental Degrodatiunof Materials is Nuclear Power Syn'teacs Water Reaclors, low oxygen HWC. in both surface crack and conventional deep NACE, PP. 605-623. crack tests. The large environmental enhancement in 304 55 '17] Gordon, b. M., IndiE, M. E., Davis, R.a., Pickett, A. E.. and Jewett, C. W., (12?<) persisted to crack extensions up to 4.1 amm. far outside the 1985. "Envimnmentally Assisted Cracking Resistance of BWR Structural Ma-* e fpts.Te (12))persistedto cracksame larg- teals in Hydrojgen Water Chrmnistry." Proceedings of thk Second Interna. range associated with short crack effects, The stme large environ- aionel Sympa3ium on Envfronmental Degradation of Mate,'lslts in Nuclea, mental effects observed in the DEN tests were reproduced in CT Power Syvlrems-lare, Reactors, NACE. pp, 583-592. 1 specimens at'a high stress ratio and low AK. Theoverall results [181 Jowett, C.W., and Pickctt, A. f-, 1986, "The Benefit of Hydrogen Addition to can be normalized successfully by incorporating 'the combined the Boiling Water Reactor Environment on Stress Corrosion Crack lnitiation effects of stress ratio and rise time, qualitatively 'similar to the and Growth in Type 304 Staintlen Stael," ASME 3. &fug.Moter. Tech'ol.. 1,08. formulation developed by Itatani et al. to describe test results in pp .jngbere,L. G.. 1989."Effect ofWatr" Impurities in BW9 o. Environrnn-BWR Water. tal Crack Growth Under Realistic Load Conditions," Promeedings of the Journal of Pressure Vassel Technology AUGUST 2004, Vol, 126 / 325 4J Founh IJnremorionoi Sy^rwosijnz on Environmental in NuclearPower Sysrem'- Degradotioi of MAierlu.ls [20] Andresen. P. L., Water Re~tctor.r. t4ACE. [25)] Itstai, M., Aacno, and Cornpbell. P. G., pp, 4-59-4-75. M.. Yikuchi, M.. 5uzul. High Thmpcratuic Water 1989, "The Uffc(*' of Crack Growth Curve 3,, and lida, K. 2001. and Ite Crack Closure in for Ausletitic Stainless "'Fatigue Role in Inllueseing' CrTAck ASME J. Pressure Vessel Steels Proceedisigs of the Fourth /ttmnationat Symposiunr Closure Data," TechnoL, 123. pp, 166-172 in BWR Environmcnt,'" dalion of Materialx be Nuclear on &mtironmental Degrao (26] Gao, M.. Chen, S., and Wei, R. P, 1992, NACER, pp. 4-86-4-110. Power 5yeens' Wetter Fatigue Crack Grnwth "Crack Paths, [21] Gilman, I. D.. 1988, Reactrs, Jekyll lslectd, in Annealed and Cold-Rolled Micrnsutecture, and "Corrosion-Fatiguc CratA-Q-rowth Stce.l," MvieatI. Trans. AISI 304 Stainless Stainless Steels in Uigbh A, Z3A. pp. 355-371. Water RPeactor F0nvirontmentn," Race. in Austeniie [27] Wei, R. P., and Gao, Piping, 31, pp. 55-68. 1w,.], Prcemure Ve,4rFlK M_. 1993, "MiCroMechAnisat Growth ire Metastable (22] Barrfdord, W. H4., Ausmritiic Stainless Steels, for Corrosion Fatigue Crack 1979, "Fatigue Crack terrrtio't LeasEditions " C,'irrrslon-Dbftnatietrn Press*riszed Water keacwtr Growth of In-101, pp. 73-79. Environient,' ASME Staitless Steel Piping in a (28) Mills. W. I., and'James, de. Physique, tea Ulis, France, pp, 619-629. J. Pres,%tsuVesel T'hrcsrol. L. A., 1988, "Fatigue (23] Culen, W. 9,, 1985, 'Type 316 Stainless Stee Crack Propagation Behavior "Patiguc at Elevated Temperature of ljeas Piping Steels in PWR Crack Growtb Ra(en of Low-Carbon tipse. 10, pp. 33-36. in a Vacuum," Ilo. J. Va-NUREOUCR-3945, MEA,2055, (Pre.sutizod Water Reactor) Environmetnt," and Stain- [z2j Lacombe, P., and [24] Bernard, 1,L., Slamsa, iBeraItgcr. C., 1993, "Structure Various Stainless Stoel ment on Fatigue Crack G.. and Rabbe, P., 1979, "'nflue(ce of PWR Environ- Grades," Stainless Steels.and Elquilibrium Diagrams of Growth Behavior of Les Uls, France, pp. Les Editions de Physique. Dep*endent Degrddation Slainlexs Stelas," Time J5-58. of Pts.fure Bouocdory and LoaSd [30)] Kt'anne', V4.,and Interancional Atomic Mcterlals, IWO.RRPC-79/2, l4akarainen, T., 1961, Energy Agency, pp. Hydrogen Ecmhrittletnetlt "On the Effeccs of a' 27-36. MaNrtensite in Stainless Steel," Corrosionor a Cathudlcally Charged M4ST Type 304 Austenitic (R-Iuswtoc), 36. pp. 47-5t. -x 2 326 / VoL 126, AUGUST 2004

• ~~Transactions o the ASME.I:,

of 2 NEC-JH 67 UNITED STATES NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY LICENSING BOARD -- -----.---------.................-------------------------- x In re: Docket Nos. 50-247-LR and 50-286-LR License Renewal Application Submitted by ASLBP No. 07-858-03-LR-BD01 Entergy Nuclear Indian Point 2, LLC, DPR-26, DPR-64 Entergy Nuclear Indian Point 3, LLC, and Entergy Nuclear Operations, Inc. May 22, 2008

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x NEW YORK STATE'S SUPPLEMENTAL CITATION IN SUPPORT OF ADMISSION OF CONTENTION 26A On May 14, 2008 - two weeks after the State of New York submitted its Reply to Entergy's Answer and NRC Staff's Response to New York's Supplemental Contention No.26-A (Metal Fatigue) - the NRC Staff posted on ADAMS a May 8, 2008 Summary of an April 3, 2008 telephone conference between Entergy and Staff regarding, inter alia, how much information NRC Staff would require Entergy to produce as part of its License Renewal Application.' The Summary is contained in Attachment I to this Supplement, and is also available at ML081190059. The May 8 Summary reveals that Entergy, with the acquiescence of Staff, does not intend to allow the details of how it will address metal fatigue issues to be made a part of this license renewal proceeding. Enclosure I to May 8, 2008 Summary of April 3, 2008 Telephone Conference, at pages 1 to 3.

This newly-disclosed information supplements the statements made by New York State in

/

its May 1, 2008 Reply at the end of the first full paragraph on page 10.

'The New York State Office of the Attorney General received a copy of the May 8, 2008 Sununary via U.S.

Mail on May 19, 2008.

Respectfully submitted, May 22, 2008 Joan Leary Matthews J bk. Sipos Senior Attorney for Special Projects Janice A. Dean New York State Department Assistant Attorneys General of Environmental Conservation Office of the Attorney General 625 Broadway, 14th floor for the State of New York Albany, New York 12233-5500 The Capitol (518) 402-9190 Albany, New York 12224 jlmatthe@gw.dec.state.ny.us

,(518) 402-2251 john.sipos@oag.state.ny.us John Louis Parker, Esq.

Regional Attorney New York State Department of Environmental Conservation 21 South Putt Comers Rd New Paltz, NY 12561-1620 r

ATTACHMENT 1 NRC May 8, 2008 Summary of an -

April 3, 2008 telephone conference between Entergy and NRC Staff also available at ML081190059

(

UNITED STATES NUCLEAR REGULATORY COMMISSION wiZ WASHINGTON, D.C. 20555-0001 May 8, 2008 h._

LICENSEE: Entergy Nuclear Operations, Inc.

FACILITY: Indian Point Nuclear Generating Unit Nos, 2 and 3

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON APRIL 3,2008, BETWEEN THE U.S. NUCLEAR REGULATORYCOMMISSION AND ENTERGY NUCLEAR OPERATIONS, INC,, CONCERNING RESPONSES TO REQUEST FOR ADDITIONAL INFORMATION RELATED TO THE INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3, LICENSE RENEWAL APPLICATION-METAL FATIGUE, BOLTED CONNECTIONSt AND BORAFLEX The U.S. Nuclear Regulatory Commission (NRC or the staff) and repr~esentatives of Entergy Nuclear operations. Inc., held a telephone on April 3, 2008, to discuss and

-conferencecall c.,larify the staffs draft request for additional information (D-.RAI) concerning the Indian Point Nuclear Generating Unit Nos. 2 and 3, license renewal application. The telephone conference call was useful in clarifying the intent of the staff's D-RAI.

Enclosure 1 provides a listing of the participants and Enclosure 2.contains a listing of the D-RAI items discussed with the applicant, including a brief description on the status of the items.

The applicant had an opportunity to comment on this summary.

Kimberly Green, Safety.Project Manager Projects Branch 2 DMsion. of License Renewal Officeobf Nuclear ReactorRegulation Docket Nos. 50-24,7 and 50-286

Enclosures:

1. List. of Participants 2., Summary of Discussion Th cc w/encls: See next page

Indian Point Nuclear Generating Units 2 and 3 cc:

Senior Vice President Mr. John P. Spath Entergy Nuclear Operations, Inc. New York State Energy, Research and P.O. Box 31995 Development Authority Jackson, MS 39286-1995 17 Columbia Circle Albany, NY 12203-6399 Vice President Oversight Entergy Nuclear Operations, Inc. Mr. Paul Eddy P.O. Box 31995 New York State Department Jackson, MS 39286-1995 of Public Service 3 Empire State Plaza Senior Manager, Nuclear Safety & Albany, NY 12223-1350 Licensing Entergy Nuclear Operations, Inc. Regional Administrator, Region I P.O. Box 31995 U.S. Nuclear Regulatory Commission Jackson, MS 39286-1995 475 Allendale Road King of Prussia, PA 19406 Senior Vice President and COO Entergy Nuclear Operations, Inc. Senior Resident Inspector's Office 440 Hamilton Avenue Indian Point 2

,White Plains, NY 10601 U.S. Nuclear Regulatory Commission P.O. Box 59 Assistant General Counsel Buchanan, NY 10511 Entergy Nuclear Operations, Inc.

440 Hamilton Avenue Senior Resident Inspector's Office White Plains, NY 10601 Indian Point-3 U.S. Nuclear Regulatory Commission Manager, Licensing P.O. Box 59 Entergy Nuclear Operations, Inc. Buchanan, NY 10511 Indian Point Energy Center 450 Broadway, GSB Mr. Charles Donaldson, Esquire P.O. Box 249 Assistant Attorney General Buchanan, NY 10511-0249 New York Department of Law 120 Broadway Mr. Paul D. Tonko New-York, NY 10271 President and CEO New York State Energy Research and Mr. Raymond L. Albanese Development Authority Four County Coordinator 17 Columbia Circle 200 Bradhurst Avenue Albany, NY 12203-6399 Unit 4 Westchester County Hawthorne, NY 10532 Mayor, Village of Buchanan 236 Tate Avenue Buchanan, NY 10511

Indian Point Nuclear Generating Units 2 and 3 cc:

Mr. William DiProfio John Sipos PWR SRC Consultant Assistant Attorney General 48 Bear Hill Road New York State Department of Law Newton, NH 03858 Environmental Protection Bureau The Capitol Mr. Garry Randolph Albany, NY 12224 PWR SRC Consultant 1750 Ben Franklin Drive, 7E Robert Snook Sarasota, FL 34236 Assistant Attorney General Office of the Attorney General Mr. William T. Russell State of Connecticut PWR SRC Consultant 55 Elm Street 400 Plantation Lane P.O. Box 120 Stevensville, MD 21666-3232 Hartford, CT 06.141-0120 Mr. Jim Riccio Ms. Kathryn M. Sutton, Esq.

Greenpeace Morgan, Lewis & Bockius, LLP 702 H Street, NW 1111 Pennsylvania Avenue, NW Suite 300 Washington, DC 20004 Washington, DC 20001 Mr. Paul M. Bessette, Esq.

Mr. Phillip Musegaas Morgan, Lewis &,Bockius, LLP Riverkeeper, Inc. 1111 Pennsylvania Avenue, NW 828 South Broadway Washington, DC 20004 Tarrytown, NY 10591 Mr. Martin J. O'Neill, Esq.

Mr. Mark Jacobs Morgan, Lewis & Bockius, LLP

)

IPSEC 1111 Pennsylvania Avenue, NW 46 Highland Drive Washington, DC 20004 Garrison, NY 10524 The Honorable Nita Lowey Mr. R. M. Waters 222 Mamaroneck Avenue, Suite 310 Technical Specialist Licensing White Plains, NY 10605 450 Broadway P.O. Box 0249 Joan Leary Matthews Buchanan, NY 10511-0249 Senior Counsel for Special Projects Office of General Counsel Mr. Sherwood Martinelli NYS Department of Environmental 351 Dyckman Conservation -

Peekskill, NY 10566 625 Broadway Albany, NY 12233-5500 Ms. Susan Shapiro, Esq.

21 Perlman Drive Spring Valley, NY 10977

TELEPHONE CONFERENCE CALL K INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION LIST OF PARTICIPANTS APRIL 3, 2008 PARTICIPANTS AFFILIATIONS Kim Green U.S. Nuclear Regulatory Commission (NRC)

On Yee NRC Peter Wen NRC Jim Davis NRC Bo Pham NRC Jim Medhoff NRC Mike Stroud Entergy Nuclear Operations, Inc. (Entergy)

Garry Young Entergy Alan Cox Entergy Ted Ivy Entergy Don Fronabarger Entergy Charlie Caputo ,Entergy John Curry Entergy Nelson Azevedo Entergy Charlie Jackson Entergy ENCLOSURE1

DRAFT REQUEST FOR ADDITIONAL INFORMATION INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION METAL FATIGUE April 3, 2008 The U.S. Nuclear Regulatory Commission (NRC or the staff) and representatives of Entergy Nuclear Operations, Inc., held a telephone conference call on April 3, 2008, to discuss and clarify the following draft requests for additional information (D-RAIs) concerning the Indian Point Nuclear Generating Unit Nos. 2 and 3 license renewal application (LRA).

D-RAI 4.3.1.8-1 License Renewal Application Section 4.3.1 states "Current design basis fatigue evaluations calculate cumulative usage factors (CUFs) for components or sub-components ,based on design transient cycles." For CUF values listed in LRA Tables 4.3-13 and 4.3-14, please provide the methodology used with sufficient results of the fatigue analysis such that the staff can make a determination based on the guidance described in Standard Review Plan-License Renewal (SRP-LR) (NUREG-1800). Specifically, please describe the details of how environmentally assisted fatigue (EAF) is factored into the calculation of the CUF using Fen values.

Discussion: The applicant was uncertain as to whether the staff was requesting that they provide the evaluations or a description of evaluations. Based on the discussion with the applicant, the staff agreed to revise this question as follows. The revised question will be sent as a formal RAI.

License renewal application (LRA) Section 4.3.1 states "Current design basis fatigue evaluations calculate cumulative usage factors (CUFs) for components or sub-

,components based on design transient cycles." For CUF values listed in LRA Tables 4.3-13 and 4.3-14, please describe the details of how various environmental effects are factored into the calculation of the CUF using Fen values.

D-RAI 4.3.1.8-2 N From the review of EAF analysis of other plants, it was found that the transfer function methodology used in the EAF analysis may not provide valid results, as it is dependent on the inputs. To assist the staff in its review, please provide the EAF analysis for all the NUREG/

CR-6260 locations (components) at Indian Point unless it can be demonstrated that the CUF value is within the ASME Code limit of 1.0 by using the original 40-year analysis value adjusted for 60 years and multiplied by Fen, which is consistent with SRP-LR and ASME Code. This analysis should be completed by using NRC-approved fatigue software and the ASME Code,Section III, Subsection NB-3200 methodology (which defines the use of six stress components to determine the stress state and thereby calculates the principal stresses and stress intensities). Justify the analysis method, the load (stress) combination, and the results of the ASME Code analysis if 2-D axis-symmetric modeling is used. In addition, the analysis should apply ASME code rules such as elastic-plastic correction factor, K,, and stress intensities correction factor for modulus of elasticity. This analysis should be performed without the use of the transfer function method.

ENCLOSURE 2

Discussion: The applicant wanted clarification on the staff's request The applicant pointed out that the request is a new staff position and that for previous plants, the staff has not requested the analyses to be provided and has accepted a commitment to perform the analyses two years prior to entering the period of extended operation as part of the Fatigue Monitoring Program in accordance with 10 CFR 54.21 (c)(1)(iii). Subsequent to the telephone conference, the staff determined that no additional information is needed at this time. Therefore, a formal RAI will not be issued at this time.

D-RAJ 4.3.1.8-3 SRP-LR Section 4.3.2.1.1.3 provides the basis for the staff acceptance of an aging management program to address environmental fatigue. It states, "[Tihe staff has evaluated a program for monitoring and tracking the number of critical thermal and pressure transients for the selected reactor coolant system components. The staff has determined that this program is an acceptable aging management program to address metal fatigue of the reactor coolant system components according to 10 CFR 54.21(c)(1 )(iii)." The staff is unable to determine ifthe Fatigue Monitoring Program of IP2 and IP3 contain sufficient details to satisfy this criterion, based on the NA items listed in LRA Tables 4.3-13 and 4.3-14. Please provide adequate details of the Fatigue Monitoring Program, specifically the fatigue analysis used in determining the CUF values for the NA locations and how IPEC plans to proceed in monitoring the locations of Tables 4.3-13 and 4.3-14 during the period of extended operation.

Discussion: The applicant wanted clarification on what the staff is requesting. Based on the discussion with the applicant, the staff agreed to revise this question as follows. The revised question will be sent as a formal RAI.

Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP-LR) Section 4.3.2.1.1.3 provides the basis for the.staff acceptance of an aging management program to address environmental fatigue. Itstates, "[tjhe staff has evaluated a program for monitoring and tracking the number of critical thermal and pressure transients for the selected reactor coolant system components.-

The staff has determined that this program is an acceptable aging management program to address metal fatigue of the reactor coolant system components according to 10 CFR 54.21(c)(1)(iii)." The staff is unable to determine ifthe Fatigue Monitoring Program for Indian Point 2 and Indian Point 3 contains sufficient details to satisfy this criterion. Please provide adequate details of the Fatigue Monitoring Program such that the staff can make a determination based on the criterion set forth in SRP-LR Section 4.3.2.1.1.3. Also, please explain in detail the corrective actions and the frequency that such actions will be taken so that the acceptance criteria will not be exceeded in the period of extended operation; (This RAI will be renumbered as RAI 4.3.1.8-2.)

D-RAI 4.3.1.8-4 Section B.1.12 of the LRA amendment, dated January 22, 2008, states, "Ifongoing monitoring indicates the potential for a condition outside that analyzed above, IPEC may perform further reanalysis of the identified configuration using established configuration management processes as described above." Please explain in detail what is meant by the phrase "using established configuration management processes." Also, please explain in detail the corrective actions and the frequency that such actions'will be taken so the acceptance criteria will not be exceeded in the period of extended operation.

Discussion: The applicant stated that it was unclear about the staffs request regarding "configuration management processes." In a subsequent call, the applicant explained that the configuration management processes referred to are those governed by its 10 CFR Part 50, Appendix B Quality Assurance program, and include design input verification and independent reviews which ensure that valid assumptions, transients, cycles, external loadings, analysis methods, and environmental fatigue life correction factors will be used in the fatigue analyses.

Therefore, this portion of question is withdrawn and will not be sent as a formal RAI. The portion of the request that deals with corrective actions will be added to RAI 4.3.1.8-2 (as renumbered).

Non-EQ Bolted Cable Connection AMP D-RAI 3.0.3.3.6-1

-With regard to Indian Point Aging Management Program (AMP) B.1.22, "Non-EQ Bolted Cable Connection Program," the license renewal application states that inspection methods may include thermography, contact resistance testing, or other appropriate methods including visual, based on plant configuration and industry guidance. In Generic Aging Lessons Learned (GALL)

AMP XI.E6, the staff recommends thermography, contact resistance testing, or other' appropriate methods based on plant configuration and industry guidance for detecting loss of preload or bolt loosening. In the case where visual inspection will be the only method used, provide a technical basis of how this will be sufficient to detect loss of preload or loosening of bolted connections.

Discussion: The applicant stated that this question is similar to an audit question that has been answered and subsequently discussed during two telephone conferences. This issue is being reviewed by the Division of Engineering and, therefore, is withdrawn at this time., However, when the staff has reached a determination, a formal RAI may be issued at such time.

Boraflex AMP-D-RAI 3.0.3.2.3-1 Indian Point 2 Updated Final Safety Analysis Report, Revision 20, dated 2006, Section 14.2.1 on page 55 of 218, states in part that:

"Northeast Technology Corporation report NET-173-01 and NET-1 71-02 are based on conservative projections of amount of boraflex absorber panel degradation assumed in each sub-region. These projections are valid through the end of the year 2006."

Please confirm that the Boraflex neutron absorber panels in the Indian Point Unit 2 spent fuel pool have been re-evaluated for service through the end of the current licensing period. Also, please discuss the plans for updating the Boraflex analysis during the period of extended operation.

Discussion: The applicant indicated that the question is clear. This D-RAI will be sent as a formal RAI.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY LICENSING BOARD

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6 In re:

Docket Nos. 50-247-LR and 50-286-LR License Renewal Application Submitted by ASLBP No. 07-858-03-LR-BDO0 Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, and DPR-26, DPR-64 Entergy Nuclear Operations, Inc.

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. x CERTIFICATE OF SERVICE Pursuant to 28 U.S.C. § 1746 Teresa Fountain hereby declares:

I am over 18 years old and am an employee in the New York State Office of the Attorney General.

I hereby certify that on May 22, 2008, copies of "The State of New York's Supplemenital Citation In Support of Contention 26A" were served upon the following persons via electronic mail and by deposit in the U.S. Postal Service with first class postage:

Lawrence G. McDade, Chair Kaye D. Lathrop Administrative Judge Administrative Judge Atomic Safety and Licensing Board Panel Atomic Safety and Licensing Board Panel U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Mailstop 3 F23 190 Cedar Lane E.

Two White Flint North Ridgway, CO 81432 11545 Rockville Pike Kaye.Lathrop@nrc.gov Rockville, MD 20852-2738 Lawrence.McDade@nrc.gov. Atomic Safety and Licensing Board Panel U.S. Nuclear Regulatory Commission Richard E. Wardwell Mailstop 3 F23 Administrative Judge Two White Flint North Atomic Safety and Licensing Board Panel 11545 Rock-ville Pike U.S. Nuclear Regulatory Commission Rockville, MD 20852-2738 Mailstop 3 F23 Two White Flint North Zachary S. Kahn, Esq.

11545 Rockville Pike Law Clerk Rockville, MID 20852-2738 Atomic Safety and Licensing Board Panel Richard.Wardwell@nrc.gov U.S. Nuclear Regulatory Commission Mailstop 3 F23 Two White Flint North 11545 Rockville Pike Rockville, MD 20852-2738 Zachary.Kahn@nrc.gov Marcia Carpentier Elise N. Zoli, Esq.

Law Clerk Goodwin Procter, LLP Atomic Safety and Licensing Board Panel Exchange Place U.S. Nuclear Regulatory Commission 53 State Street Mailstop 3 E2B Boston, MA 02109 Two White Flint North ezoli@goodwinprocter.com 11545 Rockville Pike.

Rockville, MD 20852-2738 WilliamC. Dennis, Esq.

Marcia.Carpentier@nrc.gov Assistant General Counsel Entergy Nuclear Operations, Inc.

Office of Commission Appellate Adjudication 440 Hamilton Avenue /

U.S. Nuclear Regulatory Commission White Plains, NY 10601

• Mailstop 16 G4 wdennis@entergy.com One White Flint North 11555 Rockville Pike Robert D.- Snook, Esq.

Rockville, MD 20852-2738 Assistant Attorney General ocaamail@nrc.gov Office of the Attorney General State of Connecticut Office of the Secretary 55 Elm Street Attn: Rulemaking and Adjudications Staff P.O. Box 120 U.S. Nuclear Regulatory Commission Hartford, CT 06141-0120 Mailstop 3 F23 robert.snook@po.state.ct.us Two White Flint North 11545 Rockville Pike Justin D. Pruyne, Esq.

Rockville, MD 20852-2738 Assistant County Attorney hearingdocket@nrc.gov Office of the Westchester County Attorney Michaelian Office Building Sherwin E. Turk, Esq. 148 Martine Avenue, 6th Floor David E. Roth, Esq. White Plains, NY 10601 Marcia J. Simon, Esq. jdp3@westchestergov.com Beth N. Mizuno, Esq.

Jessica A. Bielecki, Esq. Daniel E. O'Neill, Mayor Office of the General Counsel James Seirmarco, M.S.

U.S. Nuclear Regulatory Commission Village of Buchanan Mailstop 15 D21 Municipal Building One White Flint North 236 Tate Avenue 11555 Rockville Pike Buchanan, NY 10511-1298 Rockville, MD 20852-2738 vob@bestweb.net set@nrc-gov der@nrc.gov Daniel Riesel, Esq.

jessica.bielecki@nrc.gov Thomas F. Wood, Esq.

bnm 1n@r-c-gov Jessica Steinberg, J.D.

marcia.simon@nrc.gov Sive, Paget & Riesel, P.C.

460 Park Avenue Kathryn M. Sutton, Esq. New York, NY 10022 Paul M. Bessette, Esq. driesel@sprlaw.com Martin J. O'Neill, Esq. jsteinberg@sprlaw.com Mauri T. Lemoncelli, Esq.

Morgan, Lewis & Bockius LLP Michael J. Delaney, Esq.

1111 Pennsylvania Avenue, NW Vice President - Energy Department Washington, DC 20004 New York City Economic Development Corporation ksutton@morganlewis.com (NYCEDC) *"

pbessette@morganlewis.com I 10 William Street martin.o'neill@rmorganlewis.com New York, NY 10038 mlemoncelli@morganlewis.com mdelaney@nycedc.com cadams@morganlewis.com

)

Arthur J. Kremer, Chairman Richard L. Brodsky, Esq.

New York Affordable Reliable Electricity Alliance Assemblyman (AREA) Suite 205 347 Fifth Avenue, Suite 508 5 West Main Street New York, NY 10016 Elmsford, NY 10523 kremer@area-alliance.org brodskr@assembly.state.ny.us ajkremer@rnfpc.com richardbrodsky@msn.com Manna Jo Greene, Director Sarah L. Wagner, Esq.

Hudson River Sloop Clearwater, Inc. Room 422 112 Little Market St. Legislative Office Building Poughkeepsie, NY 12601 Albany, NY 12248 Mannajo@clearwater.org sarahwagneresq@gmail.com Stephen Filler, Esq. John LeKay Board Member FUSE USA Hudson River Sloop Clearwater, Inc. 351 Dyckman Street Suite 222 Peekskill, NY 10566 303 South Broadway fus'e_usa@yahoo.comr Tarrytown, NY 10591 sfiller@nylawlhne.com Diane Curran, Esq.

Harmon, Curran, Spielberg & Eisenberg, LLP Susan H. Shapiro, Esq. Suite 600 Wesehester Citizen's Awareness Network 1726 M Street, NW (WestCan), Citizens Awareness Network (CAN),etc. Washington, DC 20036 21 Perlman Drive dcurran@harmoncurran.com Spring Valley, NY 10977 mbs@ourrocklandoffice.com Phillip Musegaas, Esq.

Victor Tafur, Esq.

Nancy Burton Riverkeeper, Inc.

147 Cross Highway 828 South Broadway Redding Ridge, CT 06876 Tarrytown, NY 10591 NancyBurtonCT@aol.com phillip@riverkeeper.org vtafur@riverkeeper.org I declare under penalty of perjury that the foregoing is true and correct.

Executed on:

this 22nd day of May 2008 Albany, New York Teresa Fountain NEC-JH 68 Entergy CONDITION REPORT CR-VTY-2007-02133 Originator: Fales,Neil Originator Phone:ý 8024513057 Operability Required&-Y Originator Group: Eng P&C Codes Staff Reportability Required: Y Supervisor Name: LukensLarry D Discovered Date: 05/28/2007 17:06 Initiated Date: 05/28/2007 17:11 Condition

Description:

Steam Dryer Inspection Indications During RF026 reactor vessel inspections, linear indications on the Steam Dryer Interior Vertical Weld HB-V04 were identified by General Electric. Most of these indications were previously identified in RFO25 with no discernable changes noted in RF026. One new relevant indication was observed of similar appearance, orientation 'and size as those previously seen. These were documented via GE's process~by INR-IVVI-VYR26-07-10. See attached GE INR's for details.

Immediate Action

Description:

Notified Supervisor and generated CR.

Suggested Action

Description:

The new indication will need to be evaluated.

EQUIPMENT:

Tag Name T ag Suffix Name Component Code Process System Code STEAM-DRYER REACTOR MR=Y NB TRENDING (For Reference Purposes Only):

Trend Type ,Trend Code KEYWORDS KW-PRE-SCREENED FOR MRFF INPO BINNING ER1 '

KEYWORDS KW-ISI REPORT WEIGHT I EM ESPC HEP FACTOR E Attachments:

Condition Description GE INR 10

Entergy ADMIN ICR-VTY-2007-02133 Initiated Date: 5/28/2007 17:11 Owner Group :Eng P&C Codes Mgmt Current

Contact:

vw Current Significance: 'C - INVEST & CORRECT Closed by: Taylor,James M ) . 6/18/2007 16:06 Summary

Description:

Steam Dryer Inspection Indications During RF026 reactor vessel inspections, linear indications on the Steam Dryer Interior VerticalWeld HB-V04 were y identified by General Electric. Most of these indications were previously identified in RF025 with no discernable changes noted in RF026. One new relevant indication was observed of similar appearance, orientation and size as those previously seen. These were documented via GE's process by JNR-IVVI-VYR26-07-10. See attached GE INR's for details.

Remirks

Description:

Closure

Description:

CR closure review performed.

..)

Attachment Header Document Name:

luntitled Document Location j~ondition Description Attach

Title:

jGE INR 10

INIR-IVVI-VYR26-07-1 0- Steam Dryer Interior HB-V04 Indication Notification Report Plant/ Unit Comp6nent Description Reference(s)

DVD DISK IVVI-VYR26-07-58 Title 4 Steam Dryer RFO-25 IVVI Report INF # 002.

Vermont .Yankee Interior Vertical Weld RF026 Spring 2007 HB-V04

Background

During the Veirmont Yankee 2007 refueling outage, in accordance with the Vermont Yankee VT-VMY-204V10 Rev 2 Procedurej the Steam Dryer was inspected. The dryer inspection included inspection. of the Steam Dryer interior welds and components. These inspectio6ns were done with G.E'sFire.Fly ROV withcolor camera During the inspection of the HB-V04 weld (Dryer Unit Hood End Panel to HB-PL3 Plate weld), relevant linear.indicationsvwere observed in the heat affected.zone on the: Dryer Unit side of the weld. Most.of these linear indications were previously

• seenin:.RFO-25, Reference-INF # 002. When comparing this outage with last outage,.one new relevant indication is seen 00 (3 indication) of similar appearance, orientation and size as those previ6usly.seen; one indication was not seen.

(RFO25. 3th:.indication). No discernible change was noted in those indications which correlates to those of RF026.

See attached 2007 photos and sketches.

R3 tn SW tone, e an r Top

. 2700 A 90

.Sketch on the left shows the weld mnap. rollout The sketch, on the right'shows a. bottom%view of~the dryer.

N Prepared'by Dick..Hoopr . Date: 05127/07 Reviewed by: .Rodney Drazich Date- 0512_7/07 Utility Review. By: ___________Date: i ,

INR4-VVI-VYR26807-1O Steam Dryer lotHB.V04 Page !. of. 8

GE Nucreea- ETer"gy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo shows the interior of the dryer and the location of HB-V04 vertical weld.

This 2007 photo shows the top of the vane bank (on the left) and the end panel (on the right) and the vertical weld in the center INR-IWI-VYR26-07-10 Steam Dryer Int HB-V04.doc Page 2 of 8

GE Nuclear E7ergy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo is of the 1st indication from top down (Correlates to RF025: 1 st indication).

This 2007photo is a close-up of the 1s indication (Correlates to RF025: 1 st indication).

INR-IWI-VYR26-07-10 Steam Dryer Int HB-V04.doc Page 3 of 8

GE Nuiuea! Eýeqiy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo is the 2 nd indication (Correlates to RF025: 2 nd indication).

This is a 2007 photo of the 3 rd indication and is a new RF026 indication.

INR-IWI-VYR26-07-10 Steam Dryer Int HB-V04.doc Page 4 of 8

GE NclearEUeru,ý INR-IWI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 4 th indication (Correlates to RF025: 3 rd indication)

This is a 2007 photo of the 5th indication (Correlates to RF025: 4th indication).

INR-IWI-VYR26-07-10 Steam Dryer Int HB-VO4.doc Page 5 of 8

INR-IVVI-VYR26-07-1 0- Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 6 th indication (Correlates to RF025: 5th indication).

This is a 2007 photo of the 7 th indication (Correlates to RF025: 6th indication).

INR-IWI-VYR26-07-10 Steam Dryer Int HB-V04.doc Page 6 of 8

INR-IWI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 8 th indication (Correlates to RF025: 7th indication).

These 2007 photos show a linear indication and change of lighting and show a non-relevant indication (Correlates to RF025: 91 indication).

INR-IWI-VYR26-07-10 Steam Dryer Int HB-V04.doc Page 7 of 8

.. . .. .. . ...____GE NuclearEnergy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 9 th indication (Correlates to RF025: 10th indication).

This is a 2007 photo of the bottom weld area and crud line.

INR-IWI-VYR26-07-10 Steam Dryer tnt HB-V04.doc Page 8 of 8

Entergy OPERABILITY CR-VTY-2007-02133 OperabilityVersion: 1 Operability Code: EQUIPMENT FUNCTIONAL Immediate Report Code: NOT REPORTABLE Performed By: Brooks,James C 05/29/2007 21:07 Approved By: Faupel,Robert F 05/30/2007 00:30 Operability

Description:

Currently the plant is shutdown with the bolt in place. The bolt has one crimp fully engaged preventing the bolt from backing out. The need for having both crimps frilly engaged will have to be evaluated prior to-startup.

Approval Comments:

ntergyA SSIGNME N S CR-VTY-2007-02133 Version: 2 Significance Code: C - INVEST & CORRECT Classification Code: C Owner Group: Eng P&C Codes Mgmt Performed By: Wren,Vedrana 05/30/2007 13:04 Assignment

Description:

II

Entergy AS SIG NMEN TS CR-VTY-2007-02133 Version: I Significance Code: C - INVEST & CORRECT Classification Code: C Owner Group: Eng P&C Codes Mgmt Performed By: Lukens,Larry D 05/29/2007 04:46 Assignment

Description:

self identified outage constraint

Entergy REPORTABILITY [CR-VTY-2007-02133 Reportability Version: I Report Number:

Report Code: NOT REPORTABLE Boilerplate Code: NOT'REPORTABLE Performed By : Devincentis,James M 05/29/2007 08:09 Reportability Description.

Not reportable - This condition does not meet the Reportability screening criteria contained in AP00l0 or AP0156. The Steam Dryer is NNS and performs no safety releted functions. VY has a commitment to provide the results of the steam dryer inspections to the NRC following startup.

7-

Entergy CORRECTIVE ACTION CR-VTY-2007-02133 CA Number:

Group _ Name Assigned By: CRG/CARB/OSRC Assigned To: Eng P&C Codes Mgmt Lukens,Larry D Subassigned To : Eng P&C Codes Staff Fales,Neil Originated By: Wren,Vedrana 5/30/2007 13:00:53 Performed By: Lukens,Larry D 6/15/2007 13:17:25 Subperformed By: Fales,Neil 6/15/2007 11:49:49 Approved By:

Closed By: Taylor,James M 6/18/2007 16:02:38 Current Due Date: 06/28/2007 Initial Due Date: 06/28/2007 CA Type: DISP - CA Plant Constraint: 0 NONE CA

Description:

C - INVEST & CORRECT (Review CR for full details)

DThe CRG has initially classified this CR as "C" INVEST & CORRECT I-3 EPer the CRG, Perform an Investigation of the issues identified in this CR and determine if additional actions are E required within 30 days.

E LEnsure all Screening Comments have been addressed in the investigation - (CR assignment tab)

- Develop adequate corrective actions and issue CAs. (Due Dates per LI 102 Attachment 9.4)

OLT CAs Require Approval from Site VP/ GMPO or Director prior to initiating. Completion of Attachment 9.9 LTCA

[-'Classification Form is required.

Response

Approved. No additional corrective action required. Therefore, this CR maybe closed. LI-102 Closure Statements follow:

CR CLOSURE STATEMENTS FROM L1-102:

oDThe root cause or apparent cause is valid. VERIFIED oDThe specific condition is corrected or resolved. VERIFIED oOlOverall plant safety is'not inadvertently degraded. VERIFIED o[Generic implicati6ns of the identified condition are considered, as appropriate. VERIFIED oLActions were taken to preclude repetition, asappropriate. VERIFIED olAny potential operability or reportability issues identified during the resolution of the condition have been appropriately addressed. VERIFIED oDAII corr6ctive action items are completed. VERIFIED oL]Effectiveness Reviews have been initiated via use of Learning Organization CR, when applicable. VERIFIED Subresponse:

The new indication was evaluated by Code Programs, see the attached document. The evaluation accepts the indication as is with no repair required. The steam dryer will be inspected per the same scope in RF027 and RF028 per letter BVY 04-097, therefore the area of this indication will be inspected again during the next two outages.

Neil Fales 6/15/07 Closure Comments:

Entergy CORRECTIVE ACTION CR-VTY-2007-02133 Attachments:

Subresponse Description Evaruation K.

Attachment Header Document Name:

luntitled Document Location jSubresponse Description Attach

Title:

Evaluation

ATTACHMENT 9.1 M 9ENGINEERING REPORT COVER SHEET & INSTRUCTIONS SHEET 1 OF 2 Engineering Report No. VY-RPT-07-00011 Rev 2 Page I of 3 ENTERGY NUCLEAR

~Entergy Engineering Report Cover Sheet Engineering Report

Title:

EVALUATION OF NEW RF026 STEAM DRYER INDICATION Engineering Report Type:

New [] Revision EI Cancelled El Superseded.__ []

Applicable Site jpjl IP2 D IP3 El JAF LI PNPS EL VY wPo nI ANO I El ANO2 LI ECH E] GGNS [_ RBS LI WF3 LI DRN No. [-IN/A; EEC 1772 Report Origin: Z Entergy [] Vendor Vendor Document No.:

Quality-Related: Z Yes LI No Prepared by: Neil Fales/ /,.J " + - Date: 61 07 Responsible Engineer (Print Name/Sign)

Design Verified/ N/A Date:

Design Verifier.(if required) (Print Name/Sign)

Reviewed by:

Scott Goodwin! _.- . .-,, N V.& Date: Co5*,5 -0 7 Reviewer (Printaame/Sign)

Reviewedlby*: N/A Date:

ANH (if require~ int Name/Si Approved by: Larry Lukens/ / Date: 6'*zj 6 Supervisor ( l Sign)

• For ASME Section X1 Code Program plans per ENN-DC-120, if require

Evaluation of Steam Dryer Indication Introduction,,

During RF026 steam dryer, visual inspections, flaw indications were reported in the dryer end plates for the internal vane assemblies. Most of these indications were previously identified in RF025 and were evaluated by GE as being acceptable to leave as is per Reference I 1. The intent of this paper is to evaluate one new indication identified during RF026 and determine whether it should be accepted as is.

Discussion One new indication was found adjacent to weld HB-V04, located on bank B at the 0' end and is labeled as the 3rd indication on INR-IVVI-VYR26-07-10 Rev.1 (Reference 2).

This indication is of similar appearance; orientation and size as those previously seen.

Because of this it is being treated similar to those indications identified in RF025. The remainder of indications on the steam dryer listed as References 1-10 were previously identified and show no signs of growth. These indications are acceptable to leave as is per GE evaluation GENE-0,000-0047-2767 (Reference 11) performed in RF025.

Therefore, the one new indication described above is the only one requiring an evaluation.

It should be mentioned that not all indications identified in RF025 were re-identified in RF026. The reasons for this vary, but can be the limitations of the equipment, crud layers masking the surface of the indication or the technique of different examiners.

Evaluation of Indications GE's evaluation in RF025 cites IGSCC as being the likely cause of most of the indications previously observed. This is based on the jagged appearance and location-in the weld heat affected zone (HAZ). The unit end plates may have cold work resulting from cold forming. Cold working Type 304 material can promote initiation of stress corrosion cracks when exposed to the BWR environment. 'The dryer unit end plates are located in the dryer interior and are not subjected to any direct main steam line acoustic loading. Continued growth is unlikely (because all of these indications appear to have stopped without propagating into the vertical weld; this is indicative of IGSCC behavior as opposed to fatigue, since weld material is more resistant to IGSCC. The flanges have experienced a near infinite number of fluctuating load cycles and if fatigue driven, more significant cracking is likely to have occurred after many years of operation. IGSCC in steam dryers has been typically limited in depth and length since in many cases it is caused by cold work or weld induced residual stress.

The dyer unit end plate, with the indication, is securely attached and captured within the structure of the steam dryer bank assembly. The vertical edges of these end plates are attached to the dryer assembly with 3/16" fillet welds, each weld approximately 48" long.

There were no relevant indications reported in these vertical welds. The geometric configuration of the unit end plates is such that the steam dryer assembly mechanically captures the upper and lower edges. The reported horizontal indications were seen in the inlet side end plate flange. The vanes prevent inspection of the central, end plate surface, but inspection of the outlet side end plate flanges at both locations found no indications.

If it is postulated that the end plate horizontal indications propagate across the entire 8.75" unit end plate width including both the inlet and outlet side flange, such full width, through-thickness cracks would have no structural impact. Nor is there any concern for loose parts. The separated end plate sections are still attached and will continue to function.

/

Safety The steam dryer assembly has no safety function. See BWRVIP-06A for additional discussion of steam dryer assembly safety. The flaw indications, reported in the steam dryer INR's from RF026 will not likely result in any lost parts at operating conditions.

Therefore, there is no safety concern with continued operation~with the Reference 1-10 indications left as is.

Conclusions and Recommendations The dryer unit end plates flaw, assessment is based on the following factors: (1) it is a highly redundant structure and there is no structural consequence of the cracking and (2) postulated significant flaw extension leading to the flaw reaching the full section of the channel geometry would not create the opportunity for loose parts. Field-experience supports this as-is operation decision in the context that the indications will be re-inspected at the next outage. It is recommended that the new visual indication given in Reference 2 be accepted as is. Repair is not recommended.

References

1. GE INR-IVVI-VYR26-07-09 Rev. 1

2. GE INR-IVVI-VYR26-07-10 Rev. 1

3. GE INR-IVVI-VYR26-07-11

4. GE INR-IVVI-VYR26-07-12

5. GE INR-IVVI-VYR26-07-13

6. GE INR-IVVI-VYR26-07-14

7. GE INR-IVVI-VYR26-07-15

8. GE INR-IVVI-VYR26-07-16

9. GE INR-IVVI-VYR26-07-18

10. GE INR-IVVI-VYR26-07-1'9

11. GENE-0000-0047-2767

Entergy CORRECTIVE ACTION CR-VTY-2007-02133 CA Number: 2

-______. Group _ Name J Assigned By: Constraint Group.

Assigned To: Eng P&C Codes Mgmt LukensLarry D Subassigned To : Eng P&C Codes Staff Fales,Neil Originated By: Wren,Vedrana 5/30/2007 13:02:05 Performed By: Corbett,Patrick B 6/1/2007 17:50:21 Subperformed By: Fales,Neil 6/1/2007 16:58:55 Approved By:

ClosedBy: Wanczyk,Robert J 6/1/2007 17:54:13 Current Due Date: 66/01/2007 Initial.Due Date: 06/01/2007 CA Type: ACTION Plant Constraint: 2 STARTUP/HOTSTANDBY CA

Description:

Address Startup Constraint-due 6/1-Disposition and evaluate

Response

approve I Subresponse:

The plant can start up with the dryer indications left as is. The new dryer indication is of the same appearance, orientation and size as those previously observed. Since this new indication is located in the heat affected zone and is consistant with the other indications, this is most likely caused by IGSCC. This is consistant with the evaluations by GE. See the INR and evaluation provided.

Neil Fales 6/1/07 Closure Comments:

Attachments Subresponse Description Evaluation Subresponse Description GE INR 10

Attachment Header Document Name:

untitled Document Location ISubresponse Description Attach

Title:

jEvaluation

Evaluation of Steam Dryer Indications Introduction During-RFO26 steam dryer visual indications, flaw indications were reported in the dryer end plates for the internal vane assemblies. Most of these indications were previously identified in RF025 and were evaluated by GE as being acceptable to leave as is per Reference 11. The intent of this paper is to evaluate one new indication identified during RF026 and accept it 'as is.

Discussion One new indication was found adjacent to weld HB-V04, located on bank B at the 0' end and is labeled as the 3d indication on INR-IVVI-VYR26-07-10 Rev. 1 (Reference 2).

This indication is of similar appearance, orientation and size as those previously seen.

Because of this it is being treated similar to those indications identified in RF025. The remainder of indications on the steam dryer listed as References 1-10 were 'previously identified and show no signs of growth. These indications are acceptable&to leave as is per GE evaluation GENE-0000-0047-2767 (Reference 11) performed in RF025.

Therefore, the one new indication described above is the only one requiring an evaluation.

It should be mentioned that not all indications identified in RF025 were re-identified in RF026. The reasons for this vary, but can be the limitations of the equipment, crud layers masking the surface of the indication or the technique of different examiners.

Evaluation of Indications GE's evaluation in RF025 cites IGSCC as being the likely cause of most of the indications previously observed. This is based on the jagged appearance and location in the weld heat affected zone (HAZ). The unit end plates may have cold work resulting from cold forming. Cold working Type 304 material can promote initiation of stress corrosion cracks when exposed to the BWR environment. The dryer unit end plates are located in the dryer interior and are not subjected to any direct main steam line acoustic loading. However, continued growth by fatigue cannot be ruled out. Nevertheless, all of these indications appear to have stopped without propagating into the vertical weld; this is indicative of IGSCC behavior as opposed to fatigue, since weld material is more resistant to IGSCC. The flanges have expierienced a near infinite number of fluctuating load cycles and if fatigue driven, more significant cracking is likely to have occurred after many years of operation. IGSCC in steam dryers has been typically limited in depth and length since in many cases it is caused by cold work or weld induced residual stress.

The dyer unit end plate, with the indication, are securely attached and captured within the structure of the steam dryer bank assembly. The vertical edges of these end plates are attached to the dryer assembly with 3/16" fillet welds, each weld approximately 48" long.

There were no relevant indications reported in these vertical welds. The geometric

configuration of the unit end plates is such that the steam dryer assembly mechanically captures theupper and lower edges. The reported horizontal indications were seen in the inlet side end plate flange. The vanes preyent inspection of the central end plate surface, but inspection of the outlet side end plate flanges at both locations found no indications.

If it is postulated that the end plate horizontal indications propagate across the entire 8.75" unit end plate width including both the inlet and outlet side flange, such full width, through-thickness cracks would have no structural impact. Nor is there any concern for loose parts. The separated end plate sections are still attached and will continue to function.

Safety The steam dryer assembly has no safety function. See BWRVIP-06A for additional discussion of steam dryer assembly safety. The flaw indications reported in the steam dryer INR's from RF026 will not likely result in any lost parts at operating conditions.

Therefore, there is no safety concern with continued operation with the Reference 1-10 indications left as is.

Conclusions and Recommendations The dryer unit end plates flaw assessment is based on the following factors: (1) it is a highly redundant structure and there is no structural consequence of the cracking and (2) postulated significant flaw extension leading to the flaw reaching the full section of the channel geometry would not create the opportunity for loose parts. Field experience supports this as-is operation decision in the context that the indications will be re-inspected at the next outage. It is recommended that the ,new visual indication given in Reference 2 be accepted as is. Repair is not recommended.

References

1. GE INR-IVVI-VYR26-07-09 Rev. I

2. GE INR-IVVI-VYR26-07-10 Rev. 1

3. GE INR-IVVI-VYR26-07-11

4. GE INR-IVVI-VYR26-07-12

5. GE INR-IVVI-VYR26-07-\13

6. GE INR-IVVI-VYR26-07-14

7. GE INR-IVVI-VYR26-07-15

8. GE INR-IVVI-VYR26-07-16

9. GE INR-IVVI-VYR26-07-18

10. GE INR-IVVI-VYR26-07-19

11. GENE-0000-0047-2767

Attachment Header 2

Document Name:

Document Location Subresponse Description Attach

Title:

[GE INR 10

INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report Plant / Unit Component Description Reference(s)

DVD DISK IVVI-VYR26-07-58 Title 4 Steam Dryer RFO-25 IVVI Report INF # 002.

Vermont Yankee Interior Vertical Weld RF026 Spring 2007 HB- V04

Background

Revision 1: Incorporates photos from RFO-25 and correctis the sketch.

During the Vermont Yankee 2007 refueling outage, in accordance with the.Vermont Ya nkee VT-VMY-204V1 0 Rev 2 Procedure, the Steam Dryer was inspected. The dryer inspection included inspection of the Steam Dryer interior welds and components. These inspections were done with GE's Fire Fly ROV with Color camera. During the inspection :of the HB-V04 weld (Dryer UnitEnd Panel-to HBwPL3 Plate weld), relevant linear.indications were observed in the heat affected zone on the Dryer :Unit. side of the weld. Most of these linearindicatioris. were previously seen in. RFO-25, Reference INF # 002. When comparing this outage with last outage, 0nejnew relevant indication is seen ( 3 rd indication) of similar appearance, orientation and size as those previously seen; one indication was, not seen (RF025: 8 th indication). No discernible change was noted for those indications which correlates to those of RF026.

See attached 2007 photos and sketches.

BWR-aJ4 00003000001 00*.l~1o)

(L~o~d..boo..100 0

2700 YanaW&4 MAW 01 00 0 f o .0 00 O 1 W0 0 0 00 000

• Sketch on the left shows the weld map rollout The sketch .on the right showsi a bottom view of the dryer.

Preparied by: Dick Hooper Da Date:, 05/31/07 -Reviewed by: Rodney Drazich Date:. 05/31/07 Utility Review Mi oSe Date: 05/31/07

,NR,-iVVWF*26-o7. 0 Int HB-VO4

• e*v'Stearrrya Page 1 of 14

GE Nuclear Eoetqy INR-IVVI-VYR26-07-10-Rev I Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo shows the interior of the dryer and the location of HB-V04 vertical weld.

This 2007 photo shows the top of the vane bank (on the left) and the end panel (on the right) and the vertical weld in the center INR-IVVI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 2 of 14

GE.Noclear E&;eqjy INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo is of the 1 s' indication from top down (Correlates to RF025: 1st indication).

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 3 of 14

AIi~

GE Nuclear Enerqay INR-IVVI-VYR26-07-10-Rev I Steam Dryer Interior HB-V04 Indication Notification Report This 2007photo is a close-up of the ls indication (Correlates to RF025: 1 st indication).

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 4 of 14

E. ,"uc'erDEnergy INR-IWI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo is the 2 nd indication (Correlates to RF025: 2d indication).

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 5 of 14

GE Noulear Er*-e,,gy INR-IVWI-VYR26-07-10-Rev I Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 3 rd indication and is a new RF026 indication.

INR-IWI-VYR26-07-10 Rev I Steam Dryer Int HB-V04.doc Page 6 of 14

GE NuclearEnerqy INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 4th indication (Correlates to RF025: 3 rd indication)

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 7 of 14

GE: Nocleat INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 5 th indication (Correlates to RF025: 4th indication).

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 8 of 14

_________ (E Nuc',ew Lutermy INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 6 1h indication (Correlates to RF025: 5th indication).

INR-IWI-VYR26-07-10 Rev I Steam Dryer Int HB-V04.doc Page 9 of 14

GE Nuclear Energy INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 7Zh indication (Correlates to RF025: 6th indication).

INR-IVVI-YR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 10 of 14

GE NucleaIr Derlgy INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 8 th indication (Correlates to RF025: 7th indication).

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 11 of 14

GE NuearEnergy INR-IVVI-VYR26-07-10-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report RFO 25 th 8

Indication RFO 25 9 th Indication These 2007 photos show a linear indication and with a change of lighting there is no indication. This indication is considered non-relevant. (Correlates to RF025: 9th indication).

INR-IVVI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 12 of 14

GE Ndeia-r E ry INR-IVVI-VYR26-07-1 0-Rev 1 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 9 th indication (Correlates to RF025: 10th indication).

INR-IWI.VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 13 of 14

GE Nuclear L.:f*el&?y INR-IVVI-VYR26-07-1 0-Rev I Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the bottom weld area and crud line.

INR-IWI-VYR26-07-10 Rev 1 Steam Dryer Int HB-V04.doc Page 14 of 14

NEC =-JH¶!9 Life Prediction and Monitoring of elý Nuclear Power Plant Components, bc Fredric A. Simonen for Service-Related Degradation gC re, Stephen R. Gosselin This paper describes industrv programs to 111anage soretiotrai degradationand to junatfy A:

e-nail: sip*hepacsseirl@v>ý QGv comttinttd opieration of nuilear conimpnttis wtthe une.pected degrodolioo /tos been en- t cotuttered due to design materials antd/ot operational prohlems. Other issues hitoe been Pacific Northwes4 National Laboralory:' lot related to operatint if comnponents beyond their originaldesign life int cases where there

,ichland, WAf9352 ite iS1no evidence of fitigue crack initiation or other forims of struct'oal deitodetjit., Data in from plant operating e.+terience have been apllied in combinhiontn lith itnserw'ice Inspec- tht tions and degradation mtnagenienr programs to ensure that the degradation nechanisms pr d1 not advein-el/ impact plant ste,t. Prohatilisticfirctitre mechanics calcudt ionsv tre Col presetted to demonstrate how tomponlent failure probabilitiescan be tianaged thirough pla atsugmented inservice inspection programs. [DO: 10. 1 I11 -1. 1344237.

19t era 1g. (Al

'is-i der Introduction ticipated during design, and have resulted in actual structural fail-have a ed that ures and early replacements and repairs to components. .. (Al f Evaluations of nuclear power plant safer y have assumed5 that This paper describes efforts in the nuclear industry to justify

• .passive components such as pressure vessel.s fand piping systems continued operation. with parlicuhar alttenttion to componentts that Set

,i have very low failure probabilities, such t (X

')at failres of these have exhibited degradation or which may exceed original limits conmponents make only negligible contributii tus to plant risk (e.g.. based on predicted design lives. Two technical bases for cotttin-core damage frequency), In the U.S. and ot her countries the de- nied operation are presented. The first approach makes use of sign, fabrication. inspection. and maiintenanc C of piping and yes- knowledge gained from plant operating experience to identify aid -4 have followed the conservative enghnec sel+;;,+s Sim, ring practices spcci- mrtanage degradation mnechanismss. These mechanisms,nay not 55 bed by the American Society of Mechanica I Engineers. ASMEt have been anticipated during the design of the phlnt, but given rant

'i Boiler and Pressure'Vessel Codes. The relati' vely small nutnber of iheir actual occurrence have the potential to cause failuies by iignificant failures that have occurred during operating experience stnall leaks, large leaks, or ruptures. The second approach ad- fore demonstrated the soundtnss of the As? elE code procedures. dresses failure mnechanistis, such as fatigue. due to anticipated tive vever, many plants will he aipproaching th cirfdesign lives (e.g.. plant operating transients. which design calculations show the po-55 flit"

,0 Vy.r), with the expectatio*t that continuled o peration beyond the tential for occurrence, but for which plant operating experience

'5 original desien period will need to be just ified: Therefore, the has not yet shown any evidence of actual occurrence. Probabilistic ure

'-'!assumption of continued high levels of struIctural reliability re- fracture mechanics calculations demonstrate that an augmented desi qutres an extrapolation beyond the current baIse of operatitg ex- '4 (i.e.

level of inservice inspection can ensure acceptahle fainture prob-limi pertience. that. must be addressed as part of plant life extension abilities for fatigue critical components. 425

.met) efforts.

- Whereas the replacement of active corn ponents (mechanical Ser Management Programs for Service-Related Degrada-sn'l elyctrical) is a routine part of plant mainnteuauce, ae-ae replacements of vessel and piping compone tits is not econoi- tion 5-45

'4- 5 St c.all feasible. The.challenge is to make reali stic life predictions, Studies by Bush [ 1,2]. Janali [3]. Thomas 14J. and Wright et al. tital

,amn to estabhlsh a hieh level of confidence in these predictions. A [5] have shtown that piping failures are generally due to opera- Failt

'desired objective is to ensure that passive con iponcnls continuecto tional conditions, materials selection, and design features that tion make only negligible contributions to plant .risk relative to less -W were not adequately addressed or perhaps not addressed at all in easily t anaged contributions to risk such aus failures of active the design of plant systems. On the other hand, those tmechanisits cOmponientS and operator errors. such as mechanical fatigue due to anticipated operational tran-

• -Fatigue damage was originally identified as t[te life-limiting sients. which have been considered as part of the plant design.

(1eoradation mechanism for tnany pressure ves sel and piping cort- have been addressed in a very effective manner and ar' seldom (if

,oancnts during the designofniuclear power p lants. With an aging ever) fie cauIsC of service related failures.

ypopulation of operating phans, certain strut tural locations may Given the large number of potential service-related degradation

• eceed their originial design lives based oni calculated values of mechanismns. the, tuclear insdustry has adopted monitoring and

~r.

,0tigue usage lactors, although tlhere has been no evidence of deg- mattaging practices, rather than life prediction and retirement

,ladltion as the predicted fatigue lives have been approached or practices, to ensure safe and reliable systems. The strategy in-exceeded, On the-.other hand, various degra dation mechanisms, volves the following steps:

uch:i:as. thermal fatigue, environmentally ass isted fatigue, stress - a reporting system to ensure that the industry can respond to CorrosiOn cracking. and flow-accelerated cr osion. were not an- adverse operating experience (detecting of cracking or leakage)

-t . .t before unanticipated degradation mechanisms impact a large nuns- 555

':!Paetit" Notnhvst National Laboratory is operated for r[ie U.S. Department of ber of plants and/or result in safety significant. structural faitlures:

Frtergv by Rattelle Mcreoria) Institate utiter Contract DE- ACo6-76RIAt) 1830, augmented iiservice inspectiots that are targeted. to specilic

• -c ttributedt i by tUsePressure Vessels antdPipint Divisi "Al- o", PprsSURE VESSEL. I'tCHNOLOty. M*nusc ripi received* by rit frpicaived by the he PVP systems. materials, and/or operating conditions to ensure detection:

ion.nJanuvary 20t)! re.ised masttucript rceirivcd Ocib cr23, 2000. Editor: S. Y, of early stages (small cracks or minimal wall thinning) of degra-I.,,'

dation mechanisms: '1t-', Fig, 1 58 : Vol 123 FEBRUARY 2001 Transactions. of the ASME Jour.

I' 51.?

iv

L

• changes to plant operating conditions (e.g.. improved water OTH chemistries) to decease degradation rates to negligible levels: UNR SC TF

- replacement of inadequate piping and vessel components E4%

WH 8%

with improved materials and/or design practices. 9% I*.d E-C Some industry programs have been elTectivc in responding to 0%*For DDL 0% - ,

both anticipated and unanticipated degradation mechanisms. On- FAC going efforts by the nuclear power industry to address service- 13%

related problems are described in the fortltcomoing.

D&C 16%j ASME Setction XT Inservicie Inspection COR Formal integrity management programs were first established 4%

for nuclear power plants in the early 1970s. Until that tinet, lim-

?

ited attention was given to the .needs of inservice inspections (ISI)

I in early nuclear power plant designs. It was generally believed that system radioactivity would render periodic inspections im-practical. Since the nuclear plant systems were being designed arid constructed to higher quality standards than those applied to fossil plants, ISI was assumed to be unnecessary. However, by the late 1960s. the number of service induced delifcts requiring the repair of' nuclear system components increased. This prompted a coop- VF 45%

erative effort between the U.S. Atomic Energy Cotmmission (AEC) and industry to develop inspection program standards un- Fig. 2 Service failures in small-bore piping (<2 in. NPS) der the oversight of the American National Standards Institute (ANSI) and the American Society of Mechanical Engineers (ASME). By 1970, the ASME Boiler and Pressure Vessel Code, f crated corrosion, thermal stratification, etc.) not anticipated in the t Section X1 :1'Inservice Inspection tof Nuclear Reactor Coolant Sys- original design. Depending on the degradation mechanism teins' was published.

present, failures are not necessarily limited to weld locations.

Over 50 percent of the inspection categories pertained to welds.

The Swedish Nuclear Power lnspectorate (SKI) compiled a da-f The inspection locations were primarily selected based on factors tabase on reported piping failure events (leaks. breaks, and rup-such as: component design stresses, estiitated fatigue usage, dis-tures) in U.S. commercial nuclear power plants [8]. This database similar metal welds, and irradiation effects.

Originally, service--induced flaws were assumed to occur from includes a total of 151 I piping and piping ctnponent failures on random causes, at random locations, and at random times. There- various safety and balance-.of-plant (BOP) systetns that have been reported to U.S. regulatory bodies frtom December 1961 through fore, the Section XI inspection program relied upon a representta-October 1995, encomnpassing 2068 reactor operating years. Figure tive sampling of weld locations and randomized the timing of I shows the distribution of all piping failures according to tf inspections as much as possible. The examination procedures and flaw acceptance standards assumed that the principle cuise of fail- following causes:

tire would be due to fatigue stress cycles created by anticipated

• corrosion tatigue-CF design cyclic loads (i.e., thermal fatigue). For Class 3 systems

• thermal fatigue--'F-(i.e., service water systems)Section XI program requirements are sstress corrosion cracking---SCC limited to periodic leak and hydrostatic pressure testing-no volu-

• corrosion attackICOR

• metric or surface examinations are required. erosion and cavitation-E-C flow-accelerated corrosion (i.e.. erosion corrosion)--...E/C

. Service Experience Insights

• high-cycle vibration fatitue-..-.VF Service experience [6,7] has shown no correlation between ac-

• water hanumer--WH I

F" tual failure probability anid design stresses in the Design Report.

Failures (cracks, leaks, and breaks) typically result from degrada-tion mechanisms and loading conditions (i.e.. IGSCC. flow accel-OTH 2%

UNR 15%

OTH CF TF

'.1 4% WH 1% 3% SCC f

m-$ E/C 14%

DDL TF

• n 23% 1% /_5%

E-C 1% E.G COR D&C 10% 2%

6%

it

'D&C e 16%

VF COR n 29% 7%

Fig. 1 Piping failure'events in U.S. nuclear plants (1§61-1996) Fig. 3 Service failures'in large-bore piping (>2 in. NPS)

L:* Journal of Pressure Vessel Technology FEBRUARY 2001, Vol. 123 1 59

hamtnet, overpressure. and frozen pipes, In these cases 30- RW-PWRS inspection programs may be ineffective in preventing traditional or reducing O0ALLVENOORS tie piping ta iluii probability. J Ficures 2. and 3 compare service failuores in small bore (<2 in.

NI'SI and larger bore (>2 in. NPS) piping.

qumitcrs of tie reported service failures Approximately three-in small-bore piping were caused by either hihv..cycle vibration fatigue (VF). flow-accelerated corrosion (FA). or design and construction errors 20 (D&C). Almost half (45 percent) of the small-bore pipe failures were due to vibration fatigue. The majority of these failures oc-curred at socket-welded connections in poorly supported or canti-levered vent and drain lines <I in. NPS.

Over 50 percent of the reiported large AUXC CS bore piping service fail-FPS FWC RAS RCS SIR ures were caused by stress corrosion cracking fSCC). VF, andl System Group FAC. SCC and FAC accounted for 42 percent, and VF accounted for 12 percent of the reported failures.

Fig. 4 Service failures by system Sixteen percent of the groups small-bore failures were caused by D&C compared to 10 percent for large-bore piping. This appears to reflect field welding and fabrication difficuilties associated with smaller-diameter Figure piping.

. design and construction 4 shows the ntumber of" service failures reported crrors--D&C eral plant systetm groups. Each system group in sev-

- other-. -OTH is described in Table I. System group service experience for Combustion PWRs, for Westinghouse PWRs. and for Enigineering The data of Fig. I shows that only 3 percent of all the reported ALL plants is shrewn.

service-induce'd piping failures were Over half of the reported service failures in Combustion Engineer-This suggests that itt their present firmcaused by thermal fatigue. ing and Westinghouse PWRs occurred the ASME Section Xt ISI tetns itt reactor auxiliary sys-

.program requirements are relatively (ColTmponent cooling water, chemical ineffectual with regard to re- V/lunite and control.

ducing overall piping failure probabilities. spent fuel pool cent of all reported failures were due Approximately 72 per- .terns (service cooling, radwaste. etc.) and auxiliary cooling sys-to degradation mechanisms" water, salt water cooling, main circulating

• not addressed by ASME Section etc.). water, X1. For approximately 25 percent of all the reported events, piping Fig failure resulted from -faiture rfmechanisms that were not associated Augmented Inspection Programrks reqkmil with a particular damage mechanism. These include. pipe which failures caused by transient load- For some of the more significant causes

• ing conditions and other factors such of piping failiures, tug- cantdy as consttrction errors, water mented iispection programs have been implemented. These pro-grams., maiy of which have been mandated Fin by the NRC. are de-signed to address component integrity (FAC relative to the impacts Table 1 Service failure data associated with a specific damage mechanism, sion a system grouping FAC Intergrassular Stress Corrosion Cracking.

GROUP SYSTEM GROUP cracking (SCC) refers to cracking caused Stress-corrosion contet REPRESENTATIVE by tile simultaneous DESIGNATOR DESCRIPTION piping SYSTEM NAMES presence of tensile stress and a corrosive mnedium.

variables, affecting SCC are temperature, The important ioic sti RCS Reactor Coolant System water composiition, stress, arid metal inicrostnicture. chemistry, metal Pressurizer, Reactor Ati Coolant System Both intergranular grain SIR (cracking proceeds alotg the material grain Safety Injection and High and Low Pressure boundary) and trans-granular (crack growth is not affected by the presence boundaries) cracking have been observed. Intergranular of grain Recirculation System Safety Injection, Residual Heat Removal, Shut Down rosion cracking (IGSCC) results from a coitbination stress cor-of sensitized Cooling, Accumulator or materials (caused by a depletion of chromium in regions adjacent other passive injection to the grain boundaries in weld heat-effected zones), high systems (residual welding stresses), and a corrosive environmeqt stress CS Containment Spray System level of oxygen or other contaminants,). (high Containment Spray System IGSCC is encountered most frequently in austenitic RAS Reactor Auxiliary Systems steels that become sensitized through the welding stainless Component Cooling Water, process and are subjected to BWR operating environments.

The extend into the baise material a few millimeters susceptible areas Chemical Volume and Control, Spent Fuel Pool heyond either side of the weld--the weld "heat-affected zone."?

Cooling, Radwaste (no salt Welds in materials considered to be resistant to sensitization or dirty water systems) fromn welding are not AUXC susceptible to degradation from Auxiliary Cooling Systems Service Water; Salt Water IGSCC.

A discussion of the IGSCC problems in BWR Cooting, Main Circulating and the associated augmented program requirementsnuclear plants Water, and other dirty water in Generic Letter 88-01 [9] and intNUREG can be found 0313 [10]. The indus-systems try was required to establish programs that FWC Feedwater and Condensate included the following:

Main Feedwater System,

- ISystems

• implement piping replacements or other measures Auxiliary Feedwater to mitigate 1GSCC:

System, Condensate

• augment the existing Section XI IS]

System program to incorporate ST an inspection scope and frequency consistent Main and Auxiliary Steam with the extent Main and Auxiliary Steam

' of mitigation actions irmplementedt Systems Systems

• improve leak detection arid monitoring

- Fire Protection Systems programs;

. Fire Protection System implement programs to improve NDE inspector performance in the detection and characterization of IGSCC damage.

60 I Vol. 123, FEBRUARY 2001 Transactions of the ASME Journ g1l11111111

1,20 e, 1.00 NRCBulletin 88-01 and____

NLRW -0313 Rtev 2 0.80 bicdustry IryWiertents recirc ppk"g augmrented irmpectlons and kxsplctior 305M pertorrnlnce 0.60 demnvrstration - -

040 V) 0.20 0.00 60 62 64 66 68 70 72 74 76 78 80 82 84 86 88 90 92 94 Fig. 5 BWR SCC failures per plant year

.Figurethat since the implementation of these program 5 shows rected at single-phase systetms.tInitial inspections were completed reqtiretitents, the frequency Of IGSCC caused piping failures, on all single-phase systems by 1989. Erosion-corrosion programs

=:hich might otherwise have increased, has instead been signifi- were in place on both single and two-phase by 1990 [I 1]. Since cantlv reduced, that time, service experience (Fig. 6) suggests that the'number of failures due to erosion-corrosion has been reduced.

Flow-Accelerated Corrosion. Flow-accelerated corrosion EPRI report NSAC/202L [ 12] provides general guidelines for (FAC) is a complex phenomenon that exhibits attributes of ero- the identilication and inspection of components subject to FAC sion and corrosion in combination. Factors that influence whether degradation, FAC is an issue are velocity, dissolved oxygen. pH. moisture content of steam, and material chiromitum content. Carbon steel Corrosion Attack in Service Water Systems. - Uniformn cor-piping with chromium content greater than I percent and austen- rosion attack in service water piping, microbiologically induced itic steel piping is not susceptible to degradation front FAC. corrosion (MIC). crevice corrosion, and pitting were typical At the end of 1996, industry initiated efforts to develop a pro- causes of failure events of pipe components grouped itt this cat-grran to address erosion-corrosion. These initial efforts were di- egory. Of these, MIC is the predominant corrosion mcrhantismn itt 0.

0i.

I.L.

70 72 74 76 78 80 82 ,84 86 88 90 92 94 Fig. 6 Erosion-corrosion failures per plant year 3' Journal of Pressure Vessel Technology FEBRUARY 2001, Vol. 123 /-61

.1!ese systems. In MIC. nuicrobes, primarily bacteria, cause wIdC- as a result of' a problem resolution. f3etwecen 1976 ,ind 19'82, di sprc adodalaige to low-alloy and carbon steels. Similar damage has signilicani a moint if vilbration fatigue related failures (Fig.

also been found at welds and heat-affected z ones for austen itic fostered increased attention to this problem by code and rea uh siinlessa seels: fpipmg Pi niopfnlnits c( With fluids containing organic ti,ry bodies. The NRC incorporated requirernelits to perforni v IQ

, erial or with organic material deposits are o'iost susceptible to bratoin testing ;a part of' nuclear power plant initial testing pro The most vulnerable components are raw water systems. grarns [ 161, and by 1982 the ASME published an operating an7)

-rage tanks, and transport systems. Systems with low to inter- maintenance standard [19] which specified requirenients [or pre Ilittenlt flow conditions. lemperatures between 20 1201F and pft operational and initial start-up vibralion testing in nuclear powC be.low 10. are primary candidates. plants,  :.

fin responsc to NRC Generic' Letter 89-13, industry was in-Risk-Based Inaservice Inspection. ,.Service experience and Ill st,'ucted to implement a comprehensive program to address corro-ison in service water systems. Prior to this. the service water in- atugmentCd i[nspectiori programs have demonstrated a need oin Sec oionXI's part to move in new directions and shift its emphasi s tegrity programs relied on the Section XI periodic leak antd away from simple inservice "inspection" rules to establishinl h drostatic pressure test requirements. Under the Section XI pro-effective integrity management programns for nuclear plantsg grarn, the service water system integrity management approach Ideally, these new programs should include the followin was 'reactive" in nature: that is. corrective action was taken axhen damage was sufficient to result in visible leakaee. The Ge- characteristics:

ncheric "proactive'

'limnrc Letter 89-13 approach augmentedto programs require the problem. For plants to take example, I Future manya ,failure progransand iechanisis need to be focus based on attention on an the understanding of locations in the programs implemented inmproved chemistry control to mitigate the plant system most likely to be affected by these mechanisms. This eotablishment of MIC sites, volumetric inspections (UT/RT ex will allow plants Ct identify problemns in a proactive manner, so

• aininations), and component condition monitoring arid trending,. that corrective actions can be planned and implemented before EPRI reports TR-103403 [131, NP-5580 [14], and NP-6815 failures occur.

5[]iprovide additional information regarding MIC degradation. 2"Monitoring and inspection methods need to be designed spe-High-Cycle.Mechanical V ibration Fatigue. More and more cifically for the degradation mechanism of concern. This has been

'atttention has recently been paid by operating plants to prevent referred to as "'insfieion-for-cause.'.

tunexpected piping faimlures hile to high.cyre vibration fatigue. 3 The integrity management program should be designed to otf i nset:'

Sroall-bore pipe (< I in). NPS) socket-welded vent and drain con- ensure reliable component operation..For example, inspection fre-quencies may need Cobeadjusted to ensure that the failure prob- cal cotil n.ctions in the immediate proximity of vibration sources tend(o bemost susceptible to this failure tnechanisin [ 16-I1i. Unlike the ability of the component is maintained at ant acceptable level. vond us; flaw pro previously discussed mechanisins, vibration fatigue does not lend ASME Section Xl hopes to accoiplish these objectives movimig itsel f to periodic inservice exam inations (i.e.. volumetric, sur. ace, in the direction ofsrisk-urarn.ed inservice inspection (RIISI).

cation o etc . ýas a means iilmanagineig this degaato mhaii.Te dgradation mechanism. Aafrstep 125.1. Sui Tie As a firstep. ASME Section XI nture oflthis rnechlnism is such that- generally, almost the entire code cases that allow for the use ofhas recently developed pilot alterative RIISI rules for flaw det faleitiue life of the component is expended during the initiation by adop piping. These code cases grew out of work sponsored by ASME (i.e.. pFic V. Once a crack initiates, failure iluickly follows. Therefore. research j201 and EPRI 01J. The three code cases implementing tinued o

,.bsence of any detectable crack may not assure reliable coin- this technology have been incorporated into ASME Section Xl to be at poincnt performance. In addition, for many of these components, Code Cases N-560, N-577, and N-578. These initial efforts fo-These in ithe plant conditions when vibration levels are unacceptable may cused primarily on the identification of inspection locations and at levels "be very difficult to predict and limited to shoil time periods of the implementation of appropriate inspection methods. Industry usage fa tillique plant/system configurations. This would explain why we pilot applications [22 ,23] have been completed for each code case.

cobntinuLe to observe cases where vibration fatigue failures occur Each application has been reviewed and approved by the NRC for Probe 1Aitein the plant's operating life [8]. Therefore, the fact that a consistencyv with NRC guidelines [24]. less stee sibration failure has not occurred within the first few vears of loaded a pl:nt operation may not preclude future failures. Probahilistic-Based Inspection Strafegies operatiom Fimure 7 shows the number of pipe failure events per reactor Thus Carisucc ess e in itia Strategies correspo p1imt-year reported to NRC as being caused by high-cycle vibra- 'his far success of the initial RI1SI studies has been measured alhernatim lnon fatigue. Prior to 1976 piping vibration fatigue was addressed in terms of estimated reductions in nuclear power induistry and The p regulatory buroen., aiiticipated noan-rem exposure reductions and with asp calculated improvements innreactor safety. These improvements in *; .griowilt safety have assumed that the selected inspection locations are ex- o9.14F.

5500'-'---.

arnited using reliable NDE methods at appropriate frequencies in was aggs' order to achieve a reduction in failure probabilities. In the long assunmed run, ultimate success will be seen in a reduction in the occurrence 0(005-0 of piping leaks in these systems. Therefore, future inspection The ai

05. strategies will need to manage component failure frequencies. iif no ino 10500 . lin this section we show how a probabilistic approach call be lion prof applied to determine inspection frequencies that account for dem.i- ability fc onstrated NDE performance and ensure reliable piping perfor- type cui tiance is maintained throughout the component's original or ex- detection tended operating life. In the example described in the forth- deionst.

coniing, we assume that the weld location is subject to thermal threshol,:

fatigue. The inspection frequency necessary to maintain the cont-P03100 ...... .. (a* = 0.

ponent's failure probability at or below that associated with the POT) fot fatigue limit specified in the original construction ASME Section provided Ill design code (e.g., cumulative usage factor (CUF) must be less greater than unity) is then determined. lively, ni Probabilistic Approach. Probabilistic fracture mechanics probabili Fig. 7 Vibration fatigue failures per plant year calculations are presented to demonstrate that an augmented level ,Figure 62 I Vol. 123, FEBRUARY 2001 Transactions of the ASME I Journal

the

.7) ilia-vt-pro-and IS SI@4 Y'..

pre- Baseline Case 2' = 0.2555h

" NsNo Additional ISI

,Wer 3.E-02 a"

• D11 l5 1, the a.

ee- ._ 2.E-02 asis ling

-- a*IS]

0 25Ync lilt ,

E a"=0.125 I-1.E-02 II10 4 Y, of 1-J0.125 1-~h the Fhis OE00 lb0

. so 5 10 Is 20 25 3D 35 40 45 t*ore Time, Years

• ;pe- Fig. 8 Calculated probability of leak before and after implementation of inspection program een I to lre- of inservice inspection can ensure that failure lates of fatigue criti-" (through-wall crack.) as a futnction of the operatinrg irme (0 it) 40

-ob- cal conponcnts sirho o(. not increase as operation is cohtin Ued be- yrl. At 20 yr (when the calculataed CUF becomes 1.0). tile cumu-vel. yond usage factors permitted by the design code. Uncertainties in lative leak probability is about I.0E-02, or one chance in 100 that

,ing flaw growth rates aInd iin taw detection were addressed by appli- thie weld would fail. If rio inspections are perforimted, the cuntula-cation of the probabilistic fracture nmechanics code pc-PRAIS tive failure probability curve continues to rise and wiith as increas-(25]. Suitable inspection frequencies were establishied for a give ing failure rate, All (if the alternative irnspection scenarios (cort-ilot fHaw detection capability iprobability of detection or POD curve binations of POD and inspection frequerincy) reduce the calculated for by adopting a goal for art acceptable piping failure ptobabilitl failure probabilities. but some scenarios reduce the failure prob.

• ME (i.e.. probability of through-wall crack per weld per yearl. Coni- ability much snore than others. The most effective inspection---,,

ing tinued ope~ratios for calculated CUFs exceeding unity was lakess (a* = 0. 125 in.) reduIces rite failure rate by about an order of rat__"

• XI to be acceptable onily itf additional inspectionst are performed. tritude compared to tire alternative ofi no inspection. In this case fo- These inspections are required to maintain calculated failure rates tire failure rates during the second 20 yr of operation are actually and at levels less than for equal to) calculated failure rates befbre the substantially lower than the corresponding rates during tile irst 2f1 3try usage factors becatne unity. yr of operation. Sorte of tire other less rigorous inspections of Fig.

ise, 8 are also suIfficiently effective to mairtain the calculated failure for Probabilistic Calculations. The example considers a stain-rates at or below tire rate that exists at the stime(20 yr) when the less steel pipe (29-in, outside diameter by 2.5-in. wall) wihich is CIJ'IFattains the limiting value o1 unity. For exaarnple. ain Appendix loaded at 5000 cycles per year to give a CUF= 1.0 after 20 yr of operation 6iven a weld root stress concentration factor of 3.0. This L inspection with a 4-yr frequency and a* = f. 125 ill. would meet corresponds to a nominal alternating stress of 27.3 ksi and a peak the probabilistie criteria as well as tire alternative of a 2-yr fre-red quency sith s * = 0.25 itt. Therefore, in this extreme case where alternating stress. at the weld root, of 81.9 ksi.

and The pc-PRAISE model assusned seisi-elliptical surface flaws thermal fatigue loading is significantly high, a 2 4-yr inspection

-ind with aspect ratios of 12 and 20, and a Paris law for fatigue crack freCtleicy will maintain file coripotteni's reltabiliti al designt ba.tsis s in levels.

growth having a Mean rate corresponding to constants of C ex-

=-9. I-4E- 12 and nr -4. A simplified treatment of flaw initiation was assumed, At tiise=0.0, very small ttner surface cracks were assurmed to be present, with depthsr uniformly distrihuted between Conclusions rice ion 0,0105. 0.0)10 in. The nuclear power industry has successfully implemtented pro-The alternative inspection frequencies were lisited to the case grans to manage degradation of pressure botndatry cornponentis.

oftno inspections and inspections every 2 or 4 yr. with the irspec- These programs have focused in utcxpected degradation rnecha-he lion program being introduced after 20 yr of operation. The reli-

,ral-nissnls that have impacted plant operations well before trie end of ability fo)r the ultrasonic NDE was described by the error function- tire expected plant design life. Programs have also breen iriple-or- type curves used by the pc-PRAISE code to describe flaw rIented to address potential mechanisms suich as fatigue cracking detection. Two bounding curves were assumed for purposes of the that were identified as life linriting as pan of tile plant design

.'Ih-demonstration calculations. The less effective NDE assumed a basis. Moinitoring of components in accordance with plant inser-threshold detection capability (50 percent POD) for a 0.10-t flaw vice inspections programs can ensure that tite reliability of piping

((* =0.25 in.), whereas tile more effective NDIE had a 50-percent systetms is maintained throughout the remainingr design life, and

.,the POD for a 0.05-t flaw {0,.125-in.). hi each case, the POD curve atldress issues related to plant life extension beyond the original

.ion 40 yr of the original design. r provided significantly better detection capabilities for flaws of ess greater depths, such that flaw depths .0.25 and 0.50 in., respee- Inspections at appropriate frequencies with reliable NDE stetlh-Lively. or about twice the threshold size, could be detected with a ods can manage the potential degradation mechanists, :'111 probability of belter than 90 percent. thereby justify continued operation even when calculated desigtr

• vel Figure 8 shows the predicted cumulative probability of leak limits may be exceeded. It is even possible with asi aggressive VIE Journal of Pressure Vessel Technology FEBRUARY 2001, Vol. 123 / 63

Itinspctiont pi rogratin to decrease fail ire freiltie ncies dlJ iJ11 thC

• eI" Mssr I

" Po-,r l,'a I.i.NUJREG 1344, Division ot Eti'ci iimgatd Sv!ecttim peniods of plant life to the same levcels that exisled rcla*tively carly +1t:rttolsgv.. !..SNR{-'. Washington. DC

[ ... iii life. 2I 1 FTRI. 1993,5. Ri.s...tr.t.,latia,ts 6i,r (i..:'/f',t - I!' / m s-A( d ,' i NSAC.21}II... Eectric PFaser Resttrch hsmitts Id, Aili,. C.A.

1:Byapplying probabilistic methods, tutule iltspc)Ci t st AlelgICs It,,cktiu.s, P. R.. 09 3). i-rvi'e r ,Sctret (ss,ttrsetr rtt;d Lt,'s, ti,,,

,-'~. cannot only be consistein with the s.rvice conditions and the dtcm- S! . (PRI TR-103403, Electric Power Rest',:lrch lthi,ti rue,i 1h Alit, fl'csb,,A onst rated peiformane levels of the Nf)F. methods, but will etisirre that the reliability of the piping is maintained over perioris of .l41 i'tiroi. G . L . 198.S. ,Siin'r/i oo .ir M...../tr hTsA';/n/!uft /.hirtlrt , ( 'ttoson mi N-.,sct' tv,'-r Planst NP-5580, Elecric Powei Research Ilstitute. Palo Alto, Ci:t" jontted operalion. Inspection stratleiclsC designed in this lash- (,A.

ion, xill he a powerful addition to current risk-based ISI I IL5.itina. G,. 1.. I1990. D eection W Cr trt l o!Moc'r icologiciilly I.f'e-',ed models. "-,t ,t,*m -An I- i'.enrr*itn "rite So r elrct, k fiur ,ti;,cr init gitsi/t rl .d It!!ts

'1,.r..sion, NP-6815. Electric Powe r Research Institute, Palt Alto, CA.

I 6j i)li 0.

) H., 1485, "Piping Vibration Experier nc Power i Piann,t " i't is.:rr References V, .sm!(I art d/Piprig TT'rh h.*gy --A D ec aid,of Pro gerss, Pressure Vessel lnd tlusi, S. tl.. 198_ "Sta istic,- oI Pressune Vessel and Pipsng Failures."-

Hi Piping Division, ASME. NY, pp. 689-705.

A.,IF J. Piesstue Vessel Techinol., 114, pit. 389-1959 [I7] EPR1. 1994, EPRI Fartiguei*fanaigteentr liiirirok. I.PRI TR-1104 53-4. Ft:eu it 121 lusth. S. I., 1992. "Failure Mechanisms in Nuclear Power Plant Piping Sys Power Re.5 ,tch Ilstitult, Pailo Alto. CA.

t:.i.s.' AS;MII J. Pressure Vessel Technol.. JIt, pp. 225-233. 1181 Riccardella. P. C., Rosario, 1. A., and Gosselin, S. R., 1997, "Fraciure Me-131 Jamali. K.. 1992, Pipe Fjiluresv in U.S. N NCleaneiaj l'erP Phtnts.

?ir chanics Analysis of Socket Welds undier High I Cyle Viliratirial l.,tding,."

EPRI TR 100380. prepared by tlatibutrion NUS, Gaithersburg. Maryland. for ASMENI PVP-.Vol. 353, pp. 3-:34.

North.a hst Utilities Service Comp:ny and the Electric Power Research lnsti [ 19J ASME, 199 1..ASAE Cirde fri" Operration andls*tli,,eutaice sI1Nuiclea, P.s-er lute. Plaons. Part.3. Requiremnentr fir P'rpteratiional antiil lial Stort-Utp T'sri,,g 01 Thosnas. H. M.. 1981, "Pipe and Vessel Failure Probatbiltlt." Pelhrthli, Fn- of Nucleor Potter iont Pil'fing Sy.rles, Ametican Society of Mechanical gi,,eers,,. 2. pp. 83- 124. Engineers, New York. NY.

15] Wright. R. E.., Stevensot, J. A., and Zuroftl. W. F._ 19.54, Pip,. ,roci FeA- [210]ASME Resiachi t['askFurce on Risk-Baed Inspection Guidcelites. 1992, Risk-qiuer"cy k risaetforr JtaNuclear l-sier Pla-is, NIJRtSG/CR-4457, hd*o Na- Bt,.r,-d I*ia*p recri - iJeliti.o.' Vol,-iere 2.JA-vet'l'lln eur suf "(...

iD. P o '! Lic' fit lotte, tional ]Engineering L.aboratory, Idaho Falls. II). Reicrtor (LWR) Nuclear Pori, Piant Crntponentrs, 17RI'D-Vol. 2012, pub-

[6) Kulal. S., Riccardella. P.. and Fougerousse. R.. 1995, 11-"thii, fjlnss-rire lished by the American Society of Mechanical Fingincers Center foi Resercth hIsprctirion Requirernnts.esr Clas.i 1, Caregor, H-J1Presmer Retinin. WVelatr aindiTechnoilogy Development.

in Piping, ASME Section.Xl Task Group on IS1 Optiizu:ation. White Paper [21] F'1RI.1996. Risk-l forriimIet ,iiic-e In.specttr n Evaluation P rocedures. EPRI Report No. 92-01-01. TR-I16706. I l.:titric Poweir Researech Institute. Pak) Alto. CA.

][7EPRI, 19901,M*etl Fftigue in Operating Nar.heor Pooer- lantr.A Re,'ir-soi 1.22)Westinghouse Electric Coprpo}ration. 1997. Westinghsusie Otee.i (;,r,,q, Apli-t,':srensign Man ironioing Requir-enrt.i FcotFailure lxperisn'.ce. and Reier. retion i, Risk lnformed-Method- to Piping Trserice h,*rcpition - 7"opi'ts Re.

nendsaionsfiorASME Section XI Action, prepared by ASME Boiler and Pres- purtr Revision II WECAP 14572. Revision I, work pe forimed by We.iimghouSc sure Vessel Code., Section Xl Task Group on Fatigue in Operating Plants. tol Electric Ciorporation in collaboration with Northeast Utilitues and Viginia ,j Section Xi Winking Group on Operating Plant Criteria. Pi..er fIn the Westinghouse Owners Group..

181 Bush. S. H.. Do. IM.I.t Slavich. A. L. and Chockie. A. D., 1996, Piping [231 ,EPRI, 1997. Applir.attior sf EPRt Risk--Infortned bnsireice ilspection Guide-

l. ihtrres im thie Unieted Staites Ntucleatr Posier Plants: 1961...1995, SKI Reptrt1 linei to (..'I Phins, EPRI TR-107531. Volumes I and 2, Electric Power Re-search Institute. Paloi Alto. CA.,

[9] Miraglia. F,:J. Jr., 198,1, NRC PIositiouona, IGSCC in BWR Austenific Swttile.is [211 USNRC. 1997. Drafit Regulatoir Giuide DG1063- Atr Apt.... rss, ftr Plant-Steel Piptrg--Ge-.Cerri Letter 88.01. U.S. Nuclear. Regulatory Coltnlissiton. Speciric. Risk Inrformed Decistoinking:Inservice hlspecisii *1f Piping. U.S.

1t0' Ilazelota, W.. and Koo. W. HI.,1988, Terrni,:al Rep-tt t, Mteial.-Ii-ehcrroi Nuclear Regulaitory- Commissin,. Aug.

an'! 'Isi,.ee Gutiderliiie fssr CWR Clt~tirrt Pre' ..rite Btturttutr Pituting. 1251 Harris. D. 0.. and Dedhi.a, I, 1991. Th-r-i tirt'i anti U ,,rs M nualIrr, p, -

NUREGY-0313. Rev. 2, U.S. Nuclear Regulatory Commnrission, Washinrgton, PRAISE. A P,'oblbiistic Fttr rie W'chnitsi (;ootputer Case t1e PipingRe-i liibilirstn Anrl.is, NUREG/CR-5864, U.S. Nuctra, Regulatory Co.o.iruissioni

[fillti: Ij LiC, 11.

. C.. 19Rt), 1-rosfion/1Grro.sotn-hfucndPip, Wal~l 11fnmng in U.S. Washingirni. DC.

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64 I Vol. 123, FEBRUARY-2001 Transactions ofthe ASME . -

IUNITED STATES GOVERNIMENT NEC-JH 70 ivt morcandum TENNESSEE VA_-LLEY. AUTHORITY 20.Q, U 2? 0:28 TO, H. L. Abercrc-_ie, Site Director, CNP, O&PS-4, Sequoyah Nuclear Fln:

FROM 0.W. Wilson, Project E-ginr-e, Sequoyah Engineering Project, DONE, DSC-E, Sequoyah Nuclear Plant DlATE "

JA.,,'7 i98T

SUBJECT:

SEQUOYAH NUCLEAR PLANT UNITS I AND 2 - PRELfI1INARY REPORT ON THE CONDENSATE-FEEDWATER PIPINGO ISPECTION SUSPECTED EROSION-CORROSIO,%l AREAS Attached for your review is the preliminary report of SQN condensate-feedwater inspection. The results indicate that there is no wall thinning due to ero -"corrosion. o~wevC h'emvb m"

-ae h*a~s not been reduced----:

.below the minimum design wall thickness. Appropriate surve illance instructions shall be written to monitor the suspect areas. '.The instruction will be written by Operations Engineering Services' metallurgical employees and is expected to be in place by June,30, 1987.

The final report will include the results of ultrasonic examinations of the elbows downstream of A and B pump and will be issued the week of February 6, 1987.

D. W. Wilson

• RB FG:L rAttachment cc (ALttachment):

RIMS, SL 26ý C-_K M. J. Burzynski, ONP '&,PS.-4, ..Sequoyah "J. C. Key, DNE, DSC-E, Sequoyah.

J. H. Sullivan, ONP, SB-2, Sequoyah.

-B 14 Ptesn NPOB-2, Sequoyah- (Attn:, E. L--B6o-keor)-

Principally Prepared By: Robert L. Phillips and Terry R. Woods~

extension 694.6 I HC7017-01 P.. FT Q Rn4Poll, n'h-.nwl*V";vrPlan" .

SEQUOYAH NUCLEAR PLANT UNITS 1 AND 2 - PRELIMINARY REPORT ON CONDENSATE-

-EEDATER PIPING INSPECTION SUSPECTED :EROSION-CORROSION AREAS.

Re..erences : D. W. Wilson's memorandu*z to H. L. Atcrcrombie da!-ad

.. December" 19, 1986, "Sequoyah Nuclear Plant Units 1 and 2 Inspection of Feedwater Piping for Wall Loss"

• C(B25 861219 001)

2. Report by P. Berge and F. Khan, of Electricite de France, dated May. 1982, "Corrosion Erosion' of Ste*ls "in High: .

, Te mperature Water and Wet Steam"

3. EPRI NP 39414 report, ".rso Cre o..iNc aPat Steam Piping;* Causes and Inspection Progra~m' Guiidelines".

Background

On-December 9, 1986, Surry Station Nuclear Plant had a pipe" rupture on the condensate-feedwater system that caused several fatalities. !'The rupture was caused by. localized wall thinning at a pipe-to-elbow weld. The thinngni m chan*i'sm:was:identified as erosion-corrosion' (EC). Sequoya . .

(sNuclearelntc, 1Q). iprogrmen h a*program to 'identify possible EC dauiage

seerefrence..1Y,.. The program was developed from technical information: .

from Surry, Station,, INPO network, regional and resident NRC inspectors, and information from:,references 2 and 3. EC is characterized by dissolutionof protective. magnetite film by a high temperature liquid stream. in contact

..wi'th steelA surfaces. EC damage is normally found in elbows. on the extrados

• (outer 'adius;) however, it may also be seen on the intrados (inner radius). The&phenomenon is usually observed in plain carbon and low alloyed steel~s'at elevated temperatures.~ The following are factors influencing the E'C mechan.isms.....

pH and water and/or, steam chemistry C) C Z fe' Material composition . ......

ýFlow path'geometry.

',Temperature I1nQoppozating .the above factors and ex e *ecefrmury'atoa temp.er.a.tue .. boundary E6. ee..ahrenheit was es initial rinspect~ion. Thse. areas e considered to have the highest probability of damage. The locations inspected are identified in figures.l,ý2,.ahd 3.. . . , . .

- -' * . t"-* " *i**';?

": '  ;'** )"  : ,

TTeplants, als~o had. similar operating p&araeters at the iewater chemistry)..', The piping that' failed had

• :~~~A.

.' ', '.*... ' heA

7 .. K ...

08/01/2008 20: 24 3017623511 NUVE'FLUO u.

£ The UT data was uniform and consistent and indicated that there was no thinning occurring as a result of EC, which would appear to be localizen areas of non-uniform thinning. With one exception, there were no readings below the minimum thickness established in accordance with ANSI specifications. -Wall thicknuess measurements taken on the discharge side of the feedwater pump on a 24- by lb-inch reducing elbow (Grid 2-FW-9) showed some evidence of wall loss. This wall reduetion is believed to have resulted from cavitation damage because of the large pressure drop that exists at that Iccation. Although three-percent wall reduction was noted, the minimum wall acceptance criteria for this fitting had not been violated, and this area will be monitored for wall reduction in the future.

The Division of Nuclear Engineeving (DNE) had provided-fl--L~r~m* *J for the areas identified for

'UTerrflfT I . The inspections showed that. . -

Metallurgical Inspection Metallurgical inspections were performed on A and C trains of units 1 and 2 number 2 feedwater heaters. The locations are shown on figure 16. Both the inlet and discharge piping and fittings were inspected. The inlet piping had some superficial patterns on its wall because of direct impingement from the number _ piging g re htank ematite was observed on the ID, and .(see location 3,, figure 16). At -ocation 2, no req mSt. eo e-posed base metal'was observed. On the discharge piping, the results were similar.

Also, there was a backing-ring that had'.been pushed into the flow phth during original installation. It showed no signs of wear and was covered with the protective magnetite film, even though it was in a severe environment.

Discussion UT and metallurgical inspections indicated that no EC damage or significant thinning by other means was detected, although SQN has conducive ee ns. Hoee , II IIIIO PEMIPMR The historyo -6 if Ma-3 Mgrry station is own. Previous inspections on the number 3.heater drain tank, the steam generator feedring header, and the feedring tee did-not reveal s rvice-Induced damage. a~wfn(h J-tuL~s were A106M §rDW ~~doije aTaei we-re as. g 31 ft/sec.) Velocity of the 24- and 30-inch headers and fittings were 12 ft/sec and 14 ft/sec respectively (see table 3). The propensity of the EC decreases with a decrease in velocity.

O6,!F1/2008 19:59 3017623511 NOVERFLO PAGE 05 K

Conclusions and Recommendations The test data and inspection results indicared that EC damage had not occurred in the areas examined. The selected areas were identified as the highest probability areas. However, there may be other thinning mecnanasMs occurring, t.e. cavitation. The lowest readings were found on the discharge side of the feedwater pump on 24- by 16-inch reducing elbows.

None of these readings were below the design minimum wall thickness specified by DUE. The elbows further downstreamQZthe A-and B pumps will be examinedýa__final repon. The.i2in gupstrea of thea a eedWater pbushould'es* m **p aigne* pi a UamnaoDTCO minimize the potential for EC damage throughout the balance of the lant RLF:HC 1/26/87 HC7017.01 -

G. I. Bignold, BSc, PhD, K. Garbett, BSc, PhD, R. Garnsey,'BSc, PhD, C.Chem, FRSC, and I. S. Woolsey, BSc, PhD, CEGB, Leatherhead NEC-JH_71 Erosion-corrosion of carbon steels has been experienced in the steam generator and secondary water circuits of many reactor systems. Damage has occurred under both single and two-phase water flow conditions, and is associated with severe fluid turbulence at the metal surface. In the most severe cases, this can lead to very high metal wastage rates (>1mm/year), and 'consequently rapid component failure. The available experience, previous research and current understanding ofithe phenomenon are reviewed, and both experimental and theoretical work in progress at CERL is /

described. The pH dependence of the phenomenon under single phase conditions at 148 0 C is rfported.

and by using hydrodynamically well characterized specimens, the dependence of erosion-corrosion rate on mass-transfer has been investigated. At 148 0 C, the rate has been found to vary as the cube of the mass transfer coefficient. This is in agreement with the predictions of a model of the process based on the electrochemical dissolution of magnetite. In order to make quantitative measurements on the process, high precision bore metrology and surface activation of the test specimens has been used extensively, and these measurement techniques are also discussed. q INTRODUCTION has occurred in the steam-water circuits of water

1. Nuclear steam generators have experienced a and sodium cooled reactors. As a result there is.,

wide variety of corrosion related problems, and growing international interest in erosion- '

the vulnerability of individual designs to any- corrosion phenomena (ref. 4-7). The present particular type of corrosion damage can vary paper therefore attempts to summarize current widely. In all cases, however, the economic experience' and understanding of the problem, and penalties resulting from such damage are consider- describe erosion-corrosion work in progress at able, 'and there is therefore a strong incentive CERL.

to eliminate such problems as far as possible.

To this end, a wide variety of research programmes EROSION-CORROSION are in progress throughout the world.

4. The term erosion-corrosion is slightly

2. In many nuclear systems, corrosion has misleading and the phenomenon is perhaps better resulted from the generation of aggressive described as flow assisted corrosion. As such solutions via solute concentration processes it is clearly distinguishable from pure erosion (ref.l). This is particularly true in the case or cavitation damage.

of PWR steam generators, for example with the denting, phosphate thinning and tube sheet 5. Erosion-corrosion damage normally occurs at crevice stress-corrosion problems (ref.2). locations where there is severe fluid turbulence adjacent to the metal surface, either as a

3. In the case of U.K. gas cooled reactor steam result of inherently high fluid velocities, or generators, considerable effort has been directed the presence of some feature (bend, orifice etc.)

at understanding and eliminating the possibility generating high levels of turbulence locally.

of corrosion damage resulting from solute Its occurrence is also usually associated with the concentration under two phase flow and dryout use of mild or carbon steel components. The conditions, and the vulnerability of both Magnox attack occurs under both single and two-phase and AGR. steam generators to on-load corrosion water conditions, but not in dry steam, which is and stress corrosion has been reviewed very consistent with the general view that the process recently (ref.3). The need for stringent feed- is essentially one of surface dissolution. It water chemical control was recognised and to ,is frequently, although not invariably, date they have not proved to be a problem. characterized by the occurrence of overlapping However, both Nagnox and AGR steam generators horse-shoe shaped pits, giving the surface a have been subject to an entirely different type scalloped appearance, as shown in Plate I.

of corrosion damage not dependent on any solute However, these pits are normally relatively concentration process, namely erosion-corrosion. shallow in comparison to the general metal Similar erosion-corrosion problems have also wastage in the area concerned. The-oxide present been encountered in other gas cooled reactors on the corroding surface is normally very thin, elsewhere, most notably in France and Japan, but I Vm or less, and often exhibits a polished the problems are not restricted to gas cooled appearance. However, heavy oxide deposition is reactor steam generators, and this type of damage sometimes present on adjacent areas of tube not Water Chemistry II. BNES, 1980, Paper I 5

PLATE 1. Erosion-corrosion damage produced under two phase conditions in a mild steel riser pipe from a Magnox steam generator. Flow from left to right.

4 PLATE 2. Erosion-corrosion damage downstream of the orifice in a CERL mild steel orifice assembly specimen. Flow from left to right.

OXIDE -

110 Pm

• N

~- ~N7 )~

PLATE 3. Metallographic cross section of specimen-shown in Plate 2 in region of maximum erosion corrosion loss.

ý6

0.4 0.3 I0 CORROSION-EROSION LOSS U

0 0- 0 U 0-4 w .9 w I-4 3

IL 0,! 0 z

I I I ~I I I~ it I J I I,"

S I I0 100.

CORROSION-EROSION LOSS. mil/yev FIGURE 3. Erosion-corrosion loss rate v pH for 0

a rotating disc at-99 C (ref.26)

ISo

, C FIGURE 1. Temperature dependence of erosion-corrosion losses under two phase conditions (ref. 19)

tOwP'TTERN REFPRENCE VELOCITY Kc

-  ! AT SLADES PIM.ARY . . - VELOCITY OF FL .-. AT P. INITIALFLOW POINTS STAGNATION

-T-IIAIORIN PIPE IUNCTIONS OOSTACLEI 0.3

'It D I S 0.4 I

SECONOART EL:ON FLOW PIPES ST.DOINTST Z N 02$ FLOWVELOCITY I.)

-'"** SENINOpipe' JOINTS PLOW FLOW STAGNATION L 0(11.0 $MAIt60000 POINTSOUE *r-- , FLO V LO IT I I.- FLOWVELOCITY -0 TO VORTEX STAGNATION POINTS ,f5ONWN T.a..,I~

CONPLIC.STEO _SA *WA.Nss.o PRS' 0...

FLOWTARO UGH r -- . AT I AATIRA-FICURE 2. . Influence of flow path configuration FIGURE 5. Arrangement of orifice assembly on erosion-corrosion damage under two-phase specimens in autoclave flow channels.

conditions (ref.13) 7

/1

s ffering erosion-corrosion attack, particularly Power Station, erosion-corrosion damage at the under two phase conditions. feedwater inlets downstream of the flow control orifices was compounded by flow bypassing

6. Under severe conditions, metal wastage rates through the gap between the threaded ends of the of I rm/year or even higher can be observed in restrictor tubes and the orifice carriers erosion-corrosion situations, so that component (ref.12). In some cases this fluid bypassing failure can be relatively rapid in the worst completely eroded away the restrictor tube end.

cases.

11. In addition to problems within the steam Plant Experience generators themselves, erosion-corrosion damage

7. Under two phase conditions, erosion- has frequently been encountered in wet steam corrosion damage within nuclear steam generators turbines (ref.13) and associated steam pipework has frequently occurred at tube bends, (ref.6), both the feedwater and steam-side of bifurcations or similar features in the steam- feed heaters (ref.14-17) and boiler feed pumps water circuit. Among the earliest reported (ref.7). Clearly therefore the problems are instances of damage of this type were those at very widespread, and not restricted to any one the Tokai Mura plant in late 1968 (ref.8,9). type of nuclear plant.

This station employs dual pressure drum re-circulation type steam generators, and early Current Understanding of Erosion-Corrosion failures occurred at 2140C in swan neck bends and Behaviour tube bifurcations at the outlet end of the mild 12. In spite of the widespread occurrence of steel L.P. evaporator tubes. Some failures also erosion-corrosion problems, as outlined in the occurred at tube bends in the subsequent riser preceeding section, relatively little experimental pipes to the L.P. steam drum external to the or theoretical work on the subject has been steam generator itself, and significant tube reported in the open literature. It is clear, thinning was reported for the last two return however, that erosion-corrosion behaviour depends bends of the serpentine evaporator tube banks on a number of physical and chemical variables.

inside the units. Tube wastage rates as high as These are principally; materials' composition, 1.3 mm/year were found in some cases. Up to the local hydrodynamic conditions including the time of the failures, the boilers had been effects of steam quality, temperature. and water operated with hydrazine/ammonia dosing to give a chemistry. Any model of the process should boiler water pH in the range 8.5 to 9.2. Some therefore be capable of explaining the detailed dosing.with Na 3 PO 4 was also employed to combat dependence of erosion-corrosion on these chloride ion (200-300 ppb) present in the water parameters. Their general influence on (ref.9). erosion-corrosion behaviour under boiler feed-water conditions is summarised below.

8.' Similar failures to these have occurred under steaming conditions in the mild steel 13. Materials' Composition. Erosion-corrosion economiser sections of British Magnox stations, damage is most frequently observed when carbon and in the evaporator sections of once-through or mild steel components are employed. Alloy steam generators such as those at St. Laurent I steels, particularly chrome alloy steels are and II. In the case of St. Laurent II, failures much less susceptible to erosion-corrosion attack,

• and austenitic stainless steels essentially occur-red in the 1800 return bends of the mild steel serpentine evaporator towards the end of immune to damage. Relatively small amounts of the evaporation zone, at a temperature of about chromium in the steel improve its erosion 2450C (ref. 4, 10). As in the case of Tokai Mura, resistance quite markedly, although the degree the boiler feedwater was originally dosed with of improvement appears to depend on the severity ammonia and hydrazine to about pH 9.0. However, of the conditions. Thus in tests at 120 0 C, more recently *morpholine dosing has been employed involving impingement of a water jet on the because of its lower partition coefficient between sample surface at 58 ms- 1 , 2% Cr steel was found water and steam and higher basicity at high to be at least an order of magnitude more temperature, which should maintain a higher resistant to damage than carbon steel, with solution pH at temperature (ref.ll). higher chrome steels even more resistant (ref.18).

However, practical experience with wet steam

9. Erosion-corrosion problems under two phase turbines and their associated pipework suggests conditions have also been reported to have 21% Cr steel to be about four times more occurred in the steam generator units at Marcoule resistant to attack than mild steel, whilst 12%

and Chinon 2 (ref.4, 10). Cr steel has proved to be virtually unaffected (ref. 13).

10. Erosion-corrosion damage in nuclear 9team generators under single phase (water) conditions 14. It is likely that other minor alloying or has commonly been associated with boiler feed- trace elements such as copper, nickel, water tube inlets, and in particular those where manganese and silicon would influence resistance orifices have been installed to control the to erosion-corrosion as such elements are known boiler feed 'flow. Damage of this type has been to affect corrosion resistance of carbon and low experienced at St. Laurent II, with an inlet alloy steels to a wide range of aqueous feedwater temperature of about 1250C (ref. 4,10), environments. However, there appears to be no and at somewhat higher temperature (up to 246 0 C) systematic studies reported in the open in the case of the Phenix steam generators literature.

(ref. 5!, 10). In the case of Hinkley Point 'B' 8

15. Temperature. Erosion-corrosion damage is pH was less than 9.0, but attack was not most prevalent in the temperature range 500 to normally observed with pH >9.2. Similarly, the 0

250 C. Fig. 1 shows the effect of temperature occurrence of erosion-corrosion damage in wet on relative erosion rates based on data derived steam turbines has been reported to occur only from damage occurring'under two phase conditions when the condensate pH is below about pH 9.4 in wet steam turbines (ref.19). This indicates (ref.13,19).

0 maximum damage to occur at around 180 C. How-ever, more recently it has been proposed that 21. The effect of pH on erosion-corrosion under single phase conditions, the maximum is rates has been studied experimentally by 0

close to 140 C (ref.20). Limited studies on the Apblett (ref.26) using a rotating-carbon steel 0

effects of temperature under single phase disc over the pH range 8.0 to 9.5 at 99 C in conditions have also been reported by Decker, deaerated water. The results are shown in Wagner and Marsh (ref.21) which would appear to Fig. 2, and indicate a tenfold reduction in support this, but there remains some uncertainty wastage rate on increasing the pH from pH 8 to 9.

in the precise variation of erosion-corrosion Similar reductions in rate have also been 0

rates with temperature. For example, rapid two reported for jet impingement studies at 120 C phase erosion damage has frequently been observed (ref.27).

0 at temperatures well in excess of 200 C (e.g.

St. Laurent II), whereas the curve in Fig. I 22. The effect of oxygen on erosion-corrosion would suggest the problem to be disappearing behaviour as such has not been studied in great rapidly at these temperatures. detail. However, iron release rates from carbon 1

steel in neutral water at 1.85 ms- over the

16. Hydrodynamics. Erosion-corrosion damage temperature range 380. to 2040 C have been shown has in general been observed at points of to decrease by up to two orders of magnitude hydrodynamic disturbance in the fluid flow. with increasing oxygen content over the range Under single phase conditions damage has <1 to 200 ppb (refs.23, 28-31). It is to be

( frequently occurred at tube entries in preheaters, expected that erosion-corrosion will at least or downstream of orifices at boiler tube entries, qualitatively follow this type of behaviour.

whereas under two phase conditions the damage has often been associated with bends. Keller 23. Additions of up to 300 ppb oxygen (or more (ref.19) has attempted to rationalize the effects. commonly hydrogen peroxide) to neutral feedwater of various flow path configurations on erosion- forms the basis of the neutral oxygen low corrosion damage under two phase conditions by conductivity (NOLC) water chemistry regime used use of an empirical damage factor (Kc) together by a number of power utilities for fossil fired with a reference flow velocity. -These are given once thro' boilers (ref.32), and these are in Fig. 2. However, it is doubtful that these evidently largely free from erosion-corrosion parameters can be equally well applied to damage damage. 'More recently, it has been reported under single phase conditions as a result of the that combined NH3 /H 2 02 dosing of feedwater is differing hydrodynamic flow patterns which would also effective in this respect (ref.33).

occur. More recently at CERL and elsewhere (ref.7) attempts have been made to relate erosion- Models of Erosion-Corrosion Behaviour corrosion rates in single phase water to local mass transfer rates, and these will be discussed 24. Keller (ref.19) has proposed an empirical subsequently. equation for predicting erosion-corrosion losses from carbon steel, based on observations in wet

17. In view of the critical dependence of steam turbines. This has the form erosion-corrosion damage on fluid flow and turbulence, it is surprising that no detailed s = f(T).f(x).c.K c - K5 (1) studies have been reported of the effect of flow velocity and turbulence on erosion-corrosion rates. where s is the maximum local depth of material Some studies have been made at high temperature loss in mm/10 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

(>280 0 C) (ref.22-24), but these are outside the range normally associated with erosion-corrosion f(T) is a dimensionless variable denoting the attack. influence of temperature on erosion-corrosion damage. A plot of f(T) is shown

18. Water Chemistry. Several aspects of water in Fig. 1.

chemistry are thought to influence erosion-corro-sion behaviour. The effect of pH and oxygen con- f(x) is a dimensionless variable denoting the tent of the water have been examined;, but other influence of steam wetness on erosion-components such as hydrazine and dissolved iron corrosion loss. For sub-cooled water it are also expected to exert a significant has been suggested that this has a value influence on the process (ref.25). of unity, but for two phase mixtures' it has the form f(x)= (I - x)K where x is the

19. Most instances of erosion-corrosion steam fraction and 0 << Kx <1 . A value of damage have occurred with a deoxygenated volatile Kx. = 0.5 is evidently considered the most alkali dosed water chemistry. appropriate one.

Kc is a variable factor accounting for the

20. In studies of erosion-corrosion damage in feed heaters (ref.14,15), it was found that effect of local geometry on the fluid flow.

attack occurred predominantly when the feedwater Values of Kc in mm.s/mI10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> are 9

( (

I-.

0

,-.------5 -.-.- IAirrelease valve Deinied atr nk Oeiniedwtetan PupL.R e change pmpA t nf BL.R. ion exchange Main circulation pump Cartridge liler -C T

--- o -- T PAPC F I Tank PC !ankVCP TankC tan PC I T Pressurizer fI i PA IA /B /C P T PL Venturi I5 4-OP T )

Tube Tube I I I sample 1 sampfe2 N~

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Flow Mains supply Venturi4 Venturi 3 Mains ooling I P T/C Condu~ctivity I " - - . / J -- 208 Kg/h either sample, not both mCotroiervity supplyy Healer2 Mainais Coolngp T

Conductivityty P Pressure gauge cotole Coln water T Thermometer TC Thermometerlcontrot

• F Flow indicator/control PC Pressure control L Level indicator/control FIGURE 4. Isothermal Rig flow diagram

500 400 Do0 100 200 80 100 S 60 60 Sso 2 4o t.

0 40 U 20 Is 20 to 0 10 DEPTH.. TEMPERATURE. °C 56 FIGURE 6. Activity/depth curve for Co produced FIGURE 8. Variation of magnetite solubility in an iron matrix by a 10.8 MeV proton beam with temperature and pH at' bar hydrogen inclined at 100 to the surface partial pressure. (Ref. 42) 4.0 F-30 j E

E I-2.0 1- U 0

U 1.0 I I I I I I I I I 1 2 3 4 5 6 7 a 9 ORIFICE TUBE DIAMETERS BEYOND FIGURE 7., Variation of mass transfer coefficient in a tube downstream of an orifice ItO 160 , 120 Ito 100 t0

, DISTANCE F""04 SPECIMENOUTLET. -

FIGURE 9. Erosion-corrosion loss profile in tube downstream of an orifice (Dianetral circumferential locations shown. Orifice located 185 mm from specimen outlet) 11

given in Fig. 2. behaviour under two-phase conditions.

c is the fluid velocity in ms-1 Experimental Facility

28. Experimental studies of erosion-corrosion K is a constant which the first term must are being carried out using a high velocity exceed before erosion-corrosion is observed. isothermal water circulation loop, referred to 4

A value of 1 mm/lO hours has been given by as the isothermal rig for short '(ref. 37). This Keller (ref.19). facility consists basically of a main circulation loop, a secondary water clean up loop and a Equation (1) does not include any influence from pressurizer loop, together with ancillary changes in water chemistry, although as indicated" make-up/dosing and chemical sampling systems. A earlier, these have a very marked effect on the flow diagram for the rig is shown in Fig. 4.

rate and occurrence of erosion-corrosion damage.

It is also very doubtful that it can be applied in its present form to single phase erosion- 29. Four specimen flow channels are incorporated corrosion damage, since many instances of damage in the rig, two specimen autoclaves in the main have occurred under single phase conditions which loop, and two tube specimens within the secondary would not have been predicted by equation (1). polishing loop.

25. Discussions of some mechanistic aspects of 30. The rig is principally constructed of Type erosion-corrosion attack has been given by Homig 316 stainless steel, with the exception of the (ref.34) and Bohnsack (ref.35), who concluded that pressurizer vessel (21 Cr 1 Mo ferritic steel),

the process is due to dissolution of the metal the heater elements (Inconel) and some parts of 2

surface to give Fe + ions in solution, which are the main circulating pump (Incoloy 825, stellite continually removed by the turbulent fluid flow. and ferobestos). The rig is designed to operate However, both these authors restrict themselves over the following range of physical conditions:

largely to discussion of the dissolution at 0

250C, which is well below the temperatures at Temperature, up to 350 C which erosion-corrosion attack is normally 2 2 encountered. At 25 0 C, Fe(OH) 2 is normally Pressure, up to 21.78NNB- (3160 lbf in- )

considered to be the corrosion product involved in the dissolution process in deoxygenated water, Autoclave but at, temperatures higher than about lOOoC, this up to 1031 kg h-1 per autoclave flowrates, is converted to Fe 3 0 4 via the Schikorr reaction:,

Tube specimen 1 up to 208 kg h- total 3 Fe(OH) 2 -÷ Fe 3 0 4 + 2H 2 0 + H2 (2) flowrate, The rate of this reaction increases with tempera- Bypass flowrate,up to 103 kg h.1 ture, and magnetite is typically the phase observed on surfaces undergoing erosion-corrosion Pressurizer attack at temperatures above about 1200C. As a up to 20 kg h-1 flowrate, result, erosion-corrosion attack at these higher temperatures has been attributed to rapid Once the rig water has been pressurized and water dissolution of the unstable Fe(OH) 2 intermediate circulation achieyed using the main pump, (ref. 36). conirol of the physical operating parameters of the\rig is'largely automatic, with the variables

26. Very recently attempts to produce a model of interest (flow rate, temperature, pressure, of erosion-corrosion based on calculated mass water level etc.) being recorded by a dedicated transfer rates and the 'solubility of magnetite CAMAC data logger..

have been made by GUlich et al. (ref.7). Work to produce a more satisfactory model is also in 31. The rig incorporates four methods for progress at CERL, and this is outlined in controlling the water chemistry, namely ion subsequent sections. However, at present there exchange, chemical dosing, blowdown and deaeration.

is no completely satisfactory model of erosion- Data on the chemical composition of the water corrosion behaviour which is capable of rationali- within the rig is derived mainly from continuous sing the effect of all the diverse factors chemical monitoring of sample streams which can influencing the process. be drawn from a large number of different sampling points around the rig. The exception to this is CERL EROSION-CORROSION STUDIES the direct measurement of conductivity before and

27. The work currently in progress at CERL on after the. ion-exchange columns. To date, all the erosion-corrosion is directed at establishing a experimental work carried out on the rig has been consistent set of experimental data from which with an ammonia dosed deoxygenated water chemistry it is possible to make accurate predictions of regime, and for these conditions it has been found plant-behaviour, and to develop a satisfactory convenient to work with the cation exchange resins theoretical model of the process Zapable of of the mixed bed ion-exchange columns converted rationalizing the experimental, work. At present, to their amnonium ion form.

both experimental and theoretical studies are concerned entirely with erosion-corrosion in 32. In its present form, the rig is capable of single phase water, although it is to be hoped operating within the following limits of physical that the results of the work can be applied with and chemical control parameters.

certain limitations to erosion-corrosion 12

N-Temperature at test specimens loC hydrodynamically. They can therefore be used for prdcise'correlation of erosion-corrosion and Flow to test specimens +/- 1% mass transfer behaviour (see subsequent discussion). The particular specimens used pH of circulation water* - 0.1 pH unit permit behaviour to be studied at five different potential erosion-corrosion sites; the Conductivity of water after PS cm-I tube inlet, the jet reattachment zone downstream

< 0.6 cation exchange+ of the orifice, downstream of a tube expansion, land in two different diameter straight tube Dissolved iron in circulating sections (i.e. two different flow velocities).

0 < 10 Pg kg-water at 148 C The specimens also have the advantage that being essentially straight tube test pieces,-it Dissolved active silica in is possible to use high accuracy bore diametral 0 < 10 pg kg-circulating water at 148 C measurements to characterize the erosion loss profile throughout the specimen.

Dissolved oxygen in circulating 0 < 6 pg kg-I water at 148 C Erosion-Corrosion Monitoring Methods

37. Simple weight change measurements-are

,* Dependent on pH of circulating water, values possible on all the test specimens described, given for pH 9.0. At higher pH, the precision except the tube specimen channels themselves.

of pH control improves, and dissolved Fe levels However, most of the' effort to date has been fall. concentrated on monitoring damage produced in the orifice assembly specimens, and this has

+ Upper limit of conductivity, due to very slow been done principally by the use of high sampling rate. accuracy bore diametral measurements, and thin layer surface activation methods.

Test Specimens

33. A variety of erosion-corrosion test 38. Bore Metrology. Measurements of bore specimens can be incorporated into the isothermal diameter have been made on test specimens using loop, using both the autoclave and tube specimen a "Diatest" internal bore measuring instrument.

flow channels. This instrument permits diametral measurements to be made with a precision of +/-I pm, and on a

34. The tube specimen channels are provided uniform tube surface, the reproducibility was with couplings for the attachment of tubing better than +/-2 pm. The tubes used in the present between two'points 2 m-apart. Initially straight work are typically either drawn, or machined 3 mm bore mild steel test specimens and stainless from bar material and.have a honed surface finish.

steel dummy specimens have' been incorporated, but In both cases, the quality of the tubes used is it is possible to incorporate bent tubes, bore sufficiently good' to permit measurements to be expansions and constrictions and a~variety of made with the reproducibility quoted above.'

other options in this area of the rig.

39. On non-uniform tubes, or heavily eroded

35. Fourplate type specimens, 195 x 12 x I mm surfaces where the diameter changes rapidly, the can be incorporated into each of the autoclave reproducibility of measurement is reduced, flow channels using stainless steel specimen principally due to the relatively poor longitudinal holders. These hold the precision (+/-0.5 mm) with which measurements are specimens with -a I mm gap between them, and made at present. Measures are currently in allow rig water to flow along their length. How-hand to improve this by using an automated ever, it is possible to incorporate other types measuring procedure. Nevertheless, in all cases of test specimens in the autoclave flow channels, to date it has been possible to produce highly and most of the work to date has involved the use accurate bore loss profiles from the test of orifice assembly specimens. Up to three such specimens.

assemblies can be accommodated in each autoclave flow channel, as shown in Fig. 5. To minimise 40. Surface Activated-Specimens. Erosion-interaction between specimens in series with one corrosion losses of a number of specimens have another, a baffle plate can be-inserted, as shown been monitored in situ by the'-use of thin layer in Fig., 5, and this also serves as an impingement activatioa of the specimen. To date this has specimen. It is possible to incorporate up to only been employed with orifice assemblies, but three orifice assemblies in parallel on the inlet can in principal be used for any type of Grayloc seal of the autoclave, and, in this way specimen.

interactions between adjacent tubes could be studied, in addition to increasing the total 41. The~technique consists of activating to a, number of specimens. This does, however, reduce known depth an area of the specimen surface by the flow through any one specimen to one third of high energy charged particle bombardment (ref.38).

that through the specimen on the autoclave outlet Metal loss from the specimen can then be deter-Grayloc seal. mined by monitoring the loss in activity from the specimen surface as erosion-corrosion proceeds.

36. The advantage of using this type of orifice In the present work, small areas of *the internal assembly is that experiments can be performed tube surface (5 to 10 mm x 1.75 mm) have been on specimens which accurately simulate plant activated by bombardment with 10.8 MeV protons components, and which are well characterised at angles of 100 or 200 to the tube surface.

13

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an orifice at 1570C, and pH 9.05 10.0 10 GEOMETRY - ORIFICE.2.72 mmDIA

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L"_LJAj u.gl I J I I t I I i I , I I 0.1 1.0 10.0 9.0 9.1 9.2 9.3 9.4 9.5 9. 9.7 MASSTRANSFER COEFFICIENT. mis-1 1 10 PH FIGURE 11. Correlation of erosion corrosion FIGURE 13. gH dependence of erosion-corrosion rate downstream of orifice with corresponding rates at 157 C. Solid symbols, maximum rates mass transfer coefficient throughout the from surface activated specimens, open symbols erosion-corrosion zone average rates 14

The bombardment of Fe with high energy prc)tons where Sh in equation (6) refers to the maximum produces 5 6 Co which has a half-life of 77.3 days, Sherwood number observed downstream of the and the principal y-ray emitted on decay has an orifice, and ReN the orifice Reynolds number.

The overall variation of mass transfer energy of 845 keV. The maximum depths of activation for bombardment withprotons at II00o coefficient K in the tube downstream of the orifice is illustrated in Fig. 7.

and 200 are around 35 and 70 pm respectivel3 Deeper activation is possible by bombarding

.ng 46.

clearlyThebe value of C. in equation (3) may normally to the tube surface, or by increasi determine5 experimentally 56 for any the incident proton energy.' The,-total Co at given erosion-corrosion situation, and for most activity versus depth curve for bombardment situations of practical interest will be very 100 to the tube surface is shown in Fig. 6.

low, probably less than 10 jg kg- 1 . However, Loss of material from the specimen sui-face the 'concentration of iron in solution at the 42.

oxide-solution'interface cannot be so easily has been determined in-situ by monitoring th ae y-ray emissions from the sample using a evaluated. In the first instance, it might be scintillation detector placed in close proxi [mi ty assumed that this term may be equated with the to the autoclave containing the active speci men. equilibrium solubility of the surface'0 oxide, These have permitted measurements of erosion loss which at temperatures above about 100 C is If however some to be made as a function of time with an acc :uracy uaof usually taken to be magnetite.

metastable intermediate oxide such as Fe(OW2 of +/-0.1 pm in the case of an activation dept 35 Um. is invoked, then a different solubility would be appropriate.

43. Full details of the experimental techn ique 47. The solubility of magnetite is known to be will be reported elsewhere (ref.39).

dependent on temperature, pH and hydrogen Theoretical Work partial pressure (ref. 42). Fig. 8 shows the variation in magnetite solubility with pH and

44. If erosion-corrosion is controlled sol ely temperature at I bar partial pressure of by the rate of mass transfer of Fe from the hydrogen (1585 pg kg-y) derived from the data of eroding surface, then the erosion-corrosion rate Sweeton and Baes. However, these solubilities may be expected. to vary according to are much higher than would be anticipated in operating plant, where the partial pressure of d = K(C - C) (3) hydrogen would be much lower (il-5 pgkg- 1 ).

dt s b Under these circumstances the equilibrium Where K = mass transfer coefficient solubility of magnetite, when taken with the expected mass transfer coefficients is far too C = concentration of iron in solution at low to explain the observed erosion-corrosion S the oxide-solution interface rates (ref.43). This analysis would indicate C= concentration of iron in the bulk that the solubility of the surface oxide is much higher than that expected for magnetite in' solution equilibrium with the bulk partial pressure of dm = rate of metal loss. hydrogen. It is possible; however, that the dt solubility may be sufficiently enhanced locally

45. The value of the mass transfer coefficj Lent by the high equivalent partial pressure of K varies with the local hydrodynamic conditi( ins. hydrogen which results from the high local Its dependence on these is usually expressed in corrosion rate. Once established, the high dimensionless form using the corresponding local solubility in turn assists in maintaining Sherwood number Sh, where Sh = KD/D, D = duct the high erosion rate. Electrochemically this diameter and D = diffusion coefficient for ii .,on is equivalent to the dissolution process in solution. This is normally expressed in t :erms occurring at relatively negative potentials, of the Reynolds (Re) and Schmidt (Sc) numbers in which is in agreement with the general observation empirical correlations of the form that actively eroding areas are normally covered with magnetite, whereas nearby non-eroding Sh = aReaScy (4) surfaces are frequently covered with haematite.

This possibility may be analysed theoretically where n, B andy are constants determined by in the following manner:

experiment; y typically has a value around I/ 3, whilst the value of a is usually in the range 48. At equilibrium the dissolution of 2/3 to 7/8. Correlations of this type are magnetite to form Fel+ ions in solution (the already available for a number of hydrodynami c dominant species under the conditions of interest) situations of concern in erosion-corrosion, and may be expressed as:

two of particular interest in the present wor ks Fe304 +2H 2 0+2H 3Fe(OH) 2 are those for turbulent flow in straight pipe M 2+ +60H-(ref.40), and downstream of an orifice (ref.4 1). (7)

These have the form: .

for which the appropriate Nernst-equation is Straight pipes: Sh =0. 0165 Re 0.86 Scý0.33 (5) 3 E E=E-=Zn j-* Zn RTe(o1) (H 2 ]

(8)

Downstream of, 0.67 '0.33 27 an orifice: Shmax =0. Re" Sc (6) 1H12 15

which. gives ./ 51. In the case of specimens undergoing very F ~../ 2fH -ep -2FCE - E)

"Is (9) rapid erosion-corrosion wastage, the films are sufficiently thin to exhibit interference colours.

I jWith lower erosion-corrosion rates, however,, the eroding surface is black, as for non-eroding areas of the tube surface.

[Fe (OH) 211H] 2 52. Micropitting of the tube surface to a depth of about 5 pm is evident in the erosion where K2 = zone shown in Plate 3, and this is associated with accelerated attack of the pearlite grains reaction of the steel. Effects of this type have also The cathodic current ic of the corrosion surface been observed in plant specimens.

resulting from hydrogen discharge at the of the magnetite film may be expected to vary exponentially with the surface potential E of the 53. Most of the work to date has involved the use of mild steel orifice-assembly specimens, film, as follows:

and Fig. 9 shows a typical erosion-corrosion loss i = - FB exp --n- [0) profile downstream of the orifice, obtained c R using the bore measuring technique outlined previously. The general similarity to the mass If the anodic current ia at this potential is transfer profile shown in Fig. 7 is immediately limited by the rate of removal of Fe 2 + ions apparent. However, it is clear that the from the surface, and since ia + ic = 0, straight tube losses are quite small, whereas Fig. 7 shows the mass transfer coefficient decays asymtotically to that appropriate to the straight 2 FK Fe2+- FBexp 11) tube, which is about 1/3 to 1/4 of that at the mass transfer maximum. It is important to note however, that the maxima in both curves occurs if C. ý Ie e 2 +] and I then substitutin approximately 2 tube diameters beyond the orifice.

from equation (9) and eliminating E gives

54. Experiments exposing several specimens at different flow rates under the same conditions 2 2= 4K2 H ]8 2FE0 may be used to establish the flow and hence mass exp - (12 transfer dependence of the erosion rate, and 32 - Fig, 10 shows the velocity dependence obtained at 148 0 C using pairs of specimens at three different flow rates. The slope the plot indicates a V2 In this case the Fe2+ solubility of magnetite at dependence of erosion rate on flow, which the surface is dependent on the square of the masSs according to equation (6) would indicate a transfer coefficient K, giving an overall dependence on mass transfer coefficient cubed.

dependence of the erosion rate on the cube of Further confirmation of this K3 dependence is the mass transfer coefficient, through equation shown in Fig. 11, where the erosion loss (3). ,profiles of individual specimens have been compared point by point with the corresponding mass

49. This treatment may be extended to include transfer profile of the type shown in Fig. 7.

all soluble iron species under the conditions From this it is seen that not only do the of interest, and the effects of a non negligible maximum losses downstream of the orifice conform bulk concentration of iron. The expressions with the K3 dependence, but the erosion-corrosion become more complex in this case, but still rates over nearly the whole profile of the indicate a dependence of erosion-corrosion rate specimens correlate with K3.

on the cube of the mass transfer coefficient (plus smaller terms in K2 and K). Further 55. Whilst this alone does not substantiate analysis of the mechanistic aspects of erosion- the theoretical treatment outlined in the corrosion is still under consideration, but this previous section, it does provide strong support rather unexpected dependence of the rate on the for the type of mechanism invoked, and indicates cube of the mass transfer coefficient is born that further development of the theory along.

out by experiment. these lines should prove very fruitful.

Results 56. Fig. 12 shows the erosion-corrosion loss of an orifice assembly specimen downstream of

50. Plate 2 shows the erosion-corrosion zone the orifice as a function of time, determined downstream of the orifice generated in a mild from the activity loss of a surface activated steel orifice assembly test specimen. Although spot in the erosion-corrosion zone. It is .

the surface loss at the erosion maximum is evident that under the particular conditions relatively large (%,150 um), scalloping of the used, there is a substantial initia;ion time surface, of the type shown in Plate I has not before any erosion-corrosion loss is observed.

yet developed. However, the oxide film present Once initiated, the erosion-corrosion rate in the eroded area is extremely thin, as shown rose rapidly to a high value, and then remained in Plate 3. constant for most of the remainder of the test (the reduction in rate towards the end of the 16

test shown in Fig. 12 is -thought to be due to 60. ,Since .mass-transfer coefficients can be changes in experimental conditions). This typc calculated for a wide variety of hydrodynamic of behaviour has been observed on a number of situations, at least under single phase occasions, although the initiation time can vaiT conditions, it should be possible to use widely with the experimental conditions, generz lly correlations of this type to predict plant being much shorter under more aggressive behaviour over a wide range of conditions.

erosion-corrosion conditions. The cause of suc:h initiation periods is not certain at present. 61. Increasing pH has-been shown to markedly In some cases this most likely represents the reduce erosion-corrosion rates over the range time taken to remove a thin oxide film produced 9.05 to 9.65, in agreement with other studies of during start-up of the rig, when specimens are the effect at lower temperatures. In many plant Sexposed to low flow for a few hours. In other situations, therefore, this option should prove cases it is thought that thin air formed oxides effective in controlling erosion-corrosion produced during welding of the test specimens damage. It is likely to be especially useful were responsible. However, in some cases, an when other options such as materials change or initial loss of a few microns has been observedi, oxygen addition are not feasible.

after which no loss has occurred for up to 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />, before true erosion-corrosion attack has 62. Details of the mechanism of erosion-been initiated with a continuing linear loss as corrosion damage have still to be established, a function of time. This would suggest that but the use of surface activation in the present initiation is more complex than simply removing work has proved to be extremely valuable for a pre-existing oxide film, and may indicate monitoring losses in-situ. Using this technique changes occur in initially formed films under it has been possible to establish the linearity erosion-corrosion conditions. of erosion-corrosion loss as a function of time, after some initiation period, and it will

57. The pH dependence of erosion-corrosion ra tes undoubtedly be useful( in studying erosion-has also been investigated using orifice assemb lies corrosion behaviour under transient conditions.

and Fig. 13 shows the results obtained at 1480C In conjunction with electrochemical techniques, The upper limit of, the data is essentially therefore, it should prove very valuable in derived from the maximum linear rates observed elucidating aspects of the corrosion mechanism.

using surface activated specimens. The rates derived from other specimens are average rates, ACKGN OZEDGEl-,NTS which are in general lower as a result of a significant but unknown initiation time. The 63. We wish to thank J.H. Ashford, C.H. de Whalley, erosion-corrosion rates decrease by a factor of D. Lihaert and R. Sale for t-heir assistance with about 7 over the pH range 9.05 to 9.65, which iis the experimental work described, and M.W.E. Coney equivalent to a variation withEH+1l. 4 . This is for helpful discussions on OT-_Ss-t-r-nsfer a somewhat higher dependence than that seen by behaviour in turbulent flow, Apblett (ref.26) at 99'C, where the erosion-corrosion rate varies asi"H+i.-O. 64. This paper is published with the permission of the Central Electricity Generating Board.

SUZ52ARY REFERENCES

58. Corrosion resulting from salt concenntratji caused by evaporati continues to be a ma7ajr i. GAi~2~Y R. Boiler corrosion and the cause of steam generator damage, particularly .reuirementfor f*eed- and boiler-water, chemical in PWIRs and has been the subject of intense Control 4 nuclear steam generators. BNES international research. Erosion-corrosion damag:e Conference on Water Chemnist;r of Nuclear Reactor has occurred in a wide variety of nuclear steam Systems ,BNES, London, 1978, pp 1-10.

generators, but unlike corrosion resulting from 2% G-A-SEY R. Nucl. Energy 18, 117; 1979.

solute concentration, relatively little work on 3. GARTNSEY R. Reducing the risk of water-steam the problem has been reported in the open corrosion damage in U.K. Cas cooled reactor literature. The available experience, previous steam generators. Paper presented to ADERP research a.d current understanding of the meeting on Vater Qiemistry and Corrosion in the pzlinomcný_-- hav-7* been reviewed, acid CERL research-Steam-Water Loops of Nuclear Power Stations,

_; ---e z- ,"- *T.r:ectua riz -d. w 4-e ac, amrch C-80.

.- neraceurs de vapeur chaufes

`ails l-a ceoatiales nuceiaires occur in .nlant By tz'si.n test snec*-cns v-W~rh

~~.Z are well characrerised hydrodynamically, it has been possible to accurately correlate erosion-

__ A"-P"76-' M1.CEr ON tilý corrosion rates with the correspoonding mass-transfer rate. Under the particular conditions generate=d -ýacurt- -),zreotusanrn nn uheo (L4iC, ph 9.05), it has been found that rapi5des. Pnrr'- resented t- ADERP -Ot.fl5 Le orarse variae as the cube-on transf- r Water Chemistrv and Corrosion in the Stean-Water uskafi,4i8:- phis 9 n.)ethas been i mI.eaa t Loops of Nuclear Power Stations, Seillac, "M

-Le- -.*w 4;,14 te*xpec.-

ca M.arch 1980.

6. CE.XDA14 j.F. G, EGil3uE j. and LACAILLE L.

s i* des phanomnes derosion-corrosion 17

possibles. Paper presented to ADERP meeting p.2, 1971 on Water Chemistry and Corrosion in the Steam- 36. BORSIG F. Der Maschinenschaden, 41, 3, 1968.

Water Loops of Nuclear Power Stations, Seillac, 37. ASHFORD J.H. BIGNOLD G.J. DE WHALLEY C.H.

March 1980. FINNIGAN D.J. GARBETT K MANN G.M.W. MCFALL F.

7. GULICH J.F. FLORJANCIC D. and MULLER E. and WOOLSEY I.S. CEGB Report RD/L/N 126/79.

L'erosion-corrosion dans les pompes d'alimentation 38. CONLCO T.W. WEAR 29, 69, 1974.

et d'extraction. Recherches et choix des 39. FINNIGAN D.F. GARBETT K and WOOLSEY I.S.

materiaux. Paper presented to ADERP meeting on to be reported.

Water Chemistry and Corrosion in the Steam-Water 40. BERGER F.P. and HAU K. -F. F-L. Int J.

Loops of Nuclear Power Stations, Seillac, March Heat Mass Transfer, 20, 1185, 1977.

1980. 41. TAGC D.J. PATRICK M.A. and WRAGG A.A.

8. Japan Atomic Power Company Limited, Third Trans. I. Chem.E. 57, 12, 1979.

technical collaboration report on S.R.U. tube 42. SWEETON F.H. and BAES C.F. J.Chem.

erosion and corrosion at the Tokai Nuclear Power Thermodynamics, 2, 479, 1970.

Station, J.A.P.C. Report,November 1969. 43. CONEY M. Private Communication.

9. Japan Atomic Power Company Limited, Fourth Technical Collaboration Meeting on S.R.U. repair work at the Tokai Nuclear Power Station, J.A.P.C.

Report, September 1970.

10. GARAUD J. Revue Generale Nuclaire, No. 1,

p. 29, 1978.

11. BERGE Ph. and SAINT PAUL P., Electricite de France Report HC PV D 389 MAT/T.42.

12. PASK D.A. and HALL R.W. Nuclear Energy, 18, 237, 1979.'

13. ENGELKE W. in 'Two Phase Steam Flow in Turbines and Separators', ed M.J. YORE and C-H. SIEVERDING, McGraw-Hill, p. 291-315, 1976.

14. PERGOLA A.C. and PHILLIPS A. Heat Enzineer-ing, p. 72, September-October 1965.

15. PHILLIPS H. Foster Wheeler Corporation (New Jersey), Report No. TR-36, 1966.

16. KELP F. MITT V.G.B. 49, 424, 1969.

17. DOR F. Revue Generale Thermique, 166, 705, 1975.

18. WAGNER H.A. DECKER J.M. and MARSH J.C.

Trans. ASE 69, 389, 1947.

19. KELLER E. V...B., KraftwerkStechnik, 54, 292 1974A

20. FLTLP HN. J. !nternationaleS D'Et,,des Des Centrales Flectrique, Paper A2, 1978,

21. DECKER J.M. WAGNER H.A. and MARSH J.C.

Trans. ASi'E 72, 19, 1950,

22. WARZEE N. DARLODOT P.de and WATY J.

EURATOM Report No. EUR 2688.F., 1966.

23. NES-EYANOVA K.A. Atomnaya Energiya, 29, 781, 1970.

2f. BERGE P. ADERP Conference, E rmeenonvilie, 1972.

0zMT T IT- IJ T T-I N W Paper to this Conference. U

26. APBLETT W.R. Proc. Am. Power Conf. 29, I 751, 1967.

U 27.

28.

-DECKER J.M. and MARSH J.C. Trans. ASME 72, 19, 1954..

BRUSH E.G. and PEARL W.L. Proc. Am. Power Conf. 31, 699, (1969).

29. BRUSH E.G. and PEARL W.L. Proc. Am. Power I

Conf. 32, 751, (1970).

30. BRUSH E.G. and PEARL W.L.. Corrosion 28, 129, 1972.

IT. VREELAND D 1 G.G. and PIEARL W.L.

C.orrosion 17, '~-* lfl./

32. FREIr .

RýK V.G.B. Feedwater Conference p8 Oct. 1970.

33. EFFERTZ P.H. FICHTE W. SZENKER B RESCH C.

BURGMANN F. GRUINSCHLAGER E. and BEETZ E, VGB Kraftwerkstechnik 58, 585, 1978.

34. HOMIG H.E. Mitt V.G.B., 76, 12, 1962.

35. BOHNSACK G. V.G.B. Feedwater Conference,

NEC-JH_72 Paper 96. The influence of oxygen and hydrazine on the erosion-corrosion behaviour and electrochemical potentials of carbon steel under boiler feedwater conditions A

I. S. WOOLSEY, BSc, PhD, G. J. BIGNOLD, BSc, PhD, C. H. DE WHALLEY, BSc, MIChemE, and K. GARBETT, BSc, PhD, CEGB. Central Electricity Research Laboratories. Leatherhead In the temperature range 100 to 250 0 C, carbon steel is highly susceptible to erosion-corrosion damage in deoxygenated boiler feedwatef whefin mass ansfer coefficients are sufficiently high. The erosion-corrosion process can be completely inhibited by addition of low levels of oxygen to the feedwater, but experiments have shown that the process continues essentially unaffected below a critical oxygen threshold. The oxygen level required to inhibit the process depends on the local oxygen mass transfer coefficient to the eroding surface, and the existing metal loss rate. An upper limit for the threshold concentration can be derived from the rate of oxygen mass transfer to the surface required to match the ongoing erosion-corrosion rate. Under these circumstances, the cathodic current normally supplied by the hydrogen evolution reaction can be substituted by an equivalent one due to oxygen reduction. When the critical rate of oxygen mass transfer to the surface required to inhibit erosion corrosion is achieved, the surface electrochemical potential.

shifts several hundred millivolts positive of that previously maintained. Oxygen has been shown to inhibit erosion-corrosion and control the electrochemical potential of carbon steel even in the presence of large excesses of reducing agents such as N2 HA and H2, at temperatures up to 25 0 °C.

However, removal of the oxygen by reaction with hydrazine allows the erosion-corrosion process to re-initiate rapidly. Hydrazine alone does not significantly influence the potential of actively

!* eroding surfaces, but does appear to reduce the erosion-corrosion rate as a result of the increased I high temperature pH.

INTRODUCTION removed in the higher temperature sections of

1. In the temperature range 100 to 250 0 C, the boiler. This is to eliminate its possible

-carbon steel is highly susceptible to erosion- influence on corrosion in the 9CrlMo steel corrosion damage in deoxygenated boiler feed- evaporator and austenitic superheater sections.

water if fluid velocities and hence mass 3. Both the high and low level oxygen water transfer coefficients are high enough (ref. 1). chemistry regimes have been shown to be succes-However, oxygen in the feedwater has an inhibi- .sful in preventing erosion-corrosion damage ting effect on the erosion-corrosion process (ref. 2-5), but for the combined regime adopted (ref. 2 to 5), to the extent that when oxygen in the UK, which uses low oxygen levels, it is levels are high enough, the attack is completely important to define the limits of its applica-suppressed. However, the exact amount of bility, particularly since it involves dosing oxygen required, in general, to inhibit the excess hydrazine ultimately to remove the process under a given set of conditions has not oxygen which provides protection. Work has been established. therefore been carried out at CERL to establish

2. Various feedwater chemistries have been the oxygen concentrations required to inhibit developed in recent years which utilise ox-ygen erosion-corrosion under a variety of experi-dosing at some level which would be expected to mental conditions and in particular as a func-

'be successful in suppressing erosion-corrosion tion of the metal loss rate and hydrodynamic damage under single phase flow conditions. The conditions. In addition, it has sought to NOLC, N'eutral Oxygen Low Conductivity (ref. 6) establish the influence of hydrazine on the and Combined Oxygen-Armmonia (ref. 7) water process and the ability or oxygen to inhibit chemistry regimes employ relatively high levels erosion-corrosion in the presence of excess of oxygen in the feedwater, without or with nydrazine, particularly as a function of ammonia dosing respectively. Specifications temperature.

for the NOLC regime require >50 pg kg- 1 oxygen 4. The work has also made it possible to (ref. 6), whilst the combined regime has been establish the relationship between the high and optimised with oxygen levels in the range 150. low oxygen dosing regimes, with respect to to 300 pg kg- 1 and ammonia dosing to give a erosion-corrosion damage, and to explain why pH 2 5 0C between 8.0 and 8.5 (ref. 7). However, the incidence of damage can be rather variable a variation of the combined regime adopted for in plant operating uncier nominally deoxygenated CEGB gas cooled reactor once-through boilers AVT water chemistry, where feedwater oxygen \

employs much lower levels of oxygen dosing, levels are 1<0 ug kg 1 and !.ydrazine is dosed 15 Lug kg- 1 , with a pH25 0 C from ammonia >9.3. It as a scavenger~for residual oxygen.

5D

.1.

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SSOLUTIION BRIDGE , INTERNAL REFERENCEELECTRODE

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ELECTRICAL I CONNECTION I, I

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CLAMPING SU"FACE ..... 501.1 AND N .

SURFACEACTIVAT ,o" TEE MILDSTEEL P.T.F.E Ro:? ""

SLEEVES ENDCAP IINSULATED) 0 RIFICE"SPOT

. . ECMEN 1 2 .3 4 .5' 6. 7 ' 8~

IINCONEL IINSULAFEDI

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spcimn with Fig. :2 Tpicai.l mass transfer: coefficient

~ Fg.0rr1La~smb~~es ele~ct~rochemical. monitoring-0 ig-. .100 TIME. h TIME.I)

..- :* :Fi".  : . nfluence of oxv;"en,:on erosion-

3. -It Ituctce. of oxv gcn (,I- crosio~n- ait

...corros ion andý specimen potoijt ii L at corrosion and specimen potential 1_,. lzar.t 02 dose. 2 ,02.dose switch1di t t.0, dose.

ta 0 -dose inreased e to 2nd flow channeL.; .3, 9 0,;dos 5',

stopped.n 4, Stard r t2nd 0, doss e.

ýo se increased.

1 338

PAPER 96: WOOLSEY ET AL EXPERIMENTAL STUDIES potentials with respect to an internal Ag/AgCl/

5. The erosion-corrosion studies described 0.01 M KCI reference electrode. As shown in here were carried out using the CERL high Fig. 1, the potential was measured in the velocity isothermal water loop. Full details region of maximum mass transfer coefficient and, of the test loop have been given elsewhere therefore, of maximum erosion-corrosion loss, (ref. 1, 8). It incorporates four main speci- by inserting a PTFE tube through the specimen men flow channels, two in the main loop, and wall to form the solution bridge to the two in a secondary polishing loop. The rig is specimen. Measurements of the chloride concen-largely constructed from Type 316 stainless tration remaining in the reference electrode steel and designed to operate up to 3501C and after experiments lasting up to 1200 hours0.0139 days <br />0.333 hours <br />0.00198 weeks <br />4.566e-4 months <br /> 2

21.78 MX m- pressure. The experimental indicated substantial loss of electrolyte to programme has shown it to be capable of the recirculating water. Consequently, the operating for long periods with very precise electrochemical potentials measured do not control of both physical and chemical condi- strictly refer to a 0.01 N KCI reference, but tions. The control limits are indicated below: more closely to a saturated AgCl solution at the appropriate temperature. This does not Temperature, +/-1 0 C affect the general analysis of specimen Flow to test specimens, +/-1% up to 1031 kg behaviour, however, since it is based on large h-I potential shifts over relatively short periods pH of circulating water*, <+/-0.05 pH unit of time (a few hours), when the electrode would with NH 3 dosing have reached equilibrium with the environmental Conductivity of water after cation conditions.

exchange, <0.2 pS cm-I Dissolved active silica in recirculating CONDITIONS AND MONITORING OF WATER CHEMISTRY water, <6 og kg-i 9. The experiments described here were Dissolved Fe in circulating water*, <10l-g carried out in deoxygenated AVT feedwater, to kg-i which controlled levels of oxygen and hydrazine were then added. The pH of the recirculating

• Value depends on specific conditions of water was controlled with NH 3 . This was test, typically much lower values of dissolved effected both by dosing make-up water with the Fe are obtained. appropriate level of NH 3 and by controlled

6. For the present studies, test specimens of removal and release of NH3 by hydrogen and the type shown in Fig. 1 were used. These are ammonium ion form cation exchange resin beds in very similar in principle to those used the secondary water clean-up circuit.

previously in our experimental programme (ref. Experiments were conducted at various pHs in 1, 2), but have been modified to allow electro- the range 8.0 to 9.3, with the pH typically chemical monitoring of the specimen. The basic controlled to better than +/-0.05 pH units.

specimen design employs an inlet orifice, made However, during hydrazine dosing to the loop from erosion resistant material (Inconel 600), water pH control proved less satisfactory (see to produce highly turbulent conditions in the below).

mild steel tubing downstream, which in turn 10. The influence of oxygen and hydrazine on gives rise to the erosion-corrosion damage. erosion-corrosion behaviour was examined by The variation of mass transfer coefficient dosing either aerated water or N2 sparged downstream of an orifice is well characterised hydrazine solutions into the loop water approxi-(ref. 9, 10), as shown in Fig. 2, with the mately 1 m upstream of the test specimens. In maximum value being defined by the relationship: the case of hydrazine, the reagent rapidly recirculated around the loop and a stable Sh 0.276 Re67 Sc 33 ... () concentration was maintained at the test speci-max N mens by balancing the dose rate with hydrazine where Shmax maximum Sherwood number observed decomposition and removal on the ion exchange downstream of orifice columns. Unfortunately this displaced NH3 from ReN = orifice Reynolds number the ammoniated resin making pH control more Sc = Schmidt number difficult, particularly during periods when it was necessary to change the N2 H4 level in the The mass transfer coefficient, K. is expressed water.

in terms of the Sherwood number by the relation-

11. In the case of oxygen dosing into the ship Sh = KD/D, where D = duct diameter and D =

loop, when it had previously been operating diffusion coefficient.

under deoxygenated (reducing) conditions for

7. The erosion-corrosion loss in the region of some time, magnetite on the loop surfaces had a the post orifice maximum was monitored in-situ substantial capacity for removing oxygen in the by observing the activity loss from specimens recirculating water. As a result of this 02 which had been surface activated with 5 6 Co as 1gettering', it was usually necessary to run at indicated in Fig. 1. Full details of the a constant 02 dose level for some time before technique used have been given elsewhere (ref.

steady oxygen levels were established at the 11). The loss sensitivity in the present inlet to the test specimens. This also ensured studies was better than +/-0.15 pm, allowing very equilibration and negligible 02 loss in the accurate determination of specimen response to sample lines, which were located approximately changes in the water chemistry and in particular 15 cm upstream of ihe specimens. Valves in the to the oxygen dose level.

EROSION-CORROSION AND INHIBITORS mixing of the dose and recirculating water. more difficult. Lnder these circum-After prolonged periods of 0-2 dosing to the sLances, it was necessary to use the theoreti-around loop water, it was found to recirculate cal oxygen level derived from the dost rate to the loop and the 0) level at the test specimens gyive an upper limit for the oxygen level at thie rose cumulatively, as indicated in Fig. 3. test specimen. While this allowed demonstra-

12. Because of the difficulties of sampling rion of effects due to low levels of 02, and measuring 02 at the very low levels equivalent to those observed at lower tempera-involved in the present work, great care was ture, it precluded accurate quantitative taken to ensure the accuracy of such measure- assessment. Similarly, it was not possible to ments by multiple method determination at measure oxygen concentrations in the presence various points in the loop circuit. Samples of hydrazine at these temperatures and data were drawn continuously from a sampling point at again had to be related to the theoretical 0O the inlet to the test specimen in the flow dose. At 1500C and below, however, the channel being dosed and from an equivalent hydrazine-ox.gen reaction was sufficiently slow point in the parallel flow channel ahead of a to allow measurement of 02 in the presence of second test specimen. This provided a check on hydrazine. In both cases it was possible to oxygen recirculation arounad the loop and demonstrate clearly the effects of oxygen in allowed 'differential' experiments to be the presence of excess* hydrazine.

conducted where erosion-corrosion was main- 16. Hydrazine in loop water was monitored tained in the undosed flow channel, but continuously using the p-dimethylamino-inhibited in the dosed one. The 0, concentra- benzaldehyde hydrazone auto-analyser method tion ia the recirculating water was also (Technicon Auto Analyser Industrial Method N:o.

monitored downstream of the ion exchange column 147-71WM, 1973). Hydrogen in tne loop water in the polishing loop by batch analysis and on was determined by gas chromatography of the a continuous basis in some experiments. dissolved gases; which had been stripped from

13. The ox-ygen levels quoted in the present the sample water by diffusion through a paper were measured using an Orbisphere model silicone rubber membrane into a helium carrier 2713 membrane polarographic 02 monitor. gas (ref. 13). It was not possible to control Measurements were normally made with a total hydrogen in the loop water and its concentra-sample flow rate of around 80 ml min" 1 and a tion increased.progressively with temperature flow of 9 ml min-I through the monitor itself. as a result of the increased corrosion of steel With flow rates of this order and strenuous surfaces in the loop (from around 15 pg kg- 1 at efforts to ensure minimum 02 ingress on the low 115 0 C to 90 Pg kg-! at 210 0 C).

pressure side of the sampling system, measured 02 levels in He sparged 'blank' water wTre .RESULTS .AND DISCUSSION typically in the range 0.2 to 0.3 ug kg- Influence of Ox-egen on Erosion-Corrosion Similar values were obtained from loop water 17. Fig. 3 shows the influence of a progres-after operation under deoxygenated conditions sively increasing 02 dose on a specimen under-for a few days. With lower sample flow raLes going rapid erosion-corrosion loss (0.99 mm slightly higher oxygen levels were observed. year-1) at i150C and pH 9.1. The 02 level was Oxygen measurements obtained using the contin- progressively increased to 2.1 g kg-I without uous autoanalyser version of the leuco-methvlene any noticeable effect on the erosion-corrosion blue method (ref. 12) were in good agreement rate over a period of about 70 hours8.101852e-4 days <br />0.0194 hours <br />1.157407e-4 weeks <br />2.6635e-5 months <br />. However, with those obtained using the Orbisohere the specimen showed a progressive shift to more instrument and indicated the absolute values to negative potentials with increasing oxygen be accurate to about t0.5 i.g kg- 1 in the O. to level over this range. This effect has been 10 gg kg-I range., noted previously at low tomperature (ref. 2),

14. As noted earlier, the absolute 02 levels but its origin is unclear at present.

measured may be unrepresentative of that Inreasing the 09 concentration to 3.8 g kg-I reaching the specin:. nif significant,:-vL.,'. can be seen to have causeda :reduction in the sumption occurs within tie sample lines. As. a erosion-corroston rate over :a period of 2.

rule, therefore, several hours equilibration hours and shifted the spec imcen potential more were allowed at any given oxygen dose level to positive a;gain. In view of the continuin'-

ensure that the uo level determined was indeed positive drift of the specimen potential at the representativ.'e of that reaching the specimen. end of this period, it is possihie tiiat furth,.r Typica!ly, however, when 02 dose levels were exposure at this oxygcn *cocentraition wo-uld have' changed, the majority of the increment was seen stopped the erosion-corrosion loss eventuallv.

within an hout or so. In those cases wheti? 09 How-ever, increasing the concentration to no 1or.,

recirculation around the loop could be demon- than 6.2 :!g 'g-1 caused the.potentiai to shfi L strated not to have occurred, the oxygen levels sharply more positive and slopped furthCer were cross checked by comparison with the erosion-corrosion loss. Oxygen recirt-clat ion theoretical values expected from the 0- dose around the loop prevented more precise control rate. Fig. 3 shows a good example of such a of the 0() concentration and hence more accurate comparison for 09 dosing at 115 0 C. Only at defi:n tion of the concentration required to the end of the dosing per~iod is 02 recircula- inhibit attack.

tion evident and prior to this agreement between 18. Fig.. 4 shows similar data for 09 inhibition measured and theoretical 02 levels is good. of erosion-corrosion at 1500C and at a rather

15. At temperatures of 1800C and above, lower pH, around 7.8. The low pH adopted in increased 02 consumption by loop surfaces and this case was to ensure high erosion-corrosion

PAPER 96: WOOLSEY ET AL.

d dose starting- after 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> (4.9 .g kg- 1 ) also consistent with the rate 'of oxygen reduc-immediately ý:caused& the ongoing erosion-corrosion tion being controlled by the rate of oxygen loss of' 1.10 mm year- 1 to be inhibited. mass transfer to the specimen surface. A Reduction of. the oxygen concentration to reasonable initial approach 'ýto assessing the around 3.5 1g..kg-l continued to inhibit the oxygen concentration necessary to inhibit.any process, and.to maintain the much more positive given erosion-corrosion rate is,!"therefore, to specimen.potential. However, reducing the compare the rate under fully deoxygerated oxygen concentration to 3.2 ;:g kg-I 'allowed conditions with the rate of oxygen mass erosion-corrosion to reinitiate rapidly, at a transfer to the specimen surface required to rate similar to that seen previously. At the inhibit the process. This is, time, the specimen potential was seen to shift to equate the anodic reaction ratewith the equivalentr sharply:.negative to a. Value similar to that cathodic reaction (4), which would have been.

observed prior to 02 dosing. Subsequently, the required to balance it if the crosion-corrosion erosion-corrosion rate increased to 1.58 rmm loss had continued unaffected. i.e.

year-I and continued at this value during "

oxygen -dosing.until. the 09....concentration was.. 2-2 . 'rs . Corrsio " Rt . . (5) raised above 6.5 pg kg' 1 . Again,.,h'c posi tive where KO* = local oxyvgen mis transfer shift in specimen potential and cessation Of ccoefficient f

erosion-corrosion loss was almost immediate on . _102] concentratiun of oxygen in solutio

- raising the con~centration above the threshold. required, to ihibit.the ero'sion-  :?

-P .... t-_ af trho rtvnpe. rc-zCri hr,.

I._ ... ..

- ;have. , been;repeated many' times at." these two '. ... " density of wter. .

..... '.:,i  : except temperatures :t~~~~~~~~~~i~,a1

'h'e with.  :'"tireshoid essentially for thed inhibtosaue resul t f IIf the h e~t~si relationship ie:ieiaih'()5ii; given in equation (5) holds' eep ta th0...df ii tthen plots of the oxygen threshold Yersus erosion-corrosion varied with the loss rate and (Erosion-Corrosion 'Rate)/owKO.should.give.a mass :transfer coefficient to the specimen surface. .- At-higher temperatures.,ý up, to 250 o C, straight line of. slope 0.,285, defined/ by.the'.

equivalent weights of Fe and :02in,'.the corro- . L the.r'esults were similar,.,but. ob'taining an. i r '

o. x:yge.n' threshold'yas -more-difficult due to 'the 23. Fig. 5 and 6 s .ow,`plots'

f t*he i:,-inf luence di-fficulties,*,,in. oxygen .,determination and the. of oxygen on erosion-corrosion- rate*deric.i*d . .J low, erosion-corrosoion. rates encountered, 20 oIismpotant"o.note:

.that the oxygen r an. es were dosing experiments::at-'1l1OC and 150 0 C i-ere The mass transfer coefficients for-'ox

.carr.iedoUt.with ,10 t20. g kg-. 1 dissolved

• calculated using the expression givenin-equation (1), taking' the diffusion oef:fin ts . ....

hydrogen in -the loop water. This represents a. (K as -

.. : large-excess of over the 02' for oxygen (K.)as.8.8 x. lO-9.m 2  :-

• - ..:/s~d '. t0.ihhbi H.. . concentrat s an I.27 x .10ý8 m -sýl at 1150.l .ah'd 150 0. C, .sl and:

eresion:-corrosion,..typically 2 .. ,. .  :

' usad toi.nhibid~erosion-corrithn.ithtreqicaley an respectively (ref. 15) .. Other. aqueou*s c6ns tants ordd-r of imagnitude greater.:than ,that requiredweetknrosadr'seaabls Were taken "from s tand~ar d-.,s~te-am:.,*a'i6.:!,.! a Sic~ .";. '. . .,-:.

.- .. to combine with the oxygenvia :the formal the threshold itself is not'.as.readily 'defined

. reaction: -. .. , , . ' as the alternatives.: where erosion-corrosion H-.. H . 2 ."20 " - - ' '. .. (2) continues unaffected :or. is,, com plel'y--ifnhibied.

..-: . .. :Neverthe less-:, it was-still: the,-oxygenhpresent

-' ~Figs.

basigs, 5ad6 are. cons trucitedon thlater..

the trel bens tr edboundayine...

which . contro'lled'.the%

.. *:;..:. .,... ... . :. specimen. electrochemical , ,.. . - ' ,.,. between the two zonesý' ::i As A expected -there'.is..a-.".  !

potenrtial and.erosion-corrosion, behaviour. This t . zones . e

- wasas

" found a"t lyt

• up to . band of uncertainty: associated[-wit:.t. there is a

. his,,;I.-,.

" "" "; - .- defined by the half closed'symbols ::anhd' the

• - (up tO-"' 2 !:: orders "of' : ., magnitude)'.' It ' 'should also:" *-

,. :':i . , ".*, ' 24. At bDoth -1150:. and.:  :* Ot*,.n r' : iDs- :"clearly.. " an.. . ... .

be noted- that these H2 levelsare of course .

• 24. A an l5.,t..,e is. c an -

higher. than those' normally -in encountered oxygen concentration, treshold below.which ..

.. o..er emsl boiler ."erosion-corrosion is unaffected ,

daoo~e- .eedWys whi.chn.

21'. eessesthe process is-:inhi'bited-,, which -can- e~ ýdefined" Therapidshift in e lectrochemical poten- in termsof.thepre-.xistii:geros*on

. .. .. th f: corr.si.n.ate-

'tialP to much ,or pstive pot~enti.als and,'the; hco` s st n ý~r e:..r' to.h o nf*

adte.ae.foye ns.tase h he 1osion- corrosion l& 9.cil"Ocen~tra tion!:.i:pr ce~ss surface..

S abv 1a treh s:" - However,. the-slope of the 'threshold,`:

~atheshpd 2cocetrtin sline is lower than that predicted~by:`equation consi,"enth a switch in, the-,,cathodic reac- (5), by a factor of.4:for. correlation, at t on df the.,dorrosionipods -'ro hyroe evolution to -oxygenreduction. 1fi500C.' whi~chhrepresents 1.the be-tter' bte data set.

Tha t: is, Iiimrn tpit

.. t,.. ha h it. simportarft: to."oit o . howyr: htt From 2H+ 2e - . 2 - . . ' .- .... (3) experimentally determined erosion-corrosion . -

To 102 + "20+ 2e - -. 20H  : " (4) rate. is 'equated. to a theoreticalty In the'

• case ., v* ..'-.- i"- e-o one c"derived rate of. xygen,:mass ,ýtransfer. .' For many

-of.-.active

"...,.* .... .. erosion-corrosion,. ,, .. *. the. ... : * . : corrosion.,procesSes,.:ý.sucn.,:Ciose:*,a,,

corso pc. s..h close ...... ,r.. re~emen . n'. :*.:: ':i..,:.:

ca.hudic. hydrogen evolutio. . ..- r.action ietween

.3 'experiment and, balanced by a' equalanda.opposite anodi'c one re .d .. 'i.-,. woudi bcb.-,

S" - - -  :- .to. -'..* tleading

• he* 'ULL diSsolution

.*:,'..,* ::*  :;: of . .iron .": as" Fe-, ... L 'analysisered suff-icient ,6 :However-,:.e~xa~mi:nati.on

.to .t-e- 'the ,.nfir :o .. i.ne.tca": - 1* .',":.*

, species.  :. The

, .*'*-.* ; latter

• -.*  :. is" general-ly

.'

• agreed'

.'_

• to *haly.is * .errors: inývo Hwvr . vedl..in,.:ne. 'e.amination

-e s't ma t.1on' of orf the'"pssibl ox en occur via  ::-- reductive the

• :;' :*::.- "' :;-::; :::.kt  ;;. dissoolutoion

.

_.:: * : of : thero * ..- "mass, i ineros~ronri-e.t.ai.

.. .crtos~ion: ofoye trans,ifer..and rat i magnetite corrosion film fLormed on the metal mass transfer and erosion-corrosion

-.--surce - re..-. 2)'. .. _n' rat. .

.. indicates: that the *eviation.of thr slope ,of- ,

.- -'* - 22. The" specimen electrochernica behaviouris the threshold lines from'the.predicted 0.285 is real. Thus rather less. oxyge .is l o

OSION-CORROSIQN AND INHIBITORS 3 4 5 6 0

300 X 6 m z

a 200 0 4

lc, 100 N 2 H4 2

"0 o 3.4 2 3 4 5 6 Z-40

-Soor LOSS RATE.

0 49 /

0.061 mmy'

-goo 11 ,

48 POTENTAL... 'A.. ' IL V7.;

- ~'Y-> ,

TIME. h Fig 8 ' Influence of oxygen in the presence of hydrazine on erosion-

- corrosion and specimen potential at 210 C.

"N'4:A *, 2, N2 H4 dose increased. 3, Start 0 2 /N2H4 dose.

,4 *I. increased. 6, 02 dose stopped.

'i A**!',*t *..

"250 LOSS RA' 42 1

1.37m.Y

_,D-LOTS 'RATE' 0.40 mmAy' 400 RATE >

n -I 16000>

150 250 350' TIME.-h 320 *360~ 400 "40 Fig. 10 Effect of hydrazine on erosion-ef hydrazned ri erosion- corrosion' ,and specirmen.i*potential in .

corro.si "on:and .sjcimeif ý'poten'tial- due absence of- oxygen' at' 1)80C C 0 1, Start N2H4 dose. 2, Dose increased.

to, r moval of oxygen.,, at 100 C

,~*p -

LL~'p,.,3 r~U~'~4# ~ *M ~ i-  :. " , .

RkOSION.CORk'OSION AN) INHJHI1TORS r-equired to inhibit erosion-corrosion than Fig. 7. This represents th 2 upper limit of 02 gould be predicted by equating the loss rate to which could have been present at the specimen, 1

-lherate of oxygen mass transfer to the surface. but even these modest levels (<7 ng kg- ) were the latter does appear to represent an upper sufficient to inhibit an ongoint erosion-Limit to the amount required for inhibition corrosion rate of 0.79 mm year in the though. presence of around 180 ug kg- 1 N2 H4 . Fig. 8

?5. Whether the 02 threshold for inhibition shows that oxygen is equally effective at 210 0 C eases with increasing temperature as for inhibiting erosion-corrosion in the L,.uicated by Figs. 5 and 6 is uncertain. The presence of around 300 ,igkg-I N2 H4 , although 0 the loss rates were much lower at this lata at 1150 and 150 C can be treated as a

ingle set, but there is then greater scatter temperature. In both cases there was also a

)f the threshold values. It may at first seem large excess of hydrogen present over the

urprising that the 02 thresholds are less than oxygen concentration (H 2 ' 90 og kg- 1 at 210 0 C).

hose predicted by the mass transfer analysis, It is clear, therefore, that low levels of

,ut it appears tobe consistentwith themechanism oxygen control the incidence of erosion-

)roposed for the erosion-corrosion process by corrosion even in the presence of huge excesses

he present authors (ref. 1, 2). In effect the of the two common reducing agents likely to be

)rocess is self accelerating, due to the need present in boiler feedwater, namely H? and N2 H4 ,

o evolve hydrogen at progressively more and our data shows this to be the case up to Legative potentials in order to match the 250 0 C.

Lnodic-dissolution rate. This, in turn, 28. Since oxygen is the potential controlling

• aises the solubility of the magnetite corro- species with carbon steel up to 2500C, it is

ion film, allowing even higher mass eransfer likely that other corrosion or oxide deposition imited dissolution rates. When oxygen reduc- processes are influenced by very low levels of ion starts to compete with hydrogen evolution oxygen in the feedwater, even though excess H2

.s the cathodic reaction, the potential will or N2 H4 may be present. Of course, these tart to shift in the positive direction, reducing agents will remove'0 2 from the feed-educing the solubility of the magnetite film. water given sufficient time, but the reaction

'his, in turn, will lead to further reductions kinetics are sufficiently slow, particularly at n the mass transfer limited dissolution the lower temperature end of our investigations, rocess and, as the oxygen level is increased that 02 can penetrate many metres through the urther, to a very sharply reducing erosion- feed system and into the boiler. It is, orrosion loss rate. Our observation of a therefore, clear why haematite is frequently elatively narrow range of oxygen concentra- observed in the low temperature (<2500C) parts ions over which the loss rates are reduced, of power plant boiler and feed systems, even ut which do not completely inhibit the with nominally deoxygenated feedwater and added

-ncess, appears to match this view of the hydrazine. The data of Ribon and Berge (ref.

.bition mechanism. Further analysis of this 15) provide a good example of such behaviour in spect of-erosion-corrosion behaviour is under a conventiqn-al boiler operating with a avestigation. deoxygenated AVT feedwater chemistry with

26. As drawn, Figs. 5 and 6 show a positive additioft of hydrazine. Up to 265 0 C, haematite atercept of 1.5 Wg kg- 1 for the .02 threshold was the major oxide phase observed in corrosion t zero erosion-corrosion rate. Equation (5) product samples taken from the boiler system.

redicts that the intercept should be zero. Above this temperature magnetite predominated.

art of this offset may be accounted for by the It is also clear'why zones of active erosion-

• sitive 'blank' oxygens measured, typically corrosion damage, where the metal surface is

.2 to 0.3 jig kg-I, and by the difficulties of covered with magnetite, can be surrounded by

curate measurements at such very low oxygen adjacent ones covered by haematite. While rncentrations. However, the data do not oxygen levels are insufficient to inhibit damage

-eclude the possibility that the threshold in the highly turbulent regions, they are

.ses more rapidly at these very low 02 sufficient to shift the surface potential to

)ncentrations, with a rather lower intercept more positive values in areas of lower mass tan that indicated. This would be consistent transfer and, hence, to lead to the formation

.th the view that for very low erosion- of haematite. Similarly, some boiler feed

)rrosion rates, where the self accelerating systems operating with nominally 'deoxygenated'

!chanism of the process is much less feedwater may suffer serious erosion-ocorrosion iportant, the threshold approximates more problems, whilst others which are apparently

.osely to that given by equation (5). similar; but in reality have slightly higher feedwater ox-ygens, show none.

fluence of Oxygen in the Presence of Hydrazine 29. When reaction times are long enough, Fig.

7. As noted earlier, oxygen is effective in 9 shows that hydrazine will efficiently remove hibiting erosion-corrosion in the presence of .02 at low levels (<5 pg kg- 1 ) and allow

.cess hydrogen. Fig. 7 shows the influence of erosion-corrosion to reinitiate rapidly.

ygen in the presence of a vast excess of drazine at 180 0 C. .It was not possible to Direct Influence of Hydrazine on Erosion-asure the oxygen level reaching the specimen, Corrosion

-. to the reaction with hydrazine in the rig 30. Fig. 10 shows the influence of hy'drazine

'ween dosing and-sampling point) and down on erosion-ocorrosion in the absence of oxygen the sample line. Consequently. the (<0.5 .g kg- 1 ) at 180 0 C and essentially

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NEC-RH_04 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 In the Matter of Docket No. 50-271-LR ENTERGY NUCLEAR VERMONT YANKEE, LLC, and ASLBP No. 06-849-03-LR ENTERGY NUCLEAR OPERATIONS, INC.

June 20, 2006 (Vermont Yankee Nuclear Power Station)

PRE-FILED REBUTTAL TESTIMONY OF DR. RUDOLF HAUSLER REGARDING NEC CONTENTION 4 Qi. Please state your name.

Al. My name is Rudolf Hausler.

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 filed by Entergy and the NRC Staff concerning NEC's Contention 4? -

A3. Yes. I have reviewed the section of Entergy's Initial Statement of Position on New England Coalition Contentions (May 13, 2008) that concerns NEC's Contention 4 and all Exhibits thereto, and the Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4 - Flow-Accelerated Corrosion (May 12, 2008). I have also reviewed the section of the NRC Staff Initial Statement of Position on NEC Contentions 2A, 2B, 3, and 4 that

concerns NEC's Contention 4 and all exhibits thereto, and the Affidavit of Kaihwa R. Hsu and Jonathan G. Rowley Concerning NEC Contention 4 (Flow-Accelerated Corrosion) (May 13, 2008).

Q5. Did you prepare a report of your evaluation of the Entergy and NRC Staff Initial Statements of Position and direct testimony on NEC's-Contention 4?

A5. Yes, I did. This report is-filed with this rebuttal testimony as Exhibit NEC-RH-05.

Q6. Please briefly summarize your conclusions as stated in your report filed with this testimony as Exhibit NEC-RH_05, and the bases for your conclusions.

A6. Entergy witness Dr. Horowitz has testified that it is not necessary to recalibrate or "benchmark" the Checworks model with plant inspection data following a twenty percent power uprate. Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4

- Flow-Accelerated Corrosion at A33, 34. Rather, Dr. Horowitz contends that the only update to the Checworks model that is necessary follo~ving a twenty percent power uprate is the input of new values for flow rate and temperature into the model. Horowitz at A33, 34. Dr. Horowitz bases these assertions on his view that "[flow-accelerated corrosion (FAC)] wear rates vary roughly with velocity and do not increase with velocity in [a] non-linear (exponential) manner...

.", Horowitz at A49, and his belief that the Checworks model can accurately predict any variations in FAC rates related to geometric features. Dr. Horowitz contends that the Checworks model accounts for any localized variations in FAC associated with geometric features through the use of " 'geometric factors' to relate the maximum degradation occurring in a component, such as an elbow, to the degradation predicted to occur in a straight pipe." Horowitz at A47, 48.

As explained in detail in my report, Exhibit NEC-RI-05, I agree that the rate of FAC generally varies almost linearly with fluid velocity; however, this linearrelationship transitions 2"

to an exponential one as the local turbulence becomes such that erosional features become manifest. Whether such transition actually occurs when flow velocity increases following a power uprate must be determined experimentally. I do not agree that the Checworks model, or any model, can fully account for variations in the rate of FAC due to geometric features and discontinuities. Some things cannot be specified. For example, the internal residual weld bead from the root pass may be 1/8 inch high in one case, and 1/4 inch high in another case. The upstream and downstream turbulence surrounding the weld bead will be more severe in the latter case, and a power uprate may disproportionately affect the flow over the larger bead.

Dr. Horowitz defines FAC as corrosion in proportion to the flow rate, and excludes from the definition of FAC the more severe forms of localized corrosion - erosion-corrosion, impingement and.cavitation. See, Horowitz at A46. This definition of FAC is entirely arbitrary.

Erosion-corrosion, impingement and cavitation are extensions of FAC as the local flow intensity due to turbulence increases. The transition from one to the others is continuous and difficult to identify. If Checworks is unable to predict these more severe forms of localized corrosion related to high flow rates, which can particularly occur after a power uprate, then this is a serious shortcoming of the model and its application.

The accuracy of Checworks has been said to be within +/- 50%. This statement is based on an erroneous interpretation of the graphic representation of predicted vs. measured wear.

Actually, the accuracy is within ,a factor of 2 - the measured wear rates range from twice the prediction to half the prediction. A factor-of-two difference between measured and predicted corrosion [or corrosion rate] can be quite significant with respect to selecting a particular item (line) for inspection during a refueling outage. Indeed, the "EPRI Checworks Wear Rate 3

Analysis Results for Cycle 22B," Exhibit E-4-29, shows that the time predicted to reach the critical minimum wall thickness in a majority of cases is many years negative. This means that the item should have failed a long time ago. The remaining time to failure might just as readily be grossly overestimated. But one will never know unless the proper inspections are performed and the model is recalibrated.

Q7. Does this conclude your rebuttal testimony regarding NEC's Contention 4 at this time?

A7. Yes.

4

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

Rudolf Ha e, h AtAý, ý, Texas, this

• day of May, 2008 personally appeared Rudolf ausle and having subscribed his name acknowledges his signature to be his free act and deed.

Before me:

My Commission Expires ~ ~ ~ ~

,J~ENNIFER NoteJULANA PEREZ Public oFTEAS MySTATE My COmm. Exp. August 22, 2011

NEC-RH_05 CORRO-CONSULTA Rudolf H. Hausler 8081 Diane Drive Kaufman, TX 75142 Tel: 972 962 8287 Mobile 972 824 5871 Fax.' 972 932 3947 Flow Assisted Corrosion (FAC) and Flow Induced Localized Corrosion:

Comparison and Discussion Summary 0 The'computer model Checworks, used to manage aging of hot high pressure water and steam carbon steel lines was designed for Flow Assisted Corrosion (FAC) phenomena. Erosion Corrosion, Impingement and Cavitation are expressly excluded as unrelated to FAC. It is shown that the latter three corrosion phenomena are extensions of FAC as the local flow intensity due to turbulence increases. The transition from one to theothers is continuous and difficult to identify. FAC therefore is only one manifestation of Flow Induced Localized Corrosion (FILC).

• The localized corrosion rate under the umbrella of FAC varies, per definition, almost linearly with fluid velocity; however, this linear relationship transitions into an exponential one as the local turbulence becomes such that erosional features become manifest. Whether such transition actually occurs following a power upgrade (PU) must be determined experimentally. It cannot be estimated from within Checworks.

0 It has been stated that "the algorithms used to predict the FAC wear rate are based on extensive laboratory and plant data. This assures that the FAC wear rates predicted by Checworks are accurate." This accuracy is said to be within +/- 50%.

However, this statement is based on an erroneous interpretation of the graphic representation of predicted vs. measured wear. Actually, the accuracy is within a factor 2. The measured wear ranges from twice the predicted to half the prediction.

• Partial review of the result from the pipe inspections using Checworks in 2003 and 2006 shows significant unexplained discrepancies.

I. Introduction The direct testimony by Dr. Jeffrey S. Horowitz and Dr. James C. Fitzpatrick') with regards to NEC Contention 4 - Flow Accelerated Corrosion has raised a number of questions, which are being discus'sed below:

1) Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4 -Flow-Accelerated Corrosion, May 12, 2008.

6/2/2008 I of 12 RHH Rebuttal

" Is the model called Checworks based on sufficiently broad scientific understanding of all pertinent corrosion phenomena?

• Is the model called Checworks broad enough to capture alJ flow-assisted corrosion phenomena, or more broadly Flow Induced Localized Corrosion (FILC) in general?

" Is the model called Checworks suitable to manage aging of the hot water and steam piping system at the Vermont Yankee Power Plant?

" Is the predictive power of the model called Checworks within a probability range to prevent unforeseen catastrophic failure?

• Does the model called Cheeworks require extensive recalibration?

In order to tackle some of these questions I shall discuss some of the pertinent background and try to unravel the conundrum of language, which has, it seems to me, caused some misunderstandings if not outright confusion.

II. Background

1. The Chemical Nature of the Passive Steel Surface It is well established that under certain conditions corrosion occurs in carbon steel hot water pipes in nuclear (and fossil) power generation plants. The chemical nature of this phenomenon is straightforward: iron reacts with water to form iron ions and hydrogen. The reaction is thermodynamically favored.2 *

',However, the physicochemical nature of the processes occurring in conjunction with the oxidation of iron, is infinitely more complex and, although investigated in great detail,3' generally not easily understood.

Ferrous (Fe+2) or ferric (Fe+3) ions are not stable by themselves at the prevailing temperatures (-300 OF) at a neutral or slightly alkaline pH. Either ion will react with water and form hydroxides, oxy-hydroxides, or oxides. The reaction occurs on the surface of the metal where an oxide layer forms, which slows the corrosion reaction or prevents it from occurring altogether. The phenomenon is called passivation and makes it possible for iron, steels, or stainless steels to be used as industrial materials to begin with. At the temperatures in question the passive layer is a thin crystalline "coating" of magnetite on the surface of the steel, Fe 30 4, a mineral also found in nature. Fe3 O4 is a combination compound formed from FeO and Fe 20 3, generically called a Spinell. Because of the nature .ofthe Spinell-type oxide combining in essence a two-valent iron with a three-valent iron ion, magnetite is electrically conductive and 2)NEC-RH_03: R. H. Hausler, Discussion of the Empirical Modeling of Flow-Induced Localized Corrosion of Steel under High Shear Stress, April 25, 2008, pg 3.

3) See ACS Symposium Series Vol. 89 (1982), Editors: G.R. Brubaker, and P.B. Phipps, Chapters by Maurice Cohen, Vlasta Brusic, and J.E. Draly.

6/2/2008 2 of 12 RHH Rebuttdi

forms a contiguous thin, non-porous albeit crystalline layer on the surface of the metal.

2. The Physical Nature of the Passive Magnetite Layer

.Steel in the passive state will not corrode or only at extremely slow rates (10O' to 10-2 mpy). The question then is: What makes iron in the passive state corrode? Why do hot water or steam pipes in nuclear power generating units fail due to corrosion? Why are the failures predominantly local while the rest of the structure remains intact and passive for many years?

Any phenomenon that can destroy the protectiveness of the passive layer or assist in removing the passive layer will cause the steel to corrode at rates 103 to 104 times faster, i.e. at corrosion rates observed in the power plants.

What are these phenomena? In order to better understand this one needs to understand that magnetite is an electronic conductor. It can pass electrons from the metal side to the water-side where they can be consumed by an electrochemnical reaction.

Magnetite, however, cannot conduct ions. Neither iron ions nor oxide ions are mobile in magnetite. 4 ) The phenomena that destroy the protectiveness of the passive layer are essentially chemical in nature, but may, however, be assisted by physical effects.

For instance, chlorides in the water will convert magnetite to iron-oxy-hydroxy-chlorides, (various modifications thereof), which are much more soluble than 5

magnetite and also can conduct ions. The result is that the passivity has been lost. )

This is the mechanism that prevails in the crevices of the steam generators of PWR's and is the primary cause of denting.

Magnetite has a finite, albeit very small, solubility in hot water. The dissolution of minerals in water is aided by agitation, i.e. forced convection. Salt (sodium chloride),

e.g., will not dissolve in stagnant water, but will readily go into solution when the solution is agitated. The dissolution process will stop when the solution is saturated, with the salt. This is in essence how the corrosion process of steel in hot water has to be visualized. I have tried to sketch the physical reality as simplified as reasonably permissible in Figure 1.6)The water layer close to the magnetite surface is saturated*

with iron oxide in equilibrium with the magnetite layer. The iron concentration in the bulk water phase is practically zero. Therefore a concentration gradient develops from 4)Because of the physical nature of magnetite iron, it is also called a valve-metal (in analogy to aluminum).

However, the magnetite layer is distinctly different from such corrosion product layers as iron sulfide or iron carbonate. iron sulfide, for instance, is a p-type conductor based on iron ion vacancy mobility. This layer therefore can grow from the solution side, a process not possible with magnetite, because magnetite cannot conduct iron or oxide ions.

5) The phenomenon is well known in the nuclear industry since it is the primary cause of "denting" observed in stream generators of PWRs.

6) Note that this Figure and the mechanism derived therefrom essentially mirror Dr. Hopenfeld's explanations: NECJH_36 at pg 3 and Fig. 1.

6/2/2008 3 of 12 Rebuttal 6/2/2083f12RHH

the magnetite surface across the stagnant boundary layer. The solubility of iron (from magnetite) is very, very low. Hence, the mass transfer of iron ions across the stagnant water layer near the magnetite surface, which occurs by diffusion and is controlled by the concentration gradient, is very low as well. The thickness of the stagnant layer, which is infinite if there is no flow, is reduced as flow over the surface increases.

Therefore,, as the flow [rate] over the surface increases, the stagnant layer (also called the laminar boundary layer or the diffusion layer) is reduced in thickness, the diffusion rate increases, and hence the dissolution rate of the passive layer. The thickness of the passive layer (which is very small to begin with) becomes a steady state value when its formation rate (the corrosion rate) equals the removal rate (dissolution and mass transfer rate). The latter is controlled by the flow rate.

Therefore, this type of corrosion has been termed Flow 'Assisted Corrosion (FAC). However, as we will see below, the fact that the creators of Checworks have decided that the main characteristic of FAC is its proportionality to the flow rate is entirely arbitrary.

3. The various forms of FAC If the flow (laminar or turbulent 7)) is strictly uniform over the entire surface area of interest then the entire area will corrode uniformly and wall thickness loss is uniform.

However, at the prevailing flow rates (24 ft/sec in many cases) the flow pattern is not uniform because of the non-uniformity of the cross sections of the flow channels. In particular, where flow upsets are built into the system, such as orifice plates, flanges, etc., localized turbulences occur which are much more intensive than are normally described by general flow equations. The engineering approach is to characterize the flow at such flow disturbances by means of differential pressure drop and an average shear stress occurring at the disturbance. However, the difficulty is that the localized shear stress within the turbulence cannot be captured in this manner and is in general orders of magnitude higher than the average numbers 8) would indicate.

The different paradigms can perhaps be explained by means of Figure 2 (below). Any geometric feature in a flow channel (pipe for instance) that reduces or expands the

[hydraulic]-diameter, or changes the direction of flow, creates a flow disturbance (including sensors inserted into the pipe for temperature, pressure or other parameters). This means that the flow regime, which in the straight sections of the pipe may be fully developed laminar or turbulent flow changes to one, that also incorporates local turbulences (eddies). This leads to locally enhanced shear stress and hence enhanced mass transfer and therefore locally increased corrosion.

Just as flow in a pipe can be characterized by the pressure gradient, flow upsets, such as are shown in Figure 1, can be characterized by an average pressure drop (and 7)For definition of turbulence in the general sense see Figure 2 Ref. 2.

8)c.f. for instance Figures 4 and 5 of Ref. 2 6/2/2008 4 of 12 RHH Rebuttal

hence an increased average shear stress. Engineering practice has done this for a large number of flow features (elbows, orifices, t's, etc.) of varying diameter for the purpose of being able to calculate the pressure drop along complex piping systems.

Checworks now uses these flow features (56 of them) to record and classify observed and measured corrosion rates in a data base along with a host of environmental parameters (pressure, temperature, water chemistry, etc), physical parameters (flow rates, metallurgical features, and many more), as well as boundary conditions such as minimum critical wall thickness etc. Once the database has been established, statistical routines, such as multiple linear correlation, can be applied in order to extract explicitly and quantitatively the dependence of corrosion rate within the parameter space. The resulting correlations can then be used to predict corrosion rates for individual situations, which can be characterized well enough to be accommodated in the database (one of the 56 features). Certain theoretical concepts are combined with the multiple correlation, 9) in particular the notion that corrosion increases proportionately with velocity.

Therefore, there are two major principles imbedded in Checworks:

• Flow features have been standardized in traditional engineering fashion (an elbow is always an elbow, an orifice is always an orifice, etc.). However, for certain features that could not be done: a weld is not always a weld, and a flange is )not always a flange (see discussion below).

• A linear (or near linear) relationship between flow rate and mass transfer, i.e.

corrosion rate, has been built into Checworks. It is for this reason that Dr.

Horowitz indicates that certain failures, which had been identified as being caused by erosion or impingement could not have been predicted by Checworks, but that this lack of prediction does not invalidate the predictive value of Checworks.

It has been shown theoretically that the shear stress governs the mass transfer.

Accepting this one can readily understand that at locations of high shear stress the magnetite dissolution is high and therefore the corrosion rate is high as well. This has led to the notion of flow induced localized corrosion (FILC). Clearly the phenomenon is "flow assisted" but it is localized. By that one does not mean pitting; rather, one refers to areas of some extension, which corrode faster than the adjoining metal.

Much has been made of the extent of the areas subject to FILC (or FAC) because the risk associated with the resulting failure will be governed by the extent of corrosion. 10) 9)See Ref. 1 Horowitz at A 49. n

10) Understandably, the damage from a half-inch to one-inch "pinhole" may be considerably limited versus the damage from a pipe that splits open the length of several feet.

6/2/2008 5 of 12 RHH Rebuttal

If only a small area corrodes due to enhanced local turbulence a small pit and eventually a small hole may result with only minor consequences. If on the other hand FILC (FAC) occurs over a larger area, the pipe may split open (as has indeed happened) with potentially disastrous consequences.

One can now reasonably ask the question as to what happens if the flow intensity exceeds that which has been empirically correlated in Checworks. In other words, if a certain localized enhanced corrosion rate has been observed over a period of years in the past and all of a sudden the flow rate (and hence the flow intensity) is increased, (EPU, power upgrade), will the local corrosion rates simply increase proportionately in accordance with the established laws relating average shear stress to mass transfer, or will the local corrosion rates increase exponentially as has been suggested earlier?

In the first instance Checworks would predict the new corrosion rate, in the second instance Checworks would have to be recalibrated, or even fundamentally modified to accommodate the new relationships. This is the fundamental question that must be answered before Cheeworks can be accepted as the basic tool to manage aging of these pipes.

Indeed additional phenomena related to high flow rates, high shear stress, have been documented with failure rates in excess of those attributed to FAC. These phenomena are described as erosion corrosion, "I)impingement corrosion, 12) and finally cavitation.13) All three phenomena result in a much more severe attack than what has broadly been called FAC, and which is at the basis of Checworks (see definitions below).

It is important to highlight this since the phenomena covered by Checworks do not include the most severe corrosion, which can occur particularly after a power upgrade. In fact Dr. Horowitz dismissed as irrelevant with respect to Checworks actual catastrophic failures attributed to erosion corrosion or impingement corrosion and therefore outside the scope of Checworks. This is a serious shortcoming of the l ) This is actually a misnomer in this context since erosion corrosion generally involves solids carried in the fluid stream. However, it is recognized that the terminology is not used consistently. Erosion corrosion, which I prefer to' characterize as FILC, starts at some unevenness on the surface (inclusion, scratch, etc.).

The high flow rate causes local eddies, which leads to higher removal rate of corrosion product than over the surrounding areas. As the area of enhanced corrosion grows, the flow disturbance grows in intensity.

Consequently the rate of penetration is not constant with time.

12) Impingement is caused by liquid droplets carried in the gas to hit the surface. This can occur from any angle depending on the direction of the flow vector. When a droplet approaches the surface the liquid between the droplet and the surface has to be displaced. It turns out that the velocity of the liquid parallel to the surface increases exponentially as the droplet approaches values many times higher than the estimated average velocity of the bulk liquid relative to the surface.

13) Cavitation occurs when the liquid flows relative to the surface (or the surface moves relative to the liquid) with oscillations such that at one point in time a vacuum is generated and a bubble is created, while right afterwards the pressure increases such that the bubble collapses. This causes enormously high oscillating fluid velocities parallel to the surface and tremendously increased mass transfer and very likely mechanical damage to the corrosion product layer (the passive layer) as well.

(

6/2/2008 6 of 12 RHH Rebuttal

model and its application, because if the model forms the basis of aging management of the steam and hot water pipes it must, absolutely must,'include the occurrence of all corrosion phenomena including those that lead to the most severe corrosion damage, not be restricted to just the average corrosion. But herein lies the rub as follows:

Checworks fully recognizes the fact that the severity of flow induced corrosion depends on geometric factors as described previously. Checworks, it appears, specifies in excess of 56 different geometric features. However there-are things that cannot be specified. For example, the internal residual weld bead from the root pass may in one case be 1/8 inch high, in another % inch. The upstream and downstream turbulence surrounding the weld bead are obviously much more severe in the latter case, and a power upgrade may disproportionately affect the flow over the larger bead.

While an increase in flow rate will affect the mass transfer rate (and hence the corrosion rate) proportionately under conditions of well defined (turbulent) flow, the flow intensity in local turbulences, such as eddies upstream and downstream of mechanical (geometric) flow disturbances are increased exponentially (see earlier).

And here exactly is the uncertaiinty highlighted by Dr. Hopenfeld and denied by Dr.

Horowitz. As I have also documented, industry consensus is that the flow intensity in local turbulences is increased to a much larger extent due to a power upgrade than the flow intensity in well-developed turbulent flow.

There are however additional phenomena, which have to be taken into account.

Protective corrosion product layers can be destroyed not only through dissolution but by mechanical forces with turbulent areas. The fracture strength of corrosion product layers, such as iron sulfide and iron carbonate (highly protective formations), is extremely high (of the order of many hundreds of mega Pascals). Generally the compressive forces within turbulences are not that high. 14 It has been observed, however, that isolated events occur within the turbulences that match the fracture strength of the corrosion product scale. These events have led to the definition of a critical shear stress (or critical flow intensity) beyond which the protectiveness of the layer is lost. I am not suggesting that this absolutely happens. I am however

'postulating that past experience as built into Checworks cannot account for such occurrences. Therefore, the aging management process has to be revised or Checworks calibrated accordingly.

III. Discussion of Specific Experiences Involving Checworks

1. The Reliability of the Predictions It has been said that Checworks can predict the "wear" [cumulative corrosion] within

+/- 50 percent. If this were the case the modeling program would indeed be outstanding. However, the notion of predicted rates being with +/- 50% of the

14) This discussion relates to the "freak waves" alluded to earlier (see ref 2).

6/2/2008 7 of 12 RHH Rebuttal

measured ones is derived from a representation of the data as shown in Figure 3 below. It is true that when the measured wear data are plotted against the predicted ones most of the data points lie between two lines that are plotted +/- 50% off the 45 degree equivalency lines. This interpretation is totally misleading and scientifidally dishonest.

First, one sees that there is no correlation between the predictions and the actual measurements. Second, one also sees that measurements which we are made to believe are within 50% of the predicted value are really twice as large or larger; similarly, on the other side one sees that measured values are half or less of the predicted ones, again a factor of 2 different.

Conclusion:

The accuracy of Checworks is such that the measured values are within a factor of +/- two [+/-.2] of the predicted values rather than +/- 50% as claimed.

A factor-of-two difference between measured and predicted corrosion [or corrosion rate] can be quite significant with respect to selecting a particular item (line) for inspection during a given refueling outage. Indeed the report of the "EPRI Checworks Wear Rate Analysis Results for Cycle 22B"'15) shows that the time predicted to reach the critical minimum wall thickness in a majority of cases is many years negative.

This means that the item should have failed a long time ago. Similarly, the remaining time to failure may be grossly overestimated. But one will never know unless the proper inspections are performed and the computer model recalibrated, a process Dr.

Horowitz and Entergy seem to find irrelevant. 6)

Examination of the data from March 2003 (RFO 23) showed average and measured corrosion rates of the order of 28 and 21 mpy, respectively, for the outlet "P-1-1A" on line 001-16-FDW-01. In May of 2006 these same rates have come down to 7.524 and 5.712 mpy, respectively.17) It is hard to see how this could have happened. There is in the program something called "Line Correction Factor." This factor has been defined by Dr. Horowitz as the relationship between predicted and measured corrosion rate (see belowl8 )). However in 2003 this factor was 0.649 and by 2006 it had become 0.175. It is amazing to observe that fudge factors are built into the program which

15) Exhibit E-4-29.

'6) Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4-Flow-Accelerated Corrosion: A 34.

17) Exhibit E-4-30.

HOROWITZ'S TESTIMONY STATES THE FOLLOWING ABOUT THE ABOVE-MENTIONED "CORRECTION FACTOR" AT A28: "A Pass 2 Analysis compares the measured inspection results to the calculated wear rates and adjusts the FAC rate calculations to account for the inspection results. The program does this by comparing the predicted amount of degradation with the measured degradation for each of the inspected components. Using statistical methods, a correction factor is determined which is applied to all components in a given pipe line - whether or not they were inspected.",

6/2/2008 8 of 12 RHH Rebuttal

allow the operator to manipulate the data such that they meet certain criteria. (In the particular case mentioned above apparently negative times to failure were quite inconvenient).

Further examination of the data reveal that for the same line the corrosion rate on "Outlet P-l-1C" is exactly the same within 4 digits (+/- -0.01 percent). Under the circumstances, it is very hard to gain confidence in Checworks and the manner in which it is apparently handled.

Finally it should be mentioned that with all the work that has been done, theoretical and empirical, around the problem of Flow Induced Localized Corrosion the matter is still not understood. In discussing the failure which occurred in April 2004 at the Kewaunee plant, Dr. Horowitz states that the line in question is not FAC-susceptible because apparently it is part of the "raw water system." Therefore it was not analyzed with Checworks and is not covered by NSAC-202L.

This is obviously a very unfortunate approach to the problem of corrosion in its entirety.

Whenever corrosion is dependent on transfer of corrosionproducts away from the surface, or transfer of corrodents to the surface, the corrosionrates are mass transfer dependent and hence flow dependent.

In the case of raw water, the oxygen content in the water is responsible for the observed corrosion. The corrosion rate is dependent on the oxygen concentration as well as on the flow rate. Flow rate dependence of corrosion is almost universally true except in a very few cases which are not relevant in this context.

6/2/2008 9 of 12 RHH Rebuttal

J Figure 1 The Concept of Flow Assisted Corrosion AC Magnetite sat Fen+

bulk Fen+ Q=A. dd Steel 7

\11 Fe 304 I

Q Rate of iron diffusion across laminar boundary sub-layer A diffusion coefficient for iron k

d = boundary layer thickness Bulk of solution; Direction of flow Flow regime likely turbulent in the traditional sense Re>>2000-3000 As the fluid velocity increases the thickness of the laminar layer decreases hence the mass transfer increases: removal Rate of iron oxide increases hence corrosion Laminar Boundary rLayer Rate increases.

6/2/2008 10 of 12 RHH Rebuttal

Figure 2 Visualization of Average and Local Shear Stress Straight Pipe with Weldment Overall AP -Average Shear Stress Weidment Flow Direction Areas of high Local Turbulences and Accelerated Corrosion The local shear stress is in no explicit relationship to the average shear stress And can be orders of magnitude higher depending on geometric factors 6/2/2008 I1I of 12 RHH Rebuttal

Figure 3 Comparison of Wear Predictions 0

-e 80 100 120 Measured Wear (mils)

• Current Component 12 of 12 RHH Rebuttal 6/2/2008

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION B/ t 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 REBUTTAL STATEMENT OF POSITION, TESTIMONY AND EXHIBITS in the above-captioned proceeding were served on the persons listed below, by U.S. Mail, first class, N postage prepaid and, where indicated by an e-mail address below, by electronic mail, on June 2, 2008.

Office of the Secretary Administrative Judge Attn: Rulemaking and Adjudications Staff Alex S. Karlin, Esq., Chair Mail Stop: O-16C1 Atomic Safety and Licensing Board U.S. Nuclear Regulatory Commission Mail Stop T-3 F23 Washington, DC 20555-0001 U.S. Nuclear Regulatory Commission E-mail: hearingdocket@nrc.gov Washington, DC 20555-0001 E-mail: ask2@nrc.gov Sarah .Hofmann, Esq.

Director of Public Advocacy Administrative Judge Department of Public Service William H. Reed 1 2 State Street, Drawer 20 1819 Edgewood Lane Montpelier, VT 05620-2601 Charlottesville, VA 22902 E-mail: sarah.hofmann@state.vt.us E-mail: whrcville@embarqmail.com Lloyd B. Subin, Esq.

Office of Commission Appellate Adjudication Mary C. Baty, Esq.

Mail Stop: O-16C1 Office of the General Counsel U.S. Nuclear Regulatory Commission Mail Stop 0- 15 D21 Washington, DC 20555-0001 U.S. Nuclear Regulatory Commission E-mail: OCAAmail@nrc.gov Washington, DC 20555-0001 E-mail: lbs3@nrc.gov; mcbl@nrc.gov Administrative Judge Dr. Richard E. Wardwell Anthony Z. Roisman, Esq.

Atomic Safety and Licensing Board Panel National Legal Scholars Law Firm Mail Stop T-3 F23 84 East Thetford Road U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Lyme, NH 03768 E-mail: rew@nrc.gov E-mail: aroisman@nationallegalscholars.com

Marcia Carpentier, Esq. David R. Lewis, Esq.

Lauren Bregman, Esq. Matias F,. Travieso-Diaz Atomic. Safety and Licensing Board Panel Pillsbury Winthrop Shaw Pittman LLPI Mail Stop T-3 F23 -> "2300 N Street NW U.S. Nuclear Regulatory Commission Washington, DC 20037-1128 Washington, DC 20555-0001 E-mail: david.lewis@pillsburylaw.com E-mail mxc7@nrc.gov matias.travieso-diaz@pillsburvlaw.cofn Peter C. L. Roth, Esq. Diane Curran Office of the Attorney General Harmon, Curran, Spielberg, & Eisenberg, L.L.P.

33 Capitol Street 1726 M Street N.W., Suite 600 Concord, NH 03301 Washington, D.C. 20036 Peter.roth@doj.nh.gov dcurran('7iharmoncurran.com Jessica A. Bielecki U.S. Nuclear Regulatory Commission Office of the General Counsel Mail Stop: O-15-D21 Washington, D.C. 20555-0001 iessica.bielecki@nrc.gov by:

Christina Nielsen, Administrative Assistant SHEMS DUNKIEL KASSEL & SAUNDERS PLLC

SHEMS DUNKIEL KASSEL & SAUNDERS P L L C RONALD A. SHEMS* GEOFFREY H. HAND KAREN L. TYLER BRIAN S. DUNKIEL** REBECCA E. BOUCHER JOHN ________ ASSOCIATE ATTORNEYS JOHN B. KASSEL . EILEEN I. ELLIOTT OF COUNSEL MARK A. SAUNDERS ANDREW N. RAUBVOGEL June 2, 2008 Office of the Secretary Attn:, Rulemaking and Adjudications Staff Mail Stop O-16C1 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Re: In the Matter of Entergy Nuclear Vermont yankee, LLC and Entergy Nuclear Operations, Inc. (Vermont Yankee Nuclear Power Station),

Docket No. 50-271 -LR, ASLBP No. 06-849-03-LR Filina Discussina A Proprietary Document

Dear Sir or Madam:

Please find enclosed for filing in the above-stated matter New England Coalition, Inc.'s Rebuttal Statement of Position, Testimony and Exhibits. One document that Entergy has designated proprietary is discussed in the rebuttal testimony of Dr. Joram Hopenfeld, Exhibit NEC-JH_63.

This document is: Letter to James Fitzpatrick from EPRI (February 28, 2000). It 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.

\

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 9 1 COLLEGE STREET, BURLINGTON, VERMONT 05401 TEL 802 / 860 1 003 - FAX 802 / 860 1208 - www.sdkslaw .com

• Also admitted in the State o( Maine

• Also admitted in the District of Columbia

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.

REBUTTAL STATEMENT OF POSITION In accordance with 10 C.F.R. § 2.1207(a)(2) and the Atomic Safety and Licensing Board's ("Board") November 17, 2006 Order,' New England Coalition, Inc. ("NEC") hereby submits its Rebuttal Statement of Position ("Statement") on NEC's Contentions 2A and 2B (environmentally-assisted metal fatigue analysis), 3 (steam dryer), and 4 (flow-accelerated N/

corrosion). In support of this Statement, NEC submits the attached rebuttal testimony of Dr.

2 3 Joram Hopenfeld 2 and Dr. Rudolf Hausler, and the Exhibits listed on the attached Rebuttal Exhibit List.

I. NEC CONTENTIONS 2A AND 2B Licensing Board Order (Initial Scheduling Order) (Nov. 17, 2006) at 10(D) (unpublished).

2 Exhibit NEC-JH_63.

3 Exhibit NEC-RH_04.

(Environmentally-Assisted Metal Fatigue Analysis)

The evidence contained in Entergy's and the NRC Staff s direct testimony and exhibits fails to prove the validity of Entergy's CUFen Reanalyses. Indeed, NRC Staff witness Dr. Chang has testified that the NRC Staff cannot determine the conservatism of Entergy's analysi§, and must therefore rely on Entergy's proposed fatigue-monitoring program to demonstrate its conservatism during the period of extended operation. See, Chang Rebuttal Testimony at A 10. The Board should therefore d6cide Contentions 2A and 2B in NEC's favor. The Board should find that Entergy has failed to satisfy,§ 54.21(c)(1)(ii) by projecting its environmentally-assisted metal fatigue TLAA to the end of the period of extended operation, and therefore must now rely, pursuant to § 54.21(c)(1)(iii), on an aging management program to provide reasonable assurance of public health and safety. NEC should then be permitted to litigate its Contention 2, now held in abeyance, which addresses the sufficiency of Entergy's aging management plan for environmentally-assisted metal fatigue.

NEC's rebuttal evidence concerning Contentions 2A and 2B is contained in the prefiled rebuttal testimony of Dr. Joram Hopenfeld, Exhibit NEC-JH_63 at 2-19 and additional rebuttal Exhibits NEC-JH_64 - NEC-JH_67.

A. The NRC Staff Misconstrues. the Requirements of 10 CFR § 54.21(c)(1).

The NRC Staff's ("the Staff") Initial Statement of Position misconstrues 10 CFR

§ 54.21 (c)(1). By the Staff's construction of this rule, Entergy could resolve any of NEC's Contention 2A and 2B criticisms of the CUFen reanalyses through a commitment to continued "refinement" of these analyses after the close of the ASLB proceeding. The Staff s position is inconsistent with standard rules of statutory and regulatory 2

construction, as well as with this Board's treatment of NEC's Contention 2, 2A and 2B in this proceeding to date. Most importantly, it would defeat the ability of any' license renewal intervenor to litigate an applicant's Time Limited Aging Analysis ("TLAA")

methodology.

Section 54.21 (c)(l) allows a license renewal applicant three options to address an aging-related health and safety issue that it has evaluated under its current license through analysis that involves time-limited assumptions. It reads as follows:.

(c) An evaluation of time-limited aging analyses.

(1) A list of time-limited aging analyses, as defined in § 54.3, must be provided.

The applicant shall demonstrate that-( .

(i) The analyses remain valid for the period of extended operation; (ii) The analyses have been projected to the end, of the period of extended operation; or (iii) The effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

10 CFR' § 54.21(c). Under § 54.21(c)(1)(i), the applicant may demonstrate that the analysis performed under its current license is valid for the period of extended operation.

ýIf the applicant is unable to satisfy § 54.21(c)(1)(i), it may project the analysis to the end of the period of extended operation under § 54.21(c)(1)(ii). Finally, if the applicant is unable to demonstrate reasonable assurance of public health and safety through a TLAA analysis under § 54.2 1(c)(i) or § 54.21 (c)(ii), it must then develop an aging management plan under § 54.21(c)(1)(iii).

Entergy's CUFen reanalyses'are properly subject to 10 CFR § 54.21(c)(1)(ii) -

Entergy has performed these reanalyses in an attempt to demonstrate that its CUFen TLAA has been projected to the end of the period of extended operation. This was the 3

NRC Staff's view in August, 2007. Then, the Staff rejected Entergy's license renewal commitment to complete its CUFen reanalyses prior to entering the period of extended operation on grounds that "in order to meet the requirements of 10 CFR § 54.21 (c)(1), an applicant for license renewal must demonstrate in the LRA that the evaluation of the time-limited aging analyses (TLAA) has been completed." See, Exhibit NEC-JH_62 at .

Now, however, the NRC Staff takes the position that Entergy's CUFen Reanalyses constitute a "corrective action" to "manage the effects of aging" that falls under 10 CFR 54.21 (c)(1)(iii). The Staff has thus reversed its view of when Entergy must complete its CUFen reanalyses. It is now the Staff's opinion that Entergy may perform the CUFen Reanalysis as part of its aging management program after its license renewal application is granted, possibly even during the period of extended operation.

The Staff explains:

If a licensee chooses to satisfy § 54.21 (c)(1)(i) or (ii), the 'demonstration' must be in the LRA, and a commitment to perform analyses projecting 60-year CUFs prior to the period of extended operation is inconsistent with the regulatory language. However, if the licensee chooses to satisfy § 54.21(c)(1)(iii), the licensee must instead demonstrate that effects of aging will be adequately managed and a commitment to perform refined CUF analyses in the future as part of an aging management program is acceptable.

NRC Staff Initial Statement of Position at 11 -12 (emphasis 'in original).

The Staff's interpretation of § 54.21(c)(1) is inconsistent with its plain language, and with standard rules of construction. Part 54.21(c)(1)(iii) is properly interpreted as a requirement to manage aging in the event the TLAA cannot be projected to the end of the license renewal period. In other words, an applicant may avoid the obligation to develop an aging management plan under § 5'4.21(c)(1)(iii) if it satisfies § 54.21(c)(1)(i) or 4

(

54.21 (c)(1)(ii) by including a demonstration that the TLAA is either valid or can be projected for the period of extended operation in the LRA. Under the NRC Staff's construction, parts 54.21(c)(1)(i) and 54.21(c)(1)(ii) collapse into part 54.21(c)(1)(iii):

that is, the TLAA demonstration becomes a component of the aging management plan, instead of a means to avoid the obligation to develop an aging management plan. The Staff's construction is therefore invalid. Cf Dunn v. CFTC, 519 U.S. 465, 472, 473, 117 S.Ct. 913, 137 L.Ed.2d 93 (1997) (rejecting an interpretation of a statute that would have left part of it "without any significant effect at all," because "legislative enactments should not be construed to render their provisions mere surplusage.").

The Staff's interpretation is also inconsistent with the Board's interpretation of NEC's Contentions 2, 2A and 2B in this proceeding to date, which treats Entergy's CUFen reanalyses as distinct from its metal fatijue aging management plan, and as an alternative to a management plan. The Board ruled that NEC's Contention 2 addresses the sufficiency of the metal fatigue management program. It held Contention 2 in abeyance, to be litigated only if NEC prevails on Contentions 2A and 2B, and Entergy then reverts to reliance on fatigue management. The Board's Order of November 7, 2007 reads in relevant part as follows:

When this litigation began, Entergy's application showed certain CUFs to be greater than unity, and Entergy indicated that it would manage such metal fatigue over the 20-year renewal period. NEC's original Contention 2 challenged the adequacy of Entergy's demonstration of its metal fatigue management program. Now Entergy says it has recalculated the CUFs to show that they are all less than 1, thus eliminating the need to manage metal fatigue over the renewal period. NEC Contention 2A challenges Entergy's recalculation of the CUFs. If NEC Contention 2 is successful and Entergy's revised CUF analyses are not shown to be sufficient, then Entergy might return to relying on a fatigue management program as a way of satisfying the Part 54 regulations.

5

Thus, we conclude that NEC Contention 2A will be litigated now, and NEC Contention 2 will be held in abeyance. The proviso is that the parties are not to litigate Contention 2 unless and until Entergy returns to reliance on a metal fatigue management program (as would likely happen if NEC prevails on NEC Contention 2A).

Memorandum and Order (Ruling on NEC Motions to File and .2 Admit New Contention),

November 7, 2007 at 12.

Finally, the Staff s position that Entergy's environmentally-assisted metal fatigue N

TLAA analysis should be treated as a component of its metal fatigue aging management

.plan under § 54.21(c)(1)(iii) has significant consequences for the rights of NEC and other license renewal intervenors to obtain information about and contest the validity of TLAAs. Per the Staff's view, the applicant may comply with § 54.21 through a commitment to perform the TLAA analysis after the application is granted, an approach that will obviously frustrate public scrutiny of the TLAA methodology.

These consequences are already playing out in the ASLB proceeding concerning Entergy's license renewal'application for the Indian Point plant, in which both the State of New York and Riverkeeper, Inc. have petitioned for admission of a contention similar to NEC's Contention 2. Entergy has taken the positions that it should not be required- to provide a information about its CUFen analyses for the NUREG/CR-6260 locations until after the close of the ASLB proceeding, and the Staff should accept a commitment to perform CUFen analyses as part of the Fatigue Monitoring Program per 10 CFR § 54.21(c)(1)(iii). See, Exhibit NEC-JH-67 at Attachment 1, Enclosure 2, (see discussion of D-RAI 4.3.1.8-1 and D-RAI 4.3.1.8-2). The.NRC Staff has apparently acquiesced in t'

Entergy's effort to avoid public scrutiny of its CUFen methodology, and withdrew requests for this information. Id.

6

The Board should reject the Staffs interpretation of 10 CFR § 54.21(c)(1). It should find that Entergy's CUFen Reanalyses fall under § 54.21 (c)(1)(ii), and must be completed as part of Entergy's License Renewal Application. The Board should further find that Entergy cannot satisfy § 54.21 (c)(1) with a license renewal commitment to fix any problems in its CUFen Reanalyses, demonstrate the conservatism of those analyses, or finish those analyses after the close of the ASLB proceeding.

B. Enterpy's Evidence Does Not Include Information Necessary to Validate its CUFen Reanalyses; Entergy Therefore Fails to Satisfy its Burden of Proof.

Dr. Hopenfeld testifies that Entergy has not provided to NEC or filed in the evidentiary record before the Board the following information necessary to validate its CUFen Reanalyses:

1. Drawings of the VY plant piping from which it would be possible to validate Entergy's assumptions of uniform heat transfer distribution, including orientation angles, weld locations and internal diameters, Hopenfeld Rebuttal at A18, Exhibit NEC-JHr03 at 8;

2. A com'lete description of the methods or models used to determine velocities and temperatures during transients, Hopenfeld Rebuttal at A19, Exhibit NEC-JH_03 at 9; and

3. Information regarding exactly how the number of plant transient cycles was determined for purposes of the 60-year CUF calculations, from which it would be possible to evaluate the conservatism of the cycle count, Hopenfeld Rebuttal at A2 1.

Regarding the first two issues, Entergy represents that some information was provided: 36 drawings, a copy of the Design Information Record, and some information regarding the calculation of flow velocity in response to Counsel's inquiry. Entergy Initial Statement of Position at 14. Dr. Hopenfeld testifies that the information Entergy provided is insufficient. Hopenfeld Rebuttal at Al18 and Al19.

7

Entergy further faults NEC for failing to request any additional information it considered necessary to a complete evaluation of the CUFen analyses in "discovery." Id.

This argument of course ignores the. fact that, to its tremendous disadvantage, NEC has no right to formal discovery in this Subpart L proceeding. See, 10 CFR § 1.1203, Hearing file; prohibition on discovery; In the Matter of Entergy Nuclear Vermont Yankee, LLC, and Entergy Nuclear Operations,Inc. (Vermont Yankee Nuclear Power Station), 64 NRC 131, 202, ASLBP 06-849-03-LR, (September 22, 2006)("under the 'informal' adjudicatory procedures of Subpart L, discovery is prohibited except for certain mandatory disclosures.").

More importantly, Entergy's argument that NEC should have requested information in fictitious "discovery" misses the point. Entergy has the burden of proof regarding whether its CUFen reanalyses satisfy 10 CFR § 54.21 (c)(1)(ii), and provide reasonable assurance of public health and safety. Entergy does not even attempt to explain why its record evidence concernifig the VY pipe configuration and the methods or models it used to determine velocities and temperatures during transients is sufficient to validate its CUFen reanalyses. Entergy therefore fails to meet its burden.

With respect to the third issue above, the transient cycle count, Dr. Hopenfeld testifies that the explanation stated in Entergy's direct testimony of its means of determining the number of plant transients for purposes of its CUF calculations is inconsistent with information Entergy provided in its LRA and in the reports of the CUFen analyses produced to NEC. Hopenfeld Rebuttal at A2 1. Entergy's direct testimony on this subject is vague, and does not indicate that an allowance was made for the likely increase in plant transients resulting from the 20 percent power uprate or the 8

fact that the number of plant transients is likely to increase as a plant ages. Id. Dr.

Hopenfeld is unable to determine whether Entergy's transient cycle count is conservative.

Id.

The NRC Staff's Initial Statement of Position misrepresents the testimony of NRC Staff witness Dr. Chang with respect to the transient cycle count. The Statement of Position represents that the Staff "disagrees with NEC's assertion that Entergy's assumptions about the number of transients in its analyses are not conservative," and states that "[t]he Staff's position is that Entergy's assumptions are appropriate." NRC Staff Initial Statement of Position at 18. In fact and to the contrary, Dr. Chang testifies

/

that the staff, like Dr. Hopenfeld, "cannot determine the level of conservatism regarding the number of transient cycles at this time," and therefore relies on Entergy's Fatigue Monitoring Program to "ensure that the cycle projection is valid and that the fatilzue analysis results are conservative." Chang Rebuttal at A1O (emphasis added).

Thus, per the testimony of NRC Staff witness Dr. Chang, Entergy has not provided information to the NRC, or filed evidence before the Board, from which it is possible to determine whether its CUFen analysis results ale conservative. Again, Entergy has not satisfied its burden of proof, and the Board must decide Contentions 2A and 2B in NEC's favor..

C. Calculation of the Fen Multiplier

1. The NRC Staff and Entergy are Incorrect that the ASME Code Does Not Require the Fen Correction.

Both Entergy and the NRC Staff contend that the ASME Code does not require any accounting for the effects of coolant environment on component fatigue life. This is incorrect. The Code requires that the code user must account for conditions in which 9

the environment is more aggressive than air. Rebuttal Testimony of Joram Hopenfeld at A5, citing, ASME Code, Appendix B at B-2131.

2. NRC Staff guidance that sanctions use of the equations and,,

procedure described in NUREG/CR-6583 and NUREG/CR-5704 to calculate Fen multipliers is not dispositive. The Staff must prove the validity of this guidance, but has not done so. a In response to Dr. Hopenfeld's argument that Entergy used outdated statistical

-equations published in NUREG/CR-6583 and NUREG/CR-5704 to calculate Fen values, when it should have instead considered *data much more recently published in NUREG/CR-6909 (February 2007), both the NRC Staff and.Entergy cite NRC guidance stated in Section X.Ml of the GALL Report, NUREG-1801, Vol. 1, which sanctions use of the NUREG/CR-6583 and NUREG/CR-5704 equations to calculate Fen multipliers.

Entergy and the Staff also note that Regulatory Guide 1.207 recommends reference to NUREG/CR-6909 only for fatigue analyses in new reactors.

These guidance documents are by no means dispositive of NEC's criticisms of Entergy's method of calculating Fen values. "Agency interpretations and policies are not

'carved in stone' but must rather be subject to re-evaluation of their wisdom on a continuing basis." Kansas Gas and Electric Co. (Wolf Creek GeneratingStation, Unit 1),

49 NRC 441, 460 (1999), citing, Chevron USA, Inc. v. Natural Resources Defense Council,Inc., 467 U.S. 837, 863-64 (1984)).

The GALL report and Regulatory Guide 1.207 do not contain legally binding regulatory requirements. The Summary and Introduction to NUREG-l1801, Vol. 1 includes the following explanation of its legal status:

10

'Legally binding regulatory requirements are stated only in laws; NRC regulations; licenses, including technical specifications; or orders, not in NUREG series publications.

The GALL report is a technical basis document to the SRP-LR, which provides the Staff with Guidance in reviewing a license renewal application .... The Staff should also review information that is not addressedin the GALL report or is otherwise differentfrom that in the GALL report. ,

NUREG-1801, Vol. 1, Summary, Introduction, Application of the GALL Report (emphasis added). Likewise, the face page to Regulatory Guide 1.207 states the following: "Regulatory Guides are not substitutes for regulations, and compliance with them is not required." Regulatory Guide 1.207; See also, In the Matter of International Uranium (USA) Corporation,51 NRC 9, 19 (2000) ("[NRC NUREGS,r Regulatory Guides, and Guidance documents] are routine agency policy pronouncements that do not carry the binding effect.of regulations....

NUREG-1 801, Vol. 1 and Regulatory Guide 1.207 do not preclude this Bdard from considering the question at the heart of NEC's Contentions 2A and 2B: What is the most appropriate method'of calculating the effects of the environment on fatigue?

[NUREGs] do not rise to the level of regulatory requirements. Neither do they constitute the only means of meeting applicable regulatory requirements.... Generallyspeaking,.., such guidance is treated simply as evidence of legitimate meansfor complying with regulatory requirements, and the staff is requiredto demonstrate the validity of its guidance if it is called into question during the course of litigation.

In the Matter of CarolinaPower & Light Company andNorth CarolinaEastern Municipal Power Agency (Shearon HarrisNuclear Power Plant), 23 NRC 294 (1986),

citing, MetropolitanEdison Co. (Three Mile Island NuclearStation, Unit 1), 16 NRC 1290, 1298-99 (1982) (emphasis added); See also, In the Matter of Connecticut Yankee 11

Atomic Power Company (HaddamNeck Point), 54 NRC 177, 184 (2001), citing, Long IslandLighting Co. (ShorehamNuclear Power Station, Unit 1), 28 NRC 288, 290 (1988)("NUREGs and similar documents are akin to 'regulatory guides.' That is, they provide guidance for the Staff's review, but set neither minimum nor maximum regulatory requirements."); In the MatterofPrivate Fuel Storage, LLC, 57 NRC 69, 92 (2003)("[A]n intervenor, though not allowed to challenge duly promulgated Commission regulations in the hearing process... is free to take issue with ... NRC Staff guidance and thinking .....

The Staff is required in this proceeding to prove the current validity of its guidance concerning the calculation of Fen multipliers, but has produced little if any evidence of this. Entergy and the NRC Staff offer only one substantive reason 4 for use of\

the NUREG/CR-6583 and NUREG/CR-5704 equations over information contained in NUREG/CR-6909: both contend that the NUREG/CR-6909 "procedure" is less conservative and will generally produce lower Fen multipliers for operating reactors.

See, Fair Rebuttal at A5 and A6, Stevens Rebuttal at A50. Dr. Hopenfeld explains that the overall NUREG/CR-6909 "procedure" could be considered less conservative because NUREG/CR-6909 contains new air fatigue curves that are less conservative that the current ASME Code fatigue curves. Hopenfeld Rebuttal at A6. He further testifies, however, that he has never recommended use of these new air fatigue curves. Until the current fatigue curves in the Code are officially modified, these curves must be considered the "best representation of fatigue life in air." Id.

I -

4 The Staff also offers a nonsubstantive reason: i.e., that it would be inconvenient to change its guidance while a number of license renewal applications are pending or anticipated.

12

Dr. Hopenfeld explains that the alleged greater conservatism of the NUREG/CR-6583 and NUREG/CR-5704 "procedure" is irrelevant to his main point about how Entergy should have used information contained in NUREG/CR-6909 in its CUFen analyses. Hopenfeld Rebuttal at A6, A7. As Dr. Hopenfeld has previously testified, NUREG/CR-6909 describes many factors known to affect fatigue life that are not accounted for in the ANL 1998 Equations contained in NUREG/CR-6583 and NUREG/CR-5704. Dr. Hopenfeld's rebuttal testimony provides a summary of these factors at A5, Table 1, and observes that Entergy's direct testimony addressesronly one of them, surface finish. Hopenfeld Rebuttal at A5. This is the relevant information Entergy should have taken from NUREG/CR-6909. Hopenfeld Rebuttal at A7. Entergy and NRC staff witnesses fail to explain why this information contained in NUREG/CR-6909, published after the GALL report, should be ignored in the license renewal process.

Dr. Hopenfeld testifies that, given the current state of the technology, it simply is not possible to calculate Fen multipliers that are precision-adjusted to plant conditions, as Entergy purports to have done. Hopenfeld Rebuttal at A7. Given the many uncertainties in the calculation of Fen, he recommends use of bounding values contained in NUREG/CR-6909 - 12 for austenitic stainless steel and 17 for carbon and low alloy steel.

Id.

3. NEC's Rebuttal Evidence Concerning Calculation of Fen Multipliers NEC witness Dr. Joram Hopenfeld's rebuttal testimony addresses the following additional technical issues regarding the calculation the Fen multipliers raised by Entergy and the NRC Staff.

13

0 Dr. Hopenfeld disagrees with NRC witness Dr. Chang that Fen values of 12 for austenitic stainless 17 for carbon and low alloy steel represent a "worst case scenario," or that application of these values is unreasonably conservative. Hopenfeld Rebuttal at A9.

N ,Dr. Hopenfeld disagrees with Entergy witness Mr. Stevens that Fen= 17 applies only to high oxygen and temperature environments that do not exist at VYNPS.

Hopenfeld Rebuttal at A 10.

E Dr. Hopenfeld does not agree with Entergy and NRC Staff witnesses that any lack of conservatism in Fen values calculated by the ANL 1998 Equations is counterbalanced by excess conservatism in the ASME Code design fatigue curves. He observes that there is no general agreement among researchers that the current Code is conservative. Hopenfeld Rebuttal at A 12.

E Dr. Hopenfeld disagrees with Entergy witness Mr. Fitzpatrick that Entergy properly accounted for surface roughness effects through use of ASME Code design fatigue curves that include a "safety factor" to account for these effects. Hopenfeld Rebuttal at A 13.

a Dr. Hopenfeld disagrees with Entergy witness Mr. Fitzpatrick that Entergy has demonstrated its use of bounding values for oxygen as an input to the ANL equations in all its CUFen analyses. Hopenfeld Rebuttal at A14. Mr. Fitzpatrick refers to steady state values as determined by a computer Code called BWRVIA that Entergy has neither described nor provided to NEC. Id. Mr. Fitzpatrick does not address the impact on Fen of oxygen concentrations that occur during transients at higher levels than at steady state.

Id.

14

a Dr. Hopenfeld testifies that it was inappropriate for Entergy to exclude a correction factor for cracking in the cladding and~base metal of the feedwater nozzles based on results of its 2007 inspection of these nozzles for cracks in the base metal.

f Hopenfeld Rebuttal at Al15.

D. Calculation of 60-Year CUFs NEC witness Dr. Joram Hopenfeld's rebuttal testimony addresses the following issues, in addition to the above-discussed potential lack of conservatism in projecting transient cycles, regarding the calculation the 60-year CUFs raised by Entergy and the NRC Staff.

• Dr. Hopenfeld disagrees that Entergy's CUFen analyses properly applied a heat transfer equation that applies only to a fully developed turbulent flow to the VYNPS nozzles. Specifically, he disagrees with Entergy witness Mr. Stevens that flow in the feedwater nozzle is fully developed because the upstream horizontal pipe is 48 inches

/

long. Hopenfeld Rebuttal at A16. Dr. Hopenfeld further observes that Mr. Stevens did not explain why, in transients where the flow stops and heat transfer occurs by natural convection, a correction was not made for circumferential variation of the heat transfer both during single phase flow and during condensation. Id.

0 Dr. Hopenfeld disagrees with Entergy witness Mr. Stevens that' it is unnecessary to correct a heat transfer equation used in the CUFen Reanalyses by the ratio of the viscosities evaluated at the bulk and wall temperatures during each transient because there are minimal differences in temperature between the pipe wall and the bulk of the fluid. Hopenfeld Rebuttal at A17. Mr. Stevens did not quantify actual temperature 15

differences, which could only be determined from data on wall and bulk fluid temperature histories for sample transients. Id. Such information was not provided. Id.

0 Dr. Hopenfeld disagrees that Entergy's use of the simplified Green's Function methodology in its Initial CUFen Reanalysis introduced only a small error.

Hopenfeld Rebuttal at A20. Entergy has neither explained nor investigated the physical reasons for discrepancies between results obtained by the Green's Function methodology and the more exact methodology, classic NB-3200 analysis. Id. Results obtained by the Green's Function methodology therefore incorporate unquantified uncertainties. Id.

E. Error Analysis NEC witness Dr. Joram Hopenfeld's rebuttal testimony addresses the following issues regarding the need for error analysis raised by Entergy and the NRC Staff.

M Dr. Hopenfeld disagrees with Entergy's witness that it was not necessary to perform an error analysis to validate its analytical techniques because the stress analysis is based on bounding values. Hopenfeld rebuttal at A23.

M Dr. Hopenfeld disagrees with NRC witness Dr. Chang that an error analysis was unnecessary because of conservatism built into the ASME Code and the ANL 1998 Equations. Hopenfeld Rebuttal at A24.

III. NEC CONTENTION 3 (Steam Dryer)

NEC's rebuttal evidence concerning Contention 3 is contained in the prefiled rebuttal testimony of Dr. Joram Hopenfeld, Exhibit NEC-JH_63 at 20-24, and additional rebuttal Exhibits NEC-JH_68 and NEC-JH_69.

A. The Issue Before the Board is Whether a Steam Dryer Aging Management Plan Uninformed by Knowledge of Stress Loads on the 16

Dryer for Comparison to Fatigue Limits is Adequate to Provide Reasonable Assurance of Public Safety.

The validityof the steam dryer stress load modeling Entergy conducted during implementation of the VY power uprate as a basis for Entergy's steam dryer aging management plan during the period of extended operations has not been litigated in this proceeding or otherwise established. The Board has ruled that the assessment of this modeling conducted during the EPU proceeding was not dispositive for purposes of life extension:

Entergy's apparent assertion that the history of the steam dryer issue in the' separate EPU proceeding should resolve the issue in this proceeding is...

without foundation. As demonstrated by Entergy's own pleadings, steam dryer issues were addressed in the EPU proceeding primarily in regard to the power ascension toward EPU levels and the first few operating cycles thereafter.

In the Matter of Entergy Nuclear Vermont Yankee, LLC, andEntergy Nuclear Operations,.Inc. (Vermont Yankee Nuclear Power Station), 64 NRC 131, 189 (September 22, 2006).

Moreover, Entergy represented in its Motion for Summary Disposition of NEC's Contention 3 that its steamfi dryer aging management program will consist exclusively of periodic visual inspection and monitoring of plant parameters as described in General Electric Service Information Letter 644 (GE-SIL-644), will not involve the use of any analytical tool to estimate stress loads on the steam dryer, and will not rely on the finite element modeling conducted prior to implementation of the extended power uprate (EPU) in 2006 for knowledge of steam dryer stress. loads.

In partially granting Entergy's Motion for Summary Disposition, the Board accepted Entergy's representation that its steam dryer aging management plan would not 17

rely on the pre-EPU steam dryer modeling. Memorandum and Order (Ruling on Motion for Summary Disposition of NEC Contention 3), September 11, 2007 at 10 ("Entergy's expert confirms that this program does, not require the use of the CFD and ACM computer codes or the finite element modeling conducted during the EPU."). In doing so, the Board rejected NEC's argument that it should be permitted to litigate the validity of the EPU steam dryer modeling as the basis for aging management. NEC's pleading in opposition to Entergy's Motion for Summary Disposition stated the following regarding this issue:

As stated in the attached Third Declaration of Dr. Joram Hopenfeld, Entergy's claim that its steam dryer aging management program will not involve any means of estimating and predicting stress loads on the dryer simply is not credible. Exhibit 1, Third Declaration of Dr. Joram, Hopenfeld ("Hopenfeld Declaration 3") ¶ 6. A valid steam dryer aging management program must include some means of estimating and predicting stress loads on the steam dryer, and determining that peak loads will fall below ASME fatigue limits. Hopenfeld Declaration ¶ 5.

Entergy represents that it did conduct this analysis as part of the Vermont Yankee EPU power ascension testing using the ACM and CFD models.

Hoffman Declaration ¶¶ 11-13. Entergy now proposes sole reliance on visual inspection and plant parameter monitoring during the renewed license period. Such reliance must be based on Entergy's previous ACM/CFD-based predictions that stress loads on the dryer will not cause fatigue failures. Hopenfeld Declaration ¶ 7. NEC's concerns regarding the validity of the ACM and CFD models and the stress and fatigue analysis Entergy conducted using these models therefore remain current and relevant.

New England Coalition, Inc.'s Opposition to Entergy's Motion for, Summary Disposition of NEC's Contention 3' (Steam Dryer) (May 9, 2007) at 4.

Both Entergy and the NRC Staff now contend that Entergy's steam dryer aging management program does in fact rely on the steam dryer modeling conducted during EPU implementation for knowledge of dryer stress loads. See, Entergy Initial Statement of 18

Position at 32 ("[T]he loadings on the dryer derive from plant geometries ... that have not changed since the uprate was implemented, so there has been no change to the loadings on the dryer and the resulting stresses. ' Therefore, there is no reason to provide continued instrumentation to measure loadings or further analytical efforts."); NRC Staff Initial Statement of Position at 19 (The Staff's position is that stress analysis as a means of estimating and predicting stress loads during operations "is not necessary because the results of the EPU power ascension program demonstrated that the pressure loads during the EPU operations do not result in stress on the steam dryer that exceed ASME-fatigue stress limits.").

In light of the above-discussed procedural history, and Entergy's prior representations, the Board must disregard these current contentions that the modeling of the dryer during the EPU power ascension program is a proper basis for aging management.

This issue has not been determined, and the Board took it off the table in its decision of Entergy's Motion for Summary Disposition. The issue now properly before the Board is whether an aging management plan that consists solely of plant parameter monitoring,'and partial visual inspection, uninformed by knowledge of dryer loading, can provide reasonable assurance of public safety.

B. Hopenfeld Rebuttal Dr. Joram Hopenfeld provides the following rebuttal testimony regarding the above-stated issue properly before the Board.

0 . Dr. Hopenfeld testifies that the ability to estimate the probability of formation of loose parts requires knowledge of the cyclic loads on the dryer to ensure that 19

the dryer is not subjected to cyclic stress that would exceed the endurance limit.

Hopenfeld Rebuttal at A28.

0 Dr. Hopenfeld observes that Mr. Hoffman and Mr. Lukens do not provide a single quantitative assessment in support of this position, discussed in A56-62 of their testimony, that the inspection programs atVY ensure that the dryer will not fail. Id.

0 Dr. Hopenfeld disagrees with Entergy witness Mr. Lukens that "operating experience after the EPU (exemplified by the data collected during the 2007 inspection and the subsequent year of monitoring of plant operating parameters) demonstrates that the stresses experienced by the dryer are insufficient to initiate and propagate fatigue cracks." Hopenfeld Rebuttal at A29. r E Dr. Hopenfeld provides a section of the Entergy Condition Report previously filed as Exhibit NEC-JH_59 that includes General Electric's statement that "continued [steam dryer crack] growth by fatigue cannot be ruled out." This section of the Condition Report was previously inadvertently excluded due to a clerical error.

Hopenfeld Rebuttal at A29. Dr. Hopenfeld also disagrees with Entergy witness Mr.

Lukens that the~inspection photographs provided in Entergy's Condition Report, Exhibit NEC-JH59 at 2'8, show that the cracks are inactive. Metallographic examinations would be required to demonstrate this, not remote camera photos: Hopenfeld Rebuttal at A3 1.

0 Dr. Hopenfeld observes that IGSCC cracks that now exist in the VY steam dryer can provide sites for corrosion attack which would in turn accelerate crack growth under cycling loading. The rate of crack propagation would depend on load intensities and duration. Id.

20

• Dr. Hopenfeld disagrees with Entergy witness Mr. Hoffman that design basis loads ("DBA") cannot cause dryer failure. Hopenfeld Rebuttal at A32.

a Dr. Hopenfeld disagrees with Entergy witness Mr. Hoffman that it is not necessary to estimate and predict dryer stresses because "[c]onfirmation that stresses on the VY steam dryer remain within fatigue limits is provided daily by the fact that the dryer has been able to withstand without damage the increased loads imparted on it during power ascension and for the two years of operation since EPU was implemented."

Hopenfeld Rebuttal at A33. Vibration fatigue is a time-related phenomenon; the fact that the dryer has not failed to date is not at all an indication that it will not fail in the future.

Id.

0 Dr. Hopenfeld testifies that Entergy has not provided a quantitative jI estimate of the probability of crack detection, but should have done so, since the entire dryer is not accessible to visual inspection. Hopenfeld Rebuttal at A35.

IV. NEC CONTENTION 4 (Flow-Accelerated Corrosion)

NEC's rebuttal evidence concerning Contention 4 is contained in the prefiled*

rebuttal testimony of Dr. Joram Hopenfeld, Exhibit NEC-JH_63 at 24-41; additional rebuttal Exhibits NEC-JH_70- NEC-JH_72; the prefiled rebuttal testimony of Dr. Rudolf Hausler, Exhibit NEC-RH_04; and Dr. Hausler's report titled "Flow Assisted Corrosion (FAC) and Flow Induced Localized Corrosion: Comparison and Discussion," Exhibit NEC-RH_05.

Entergy witness Dr. Horowitz has testified that it is not necessary to recalibrate or "benchmark" the CHECWORKS model with plant inspection data following a twenty 21

percent power uprate. Joint Declaration of Jeffrey S. Horowitz and James C. Fitzpatrick on NEC Contention 4- Flow-Accelerated Corrosion at A33, 34. Rather, Dr. Horowitz contends that the only update to the CHECWORKS model that is necessary following a twenty percent power uprate is the input of new values for flow rate and temperature into the model. Horowitz at A33, 34. Dr. Horowitz bases these assertions on his view that

"[flow-accelerated corrosion (FAC)] wear rates vary roughly with velocity and do not increase with velocity in [a] non-linear (exponential) manner. . . .", Horowitz at A49, and his beliefs that FAC is not fundamentally a local phenomena, and the CHECWORKS model can accurately predict any variations in FAC rates related to geometric features.

Dr. Horowitz contends that the CHECWORKS model accounts for any localized variations in FAC associated with geometric features through the use of '"geometric factors' to relate the maximum degradation occurring in a component, such as an elbow, to the degradation predicted to occur in a straight pipe." Horowitz at A47, A48.

Dr. Hopenfeld and Dr. Hausler disagree with Dr. Horowitz that recalibration of the CHECWORKS model is unnecessary following substantial changes in flow velocity and'changes in temperature, and respond regarding Dr. Horowitz's grounds for this opinion as follows.

M Dr. Hausler testifies that the linear relationship between FAC rates and fluid velocity transitions to an exponential one as the local turbulence becomes such that erosional features become manifest. Whether such transition actually occurs when flow velocity increases following a power uprate must be determined experimentally. Hausler Rebuttal at A5, Exhibit NEC-RH 05.

22

• Dr. Hopenfeld stresses that "FAC is fundamentally a local phenomenon due to variations of local turbulence in curved pipe, nozzles, tees, orifices, etc," and that corrosion rates can be expected to "vary with location depending on the intensity of the local turbulence." Hopenfeld Rebuttal at A42, A52, A53, A54 Healso disagrees with Dr. Horowitz that the rate of FAC corresponds weakly with the velocity, and varies less than linearly with time, and disputes the relevance of the data Dr. Horowitz cites in support of his position. Hopenfeld Rebuttal at A41, A46, A53, A55.

0 Dr. Hausler does not agree that the CHECWORKS model, or any model, can fully account for variations in the rate of FAC due to geometric features and discontinuities. Hausler Rebuttal at A6; Exhibit NEC-RH_05. Some things cannot be specified. For example, the internal residual weld bead from the root pass 'maybe 1/8 inch high in one case, and 1/4 inch high in another case. Id. The upstream and downstream turbulence surrounding the weld bead will be more severe in the latter case, and a power uprate may disproportionately affect the flow over the larger bead. Id.

0 Dr. Hopenfeld observes that, while Dr. Horowitz denies the need to recalibrate CHECWORKS, he recognizes the need to increase the FAC inspection scope by 50% to account for the power uprate. Hopenfeld Rebuttal at A48. Entergy does not disclose what fraction of the total FAC susceptible area in the VY plant the proposed increased monitoring would represent, and its significance is therefore entirely unclear.

Id.

Both Dr. Hopenfeld and Dr. Hausler take issue with Dr. Horowitz's definition of FAG as corrosion in proportion to the flow rate, Horowitz at A46, and observe that this definition excludes the more severe forms of localized corrosion - erosion-corrosion, 23

impingement and cavitation. Hausler Rebuttal at A6; Exhibit NEC-RH_05; Hopenfeld Rebuttal at A45. Both Hopenfeld and Hausler observe that this definition of FAC is entirely arbitrary. Erosion-corrosion, impingement and cavitation are extensions of FAC as the local flow intensity due to turbulence increases. The transition from one to the others is continuous and difficult to identify. Id. If CHECWORKS is unable to predict these more severe forms of localized corrosion related to high flow rates, which can particularly occur after a power uprate, then this is a serious shortcoming of the model and its application. Id.

Dr. Hausler and Dr. Hopenfeld also address the following additional issues:

0 Dr. Hausler observes that the accuracy of CHECWORKS has been said to be within +/- 50%, but this statement is based on an erroneous interpretation of the graphic representation of predicted vs. measured wear. Hausler Rebuttal at A6; Exhibit NEC-RH 05. Actually, the accuracy is within a factor of 2 - the measured wear rates range from twice the prediction to half the prediction. Id! A factor of two difference between measured and predicted 'corrosion [or corrosion rate] can be quite significant with respect toselecting a particular item (line) for inspection during a refueling outage.

Id.

0 Dr. Hopenfeld disagrees with Dr. Horowitz's evaluation of industry FAC experience, and his contention that this experience demonstrates the e}fficacy of CHECWORKS. Hopenfeld Rebuttal at A39, A40, A49, A52, A53. Dr. Hopenfeld specifically disagrees that, in assessing industry FAC experience, a distinction should be drawn between pipe failures due to leaks and failures due to ruptures. Hopenfeld Rebuttal at A44, A53.

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• Dr. Hopenfeld faults Entergy for its failure to specify the total FAC-susceptible area that is inspected during a typical outage. Hopenfeld Rebuttal at A43.

0 Dr. Hopenfeld disputes Dr. Horowitz's suggestion that the oxygen concentration at VY did not change in 2003. Hopenfeld Rebuttal at A5 1.

V. CONCLUSIONS Extended operation of VYNPS as Entergy hasproposed in its LRA will jeopardize public health and safety. The LRA should be denied unless the important issues addressed by NEC's Contentions 2A, 2B, 3 and 4 are resolved.

June 2, 2008 New England Coalition, Inc.

by:

Andrew Raubvoge(

Karen Tyler SHEMS DUNKIEL KASSEL ý&SAUNDERS PLLC For the firm Attorneys for NEC 25