Text

Entergys Motion for Summary Disposition of New England Coalitions Contention 3 (Steam Dryer)
	ML071150066
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	04/19/2007
From:	Travieso-Diaz M; Entergy Nuclear Operations, Entergy Nuclear Vermont Yankee, Pillsbury, Winthrop, Shaw, Pittman, LLP
To:	; Atomic Safety and Licensing Board Panel
	SECY RAS
References
	50-271-LR, ASLBP 06-849-03-LR, RAS 13533
	Download: ML071150066 (156)
	v • d • e

SOS1353 April 19, 2007 UNITED STATES OF AMERICA DOCKETED NUCLEAR REGULATORY COMMISSION USNRC April 19, 2007 (1:2 2 pm)

Before the Atomic Safety and Licensing Board OFFICE OF SECRETARY RULEMAKINGS AND In the Matter of ADJUDICATIONS STAFFI

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Entergy Nuclear Vermont Yankee, LLC

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Docket No. 50-271-LR and Entergy Nuclear Operations, Inc.

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ASLBP No. 06-849-03-LR

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(Vermont Yankee Nuclear Power Station)

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ENTERGY'S MOTION FOR

SUMMARY

DISPOSITION OF NEW ENGLAND COALITION'S CONTENTION 3 (STEAM DRYER)

I.

INTRODUCTION Applicants Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc.

(collectively "Entergy") submit this motion, pursuant to 10 C.F.R. §2.1205(a)' and the Atomic Safety and Licensing Board's ("Board") Initial Scheduling Order (November 17, 2006) ("Initial Scheduling Order") to seek dismissal by summary disposition of the New England Coalition's

("NEC") Contention 3 in this proceeding ("NEC Contention 3"). Entergy asks for summary disposition of the contention on the grounds that no genuine issue as to any material fact exists and Entergy is entitled to a decision as a matter of law. 10 C.F.R. § 2.7 10(d)(2). This motion is supported by the attached Statement of Material Facts regarding NEC Contention 3 as to which Entergy asserts no genuine dispute exists and the Declaration of John R. Hoffman in Support of Entergy's Motion for Summary Disposition of NEC Contention 3 ("Hoffman Decl.").

I 10 CF.R. §2.1205(a) states: "(a) Unless the presiding officer or the Commission directs otherwise, motions for summary disposition may be submitted to the presiding officer by any party no later than forty-five (45) days before the commencement of hearing. The motions must be in writing and must include a written explanation of the basis of the motion, and affidavits to support statements of fact. Motions for summary disposition must be served on the parties and the Secretary at the same time that they are submitted to the presiding officer."

OM~e*6C' 56C7

II.

STATEMENT OF FACTS NEC Contention 3 asserts that Entergy's license renewal application for the Vermont Yankee Nuclear Power Station ("VY" or "VYNPS") ("Application") 2 should be denied because it "does not include an adequate plan to monitor and manage aging of the steam dryer during the period of extended operation." NEC's "Petition for Leave to Intervene, Request for Hearing, and Contentions" dated May 26, 2006 ("Petition") at 17.

The Board's rationale for admitting NEC Contention 3 was twofold. First the Board found that the following statements in the Declaration of Dr. Joram Hopenfeld 3 submitted in support of NEC's Petition "demonstrated a 'genuine dispute' under the standards of 1.0 C.F.R. § 2.309(f)(l)(vi)":

[T]he management of cracking at the steam dryer will be in accordance with current guidance per NUREG 1801, GE-SIL-644 and possibly future guidance from BWRRVIP-139, if approved by NRC. No matter which guidance Entergy follows, the status of the existing dryer cracks must be continuously monitored and assessed by a competent engineer.

Entergy's proposed monitoring techniques are not adequate to detect crack propagation and growth because they are not based on actual measurements of crack initiation and growth. Instead, Entergy relies on unproven computer models and moisture monitors which only indicate that the dryer was already damaged.

The estimated fatigue loads on the dryer are based on theoretical calculations of two computer models: the [CFD] Model and the [AC] Model. Neither the CFD nor the ACM were benchmarked against properly scaled dryer structure and therefore their predictions are subject to large uncertainties.

Memorandum and Order (Ruling on Standing, Contentions, Hearing Procedures, State Statutory Claim, and Contention Adoption), LBP-06-20, 64 N.R.C. 131, 190 (2006), ("LBP-06-20") quoting Hopenfeld Decl., ¶¶ 18-19. Second, the Board ruled that:

2 Vermont Yankee Nuclear Power Station, License Renewal Application (January 25, 2006), available in the NRC ADAMS system with Accession No. ML060300085.

3 Petition Exh. 7, Declaration of Dr. Joram Hopenfeld (May 12, 2006) ("Hopenfeld Decl.").

2

"since Entergy's existing license continues until 2012, its application for a license renewal necessarily only involves aging management matters after that date.

Steam dryer monitoring and inspection plans for the time period prior to 2012 are not directly relevant to, nor dispositive of, our ruling on NEC Contention 3 except to the extent that Entergy's license renewal application, or other materials properly before this Board at this stage in the proceeding, indicates a commitment to continue existing programs."

Id. at 189, emphasis in original.

As will be seen, the bald statements in Dr. Hopenfeld's Declaration are refuted by indisputable matters of record. There are no material facts in dispute that warrant holding a hearing on this contention.

III.

ENTERGY IS ENTITLED TO

SUMMARY

DISPOSITION A.

LEGAL STANDARDS FOR

SUMMARY

DISPOSITION Motions for summary disposition are available in 10 C.F.R. Part 2, Subpart L proceedings. They may be filed up to 45 days before the commencement of a hearing, unless the presiding officer orders otherwise. 10 C.F.R. §2.1205(a).4 In ruling on motions for summary disposition, the Board is to apply the standards in subpart G of 10 C.F.R. Part 2. Id., §2.1205(c).

The standards for summary disposition under Subpart G are defined in 10 C.F.R. §2.710, which states that the "presiding officer shall render the decision sought if... there is no genuine issue as to any material fact and... the moving party is entitled to a decision as a matter of law." Id.,

§2.710(d)(2). The Commission's requirements for summary disposition are satisfied with respect to NEC Contention 3 because there is no genuine issue of disputed fact that would require a hearing and Entergy is entitled to a favorable decision as a matter of law.

In its Initial Scheduling Order, the Board set June 15, 2007 as the deadline for filing motions for summary disposition herein. Initial Scheduling Order at 7.

3

Under the NRC Rules of Practice, a moving party is entitled to summary disposition of a contention as a matter of law if the filings in the proceeding, together with the statements of the parties and the affidavits, demonstrate that there is no genuine issue as to any material fact. The Rules "long have allowed summary disposition in cases where there is no genuine issue as to any material fact and where the moving party is entitled to a decision as a matter of law." Carolina Power & Light Co. (Shearon Harris Nuclear Power Plant), CLI-01-11, 53 N.R.C. 370, 384 (2001) (internal quotations omitted); Advanced Medical Sys., Inc. (One Factory Row, Geneva, Ohio), CLI-93-22, 38 N.R.C. 98, 102-03 (1993). The Commission has held that summary disposition is appropriate "[a]bsent any probative evidence supporting [a party's] claims......

Advanced Medical Sys., Inc. (One Factory Row, Geneva, Ohio), CLI-94-06, 39 N.R.C. 285, 309-310 (1994), affid, Advanced Medical Sys., Inc. v. NRC, 61 F.3d 903 (6th Cir. i 995)(Table).

Commission case law is clear that for there to be a genuine issue, "the factual record, considered in its entirety, must be enough in doubt so that there is a reason to hold a hearing to resolve the issue." Cleveland Electric Illuminating Co. (Perry Nuclear Power Plant, Units 1 and 2), LBP 46, 18 N.R.C. 218, 223 (1983). Summary disposition "is a useful tool for resolving contentions that.., are shown by undisputed facts to have nothing to commend them." Private Fuel Storage, L.L.C. (Independent Fuel Storage Installation), LBP-01-39, 54 N.R.C. 497, 509 (2001).

"'Demonstrably insubstantial issues'... should be decided pursuant to summary disposition procedures...." Louisiana Power and Light Co. (Waterford Steam Electric Station, Unit 3),

LBP-81-48, 14 N.R.C. 877, 883 (1981) (citing Houston Lighting and Power Co. (Allens Creek Nuclear Generating Station, Unit 1), ALAB-590, 11 N.R.C. 542 (1980)).

Those principles apply here. Lacking any genuine factual dispute, NEC Contention 3 has "nothing to commend" it for further litigation in this proceeding and should be dismissed.

4

B.

THERE IS NO FACTUAL DISPUTE REQUIRING LITIGATION The key facts relevant to NEC Contention 3 are uncontested or beyond dispute. In its License Renewal Application, Entergy addressed aging management of the VY steam dryer as follows:

Cracking due to flow-induced vibration in the stainless steel steam dryers is managed by the BWR Vessel Internals Program. The BWR Vessel Internals Program currently incorporates the guidance of GE-SIL-644, Revision 1. VYNPS will evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document.

Application, § 3.1.2.2.11 "Cracking due to Flow-Induced Vibration."

The guidance in the reactor vendor's document GE-SIL-644 includes detailed recommendations for monitoring of plant operational parameters that are indicative of potential steam dryer cracking and for steam dryer inspections during refueling outages. Hoffman Decl.,

IN 21-22. Entergy will implement that guidance at VY during the license renewal period. Id., ¶ 23.

Entergy has in fact been following the guidance in GE-SIL-644 since the extended power uprate ("EPU") of the VY facility was completed in 2006. Id. Implementation of that guidance is required by a condition to the VY operating license that was imposed when the EPU was approved. Id., ¶ 17.

License Renewal Application, § 3.1.2.2.11 also commits to evaluate draft industry standard BWRVIP-139 once it is approved by the NRC Staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the Staff of VYNPS's exceptions to that document. Any commitments made by Entergy will be consistent with the NRC regulatory requirements and guidance for aging management of plant components. Id.,¶ 5

25. VY has made a licensing commitment to "continue inspections in accordance with the Steam Dryer Monitoring Program, Revision 3 [i.e., the current inspection and monitoring program] in the event that the BWRVIP-139 is not approved prior to the period of extended operation." VY Licensing Renewal Commitment List, Commitment No. 37; Hoffman Decl., ¶ 25.

Dr. Joramr Hopenfeld, NEC's consultant, challenges the aging management program for the VY steam dryer during the license renewal period on two grounds: (1) that Entergy relies on unproven computer models to assess dryer performance, Declaration of Dr. Joram Hopenfeld, dated May 12, 2006 ("Hopenfeld Decl.") at ¶ 19; and (2) that Entergy did not monitor steam dryer loads reliably during the power ascension phase of implementing the EPU because the monitoring equipment used "does not measure crack propagation directly (because the strain gages are a distance away from the dryer) and therefore analytical tools would be required to interpret the data." Second Declaration of Joram Hopenfeld, dated June 27, 2006 at ¶ 14.

Neither challenge asserted by Dr. Hopenfeld is supported by any probative evidence that his concerns are relevant to this proceeding.

Dr. Hopenfeld's concerns are clearly irrelevant to the management of steam dryer performance during the license renewal period. The computer models cited by Dr. Hopenfeld were only used to estimate the peak loads on the steam dryer as a forward looking prediction that no unacceptable fatigue loadings would develop once the power uprate was implemented.

Hoffman Decl., ¶ 30.

The proposed program for monitoring and managing the aging of the VY steam dryer neither requires the use of computer models nor relies on the result of analyses using those models. d., I 19, 24. Also, the proposed aging management program for the VY steam dryer 6

does not use strain gages to measure pressure fluctuations on the main steam piping indicative of loadings on the dryer. Id., ¶ 27.

The proposed aging management program for the steam dryer during the license renewal period is based solely on monitoring of plant parameters and periodic visual examinations of the steam dryer in accordance with accepted industry guidance. Id., ¶ 23. Dr. Hopenfeld has not challenged this guidance. Therefore, there is no probative evidence to support the applicability of the concerns raised by NEC and its consultant Dr. Hopenfeld to the license renewal period.

The concerns are plainly irrelevant and do not raise issues of material fact that would bar summary disposition of this contention.

C.

ENTERGY IS ENTITLED TO A FAVORABLE DECISION AS A MATTER OF LAW There is no genuine issue on a material fact regarding NEC Contention 3 that could result in the denial of Entergy's Application. Accordingly, Entergy is entitled to summary disposition of the contention as a matter of law.

IV, CONCLUSION As demonstrated above, none of the objections to the aging management program for the VY steam dryer raised by NEC and its consultant in Contention 3 are relevant to the instant license renewal proceeding. Accordingly, there is no genuine dispute of material fact remaining to litigate and Entergy is entitled to a decision as a matter of law on the contention 3.

CERTIFICATION In accordance with 10 C.F.R. §2.323(b) and para. 8 of the Board's Initial Scheduling Order, counsel for Entergy has made a sincere effort to discuss the facts raised in this motion 7

with the other parties in an attempt to narrow the issues. Counsel for Entergy was able to hold such discussions with the NRC Staff but has not been successful in doing so with NEC.

Respectfully Submitted, A%441 David R. LewisU Matias F. Travieso-Diaz PILLSBURY WINTHROP SHAW PITTMAN LLP 2300 N Street, N.W.

Washington, DC 20037-1128 Tel. (202) 663-8000 Counsel for Entergy Dated: April 19,2007 8

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

)

Entergy Nuclear Vermont Yankee, LLC

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Docket No. 50-271-LR and Entergy Nuclear Operations, Inc.

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ASLBP No. 06-849-03-LR

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(Vermont Yankee Nuclear Power Station) )

STATEMENT OF MATERIAL FACTS REGARDING NEC CONTENTION 3 ON WHICH NO GENUINE DISPUTE EXISTS Applicants Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc.

(collectively "Entergy") submit, in support of their motion for summary disposition of NEC Contention 3, that there is no genuine issue to be heard with respect to the following material facts.

1. In connection with its extended power uprate ("EPU") application for the Vermont Yankee Nuclear Power Station ("VY"), Entergy performed two types of complementary analyses to evaluate the pressure loads acting on the steam dryer during operation at EPU conditions:

the computational fluid dynamics ("CFD") and acoustic circuit model ("ACM") analyses.

The calculated stresses obtained from the CFD and ACM analyses were inputs to a finite element analysis model that calculated peak stresses for specific steam dryer locations.

Those peak stresses were compared to the fatigue limits for the dryer material specified in the ASME Code. Declaration of John R. Hoffmnan in Support of Entergy's Motion for Summary Disposition of NEC Contention 3, ("Hoffinan Decl."), ¶ 11. The resulting maximum calculated stresses for EPU conditions were found to be well within the ASME fatigue endurance limit. Id., ¶12.

2. Entergy also installed 32 additional strain gages on the main steam line piping during the fall 2005 refueling outage. The data measured by the strain gages and other complementary 9

instrumentation were monitored frequently during EPU power ascension to verify that the structural limits for the steam dryer were not reached. Id., ¶ 13.

3. As an independent confirmation of the structural integrity of the steam dryer during operation at uprate levels, VY instituted a program of dryer monitoring and inspections to provide assurance that the structural loadings under EPU conditions did not result in the formation or propagation of vibration-induced cracks on the dryer. I, ¶ 14.

4. The monitoring and inspection program measured the performance of the VY steam dryer during power ascension testing and operation as power was increased from the original licensed power level to full EPU conditions. Following completion of EPU power ascension testing, Entergy has continued to periodically monitor plant operational parameters that could be indicative of loss of steam dryer structural integrity. Id., ¶ 15.

5. In addition to monitoring of plant operational parameters, the monitoring and inspection program calls for the steam dryer be inspected during plant refueling outages in the fall of 2005, spring of 2007, fall of 2008, and spring of 2010. The inspections are conducted in accordance with the recommendations of General Electric's Service Information Letter

("SIL") No. 644, Revision 1 (Nov. 9, 2004), ADAMS Accession No. ML050120032 ("GE-SIL-644"). The provisions of GE-SIL-644 also govern the manner in which monitoring of plant parameters is being conducted since VY has started operating at EPU levels. Id., ¶ 16.

6. This commitment to follow the GE-SIL-644 recommendations is reflected in a licensing condition by which Entergy is required to take specified actions to ensure that the structural integrity of the VY steam dryer is maintained, as set forth in the VY operating license. Id. ¶ 17.

7. As required by the VY operating license, VY is operating under a program that provides for long-term monitoring of plant parameters potentially indicative of steam dryer failure, plus inspections at three consecutive refueling outages, all in accordance with GE-SIL-644. Id. ¶

18. The monitoring that has been performed under the EPU program, and the inspections conducted to date, confirm that fatigue-induced cracking of the VY steam dryer is not occurring. Id.

8. The ongoing steam dryer monitoring and inspection program does not rely on the CFD and ACM analyses. Id., ¶ 19.

10

9. In its License Renewal Application, Entergy addressed aging management of the VY steam dryer as follows:

Cracking due to flow-induced vibration in the stainless steel steam dryers is managed by the BWR Vessel Internals Program. The BWR Vessel Internals Program currently incorporates the guidance of GE-SIL-644, Revision 1. VYNPS will evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document.

Application, § 3.1.2.2.11 "Cracking due to Flow-Induced Vibration."

10. VY is implementing the applicable monitoring and visual inspection guidelines in GE SIL-644. Hoffman Decl., ¶ 22.

11. The aging management program for the VY steam dryer during the twenty-year license renewal period will consist of well-defined monitoring and inspection activities that are identical to those being conducted during the current post-EPU phase. The monitoring program will continue for the entire license renewal period. The inspection activities will include visual inspections of the steam dryer every two refueling outages consistent with GE and BWR Vessel Internals Program (VIP) requirements. Id., ¶ 23.

12. The aging management plan for the steam dryer at VY for the license renewal period does not depend on, or use, the CFD and ACM computer codes or the analyses conducted using those codes. Id.. ¶ 24.

13. Dr. Hopenfeld states that "[n]o matter which guidance Entergy follows, the status of the existing dryer cracks must be continuously monitored and assessed by a competent engineer." Hopenfeld Decl. at ¶ 19. Entergy's steam dryer aging management plan does what Dr. Hopenfeld requires, since it is based on continuous monitoring of plant parameters whose value is indicative of potential dryer cracking and crack propagation. Hoffman Decl.,

¶26.

14. Dr. Hopenfeld also asserts that "Entergy's monitoring equipment does not measure crack propagation directly (because the strain gages are a distance away from the dryer) and therefore analytical tools would be required to interpret the data." Second Declaration of Joram Hopenfeld, dated June 27, 2006 at ¶ 14. The purpose of the monitoring equipment that was utilized during the EPU power ascension phase (strain gages installed on the main steam lines) was not to measure crack propagation, but to monitor pressure fluctuations in the 11

steam piping that translate to pressure loads and ultimately to stresses on the steam dryer, to ensure that values were below the maximum levels set by the ASME Code. The strain gages will not be used in the aging management program for the steam dryer during the license renewal period. Hoffmnan Decl., ¶ 27.

15. Dr. Hopenfeld also states that "Entergy has not demonstrated that the dryer will not fail and scatter loose parts in between the visual inspections, especially during design basis accidents, DBA." Second Declaration of Joram Hopenfeld at ¶ 15. The capability of the dryer to withstand design basis loads was demonstrated by the structural analyses and stress measurements performed as part of the EPU. Only superficial cracks have been observed in the VY steam dryer and those cracks have not shown any measurable growth in the successive dryer inspections. Periodic visual examinations of the steam dryer in accordance with the license condition will continue to ensure that unacceptable flaw development or growth is not occurring. Hoffman Decl., ¶ 28.

16. The purpose of the ACM and CFD analyses was to develop peak loads for the analysis of the steam dryer as a forward looking prediction that no unacceptable fatigue loadings would develop as a the power uprate was being implemented. The plant parameter monitoring and inspection program does not rely on the analyses performed during the implementation of the EPU and is sufficient to ensure satisfactory steam dryer performance during the license renewal period. Id., ¶ 30.

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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board 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 CERTIFICATE OF SERVICE I hereby certify that copies of"Entergy's Motion for Summary Disposition of New England Coalition's Contention 3 (Steam Dryer)" dated April 19, 2007 and "Declaration of John R. Hoffman in Support of Entergy's Motion for Summary Disposition of NEC Contention 3" were served on the persons listed below by deposit in the U.S. Mail, first class, postage prepaid, or with respect to Judge Elleman by overnight mail, and where indicated by an asterisk by electronic mail, this 19thth day of April, 2007.

Administrative Judge Alex S. Karlin, Esq., Chairman Atomic Safety and Licensing Board Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 ask2@nrc.gov

Administrative Judge Dr. Richard E. Wardwell Atomic Safety and Licensing Board Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 rew@nrc.gov

Administrative Judge Dr. Thomas S. Elleman Atomic Safety and Licensing Board 5207 Creedmoor Road, #101, Raleigh, NC 27612.

tse@nrc.gov; elleman@eos.ncsu.edu Office of Commission Appellate Adjudication Mail Stop 0-16 C1 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001

Mitzi A. Young, Esq.

Mary C. Baty, Esq.

Office of the General Counsel Mail Stop 0- 15 D21 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001may@nrc.gov; mcbl @nrc.gov

Anthony Z. Roisman, Esq.

National Legal Scholars Law Firm 84 East Thetford Road Lyme, NH 03768 aroisman(-nationallegalscholars.com

Secretary Att'n: Rulemakings and Adjudications Staff Mail Stop 0-16 C1 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 secy@nrc.gov, hearingdocket~nrc.gov Atomic Safety and Licensing Board Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001

Sarah Hofinann, Esq.

Director of Public Advocacy Department of Public Service

-112 State Street - Drawer 20 Montpelier, VT 05620-2601 Sarah.hofinann@state.vt.us

Ronald A. Shems, Esq.

Karen Tyler, Esq.

Shems, Dunkiel, Kassel & Saunders, PLLC 9 College Street Burlington, VT 05401 rshems(sdkslaw.com ktyler@sdkslaw.com

Jennifer J. Patterson, Esq.

Senor Assistant Attorney General Environmental Protection Bureau 33 Capitol Street Concord, NH 03301 Jennifer.Patterson@doj.nh.gov AAýI Matias F. Travieso-Diaz 2

April 18, 2007 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of

)

Entergy Nuclear Vermont Yankee, LLC

)

Docket No. 50-271-LR and Entergy Nuclear Operations, Inc.

)

ASLBP No. 06-849-03-LR

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(Vermont Yankee Nuclear Power Station)

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DECLARATION OF JOHN R. HOFFMAN IN SUPPORT OF ENTERGY'S MOTION FOR

SUMMARY

DISPOSITION OF NEC CONTENTION 3 John R. Hoffman states as follows under penalties of perjury:

I.

Introduction

1. Prior to September 2006 1 was employed by Entergy Nuclear Operations, Inc.

("Entergy") and had, among other responsibilities, that of Project Manager for the License Renewal Project at the Vermont Yankee Nuclear Power Station ("VY"). I retired from Entergy's employment in September 2006. I am currently a consultant and provide this declaration in support of Entergy's Motion for Summary Disposition of New England Coalition's ("NEC")

Contention 3 ("NEC Contention 3") in the above captioned proceeding.

2. My professional and educational experience is summarized in the curriculum vitae attached as Exhibit 1 to this declaration. Briefly summarized, I have over 37 years of nuclear power engineering experience, and have been associated with VY since 1971.

3. During my employment at VY I had no direct involvement with the power uprate implemented between 2003 and 2006. However, I have reviewed relevant materials and conducted interviews with plant personnel to familiarize myself with the manner in which steam dryer issues were addressed during the uprate process. I have personal knowledge of the manner in which VY intends to address the steam dryer during the period of extended operation.

4. NEC Contention 3 asserts that: "Entergy's License Renewal Application does not include an adequate plan to monitor and manage aging of the steam dryer during the period of extended operation." This contention lacks technical or factual basis.

5. I will demonstrate that the plan proposed by VY for monitoring and managing aging of the steam dryer during the period of extended operation is adequate and is consistent with manufacturer recommendations and the practice in the industry.

II.

Background

6. In a boiling water reactor ("BWR"), the steam dryer is a stainless steel component whose function is to remove moisture from the steam before it leaves the reactor. The dryer is mounted in the reactor vessel above the steam separator assembly and is latched to the inside of the vessel wall below the steam outlet nozzles. Wet steam flows upward and outward through the dryer. Moisture is removed by impinging on the dryer vanes and flows down through drains to the reactor water in the downcomer annulus below the steam separators.

7. The steam dryer does not perform a safety function and is not required to prevent or mitigate the consequences of accidents. The VY steam dryer is a non-safety-related, non-Seismic Category I component. Although the steam dryer is not a safety-related component, the assembly is designed to withstand design basis events without the generation of loose parts and the dryer is designed to maintain its structural integrity through all the plant operating conditions.

8. On September 10, 2003, Entergy submitted its application to increase the maximum VY authorized power level from 1593 megawatts thermal ("MWt") to 1912 MWt. This power increase represented an increase of approximately 20% above original rated thermal power and was known as an "extended power uprate" or "EPU". Letter from J. Thayer to NRC, "Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271) Technical Specification Proposed Change No. 263 Extended Power Uprate" (Sept. 10, 2003) ("EPU Application"), ADAMS Accession No. ML032580089.

9. In 2002, steam dryer cracking and damage to components and supports for the main steam and feedwater lines were observed at the Quad Cities Unit 2 nuclear power plant. These conditions were detected after implementation of an extended power uprate similar to the one proposed in 2003 for VY. It was determined that loose parts shed by the dryer due to flow-induced vibration had damaged the supports.

10. In response to this experience and to concerns about steam dryers at other nuclear power plants Entergy substantially modified the steam dryer at VY during the spring 2004 refueling outage to improve its capability to withstand potential adverse flow effects that could result from operation of the plant at EPU levels. The modifications, intended to increase the structural strength of the dryer, are described in Attachment 2 to Supplement 8 (dated July 2, 2004) to the EPU Application, ADAMS Accession No. ML042090103.

1H1.

VY Steam Dryer Analyses in Support of EPU

11. In addition to making substantial physical modifications to the VY steam dryer, Entergy conducted two categories of activities to assure that the structural integrity of the dryer would be maintained during EPU operations. The first category of activities included performing two types of complementary analyses to evaluate the pressure loads acting on the steam dryer during operation at EPU conditions: the computational fluid dynamics ("CFD") and acoustic circuit model ("ACM") analyses. The calculated loads obtained from the CFD and ACM analyses were inputs to a finite element model (FEM) that calculated peak stresses for specific steam dryer locations. This FEM output was then compared to the fatigue limits for the dryer material specified in the ASME Code.

12. The resulting maximum calculated stresses for EPU conditions were found to be well within the ASME fatigue endurance limit. (The endurance limit is the level of stress that a material can withstand over an infinite number of cycles without failure.) The analyses indicated that there is significant margin between the magnitude of the potential stresses imposed on the steam dryer and the level at which fatigue failure would occur.

13. Entergy also installed 32 additional strain gages on the main steam line piping during the fall 2005 refueling outage (beyond 16 strain gages installed previously). The data measured by the strain gages and other complementary instrumentation were monitored frequently during EPU power ascension to verify that the structural limits for the steam dryer were not reached.

This data monitoring was accomplished as the power levels were increased towards EPU.

IV.

Steam Dryer Monitoring and Inspection Program During Implementation of EPU

14. As a second set of activities intended to provide independent confirmation of the structural integrity of the steam dryer during operation at uprate levels, VY instituted a program of dryer monitoring and inspections to provide assurance that the structural loadings under EPU conditions did not result in the formation or propagation of vibration-induced cracks on the dryer. The program is described in Attachment 6 to Supplement 33 (dated September 14,2005) to the EPU Application, ADAMS Accession No. ML052650122. The program was reviewed and approved by the NRC and included as a license condition as part of the power uprate license amendment issued on March 2, 2006 (Exhibit 2 hereto).

15. The monitoring and inspection program measured the performance of the VY steam dryer during power ascension testing and operation as power was increased from the original licensed power level to full EPU conditions. The program included taking daily measurements of moisture carryover and periodic measurements of main steam line pressure. Pursuant to the program, following completion of EPU power ascension testing, moisture carryover measurements have continued to be made periodically, and other plant operational parameters that could be indicative of loss of steam dryer structural integrity continue to be monitored.

16. In addition to monitoring of plant operational parameters, the monitoring and inspection program calls for the steam dryer to be inspected during plant refueling outages in the fall of 2005, spring of 2007, fall of 2008, and spring of 2010. The inspections are conducted in accordance with the recommendations of General Electric's Service Information Letter ("SIL")

No. 644, Revision 1 (Nov. 9, 2004), ADAMS Accession No. ML060120032 ("GE-SIL-644").

The provisions of GE-SIL-644 also govern the manner in which monitoring of plant parameters is being conducted since VY started operating at EPU levels. Plant procedures require that the periodic monitoring activities be conducted in a manner consistent with guidance in GE-SIL-644. See Exhibit 3 (VY Operating Procedure OP 0631, Appendix F).

17. The commitment to conduct dryer monitoring and inspections in accordance with the guidance of GE-SIL-644 is reflected in the above referenced license condition, proposed by Entergy in Attachment 1 to Supplement 36 to the EPU Application (October 17, 2005), ADAMS Accession No. ML052940225, and currently in effect. Entergy is committed to a program for ensuring the structural integrity of the VY steam dryer that consists of the following actions, specified in the VY operating license:

2e. Entergy Nuclear Operations, Inc. shall revise the SDMP [steam dryer monitoring program] to reflect long-term monitoring of plant parameters potentially indicative of steam dryer failure; to reflect consistency of the facility's steam dryer inspection program with General Electric Services Information Letter 644, Revision 1; and to identify the NRC Project Manager for the facility as the point of contact for providing SDMP information during power ascension.

5. During each of the three scheduled refueling outages (beginning with the spring 2007 refueling outage), a visual inspection shall be conducted of all accessible, susceptible locations of the steam dryer, including flaws left "as is" and modifications.

6. The results of the visual inspections of the steam dryer conducted during the three scheduled refueling outages (beginning with the spring 2007 refueling outage) shall be reported to the NRC staff within 60 days following startup from the respective refueling outage. The results of the SDMP shall be submitted to the NRC staff in a report within 60 days following the completion of all EPU power ascension testing.

7. The requirements of paragraph 4 above for meeting the SDMP shall be implemented upon issuance of the EPU license amendment and shall continue until the completion of one full operating cycle at EPU. If an unacceptable structural flaw (due to fatigue) is detected during the subsequent visual inspection of the steam dryer, the requirements of paragraph 4 shall extend another full operating cycle until the visual inspection standard of no new flaws/flaw growth based on visual inspection is satisfied.

8. This license condition shall expire upon satisfaction of the requirements in paragraphs 5, 6, and 7 provided that a visual inspection of the steam dryer does not reveal any new unacceptable flaw or unacceptable flaw growth that is due to fatigue.

Exhibit 2 hereto at 2-4.

18. As required by the VY operating license, VY is operating under a program that provides for long-term monitoring of plant parameters potentially indicative of steam dryer failure plus inspections at three consecutive refueling outages, all in accordance with GE-SIL-644. The monitoring that has been performed since implementation of the EPU, and the inspections conducted to date, confirm that fatigue-induced cracking of the VY steam dryer is not occurring.

19. To summarize, Entergy performed two categories of activities in support of its EPU Application: on the one hand, the CFD/ ACM FEM and the associated measurement of stress levels by means of strain gages during power ascension; this set of activities has been completed.

On the other hand, Entergy instituted a monitoring and inspection program, which was initiated during power ascension, is still ongoing, and will be in effect throughout EPU operations. The monitoring and inspection program does not rely on the CFD and ACM analyses.

V.

Steam dryer aging management plan for license renewal period A. Overview

20. In its License Renewal Application, Entergy addresses aging management of the VY steam dryer as follows:

Cracking due to flow-induced vibration in the stainless steel steam dryers is managed by the BWR Vessel Internals Program. The BWR Vessel Intemals Program currently incorporates the guidance of GE-SIL-644, Revision 1. VYNPS will evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document.

License Renewal Application, § 3.1.2.2.11 "Cracking due to Flow-Induced Vibration."

21. GE-SIL-644 recommends that BWR licensees institute a program for the long term monitoring and inspection of their steam dryers. It provides detailed inspection and monitoring guidelines (see SIL-644, ADAMS Accession No. ML050120032, Exhibit 4 hereto, Appendices C and D). With respect to monitoring, the guidelines call for the periodic monitoring of parameters that may be indicative of steam dryer failure, particularly moisture carryover:

Moisture carryover should be monitored weekly:

Statistically evaluate the moisture carryover data and qualitatively determine if there is a significant increasing trend that cannot be explained by changes in plant operational parameters. If an unexplained increasing trend is evident, then collect additional moisture carryover data with consideration for increasing the measurement frequency (e.g., from "once per week" to "once per day").

If the latest moisture carryover measurement is greater than "mean plus 2-sigma" and this increase cannot be explained by changes in plant operational parameters, then obtain a complete set of data for the plant operational parameters (identified above). Compare the current plant operational data with the baseline data to explain the increased moisture carryover (i.e., is there steam dryer damage or not). If an increase in moisture carryover occurs immediately following a rod swap, additional moisture carryover data should be obtained to assure that an increasing trend does not exist. Note that occurrence of steam dryer damage immediately following a rod swap would be highly unlikely.

If the increasing trend of moisture carryover cannot be explained by evaluation of the plant operational data, then initiate plant-specific contingency plans for potential steam dryer damage. If the evaluation of plant data confirms that significant steam dryer damage has most likely occurred, then initiate a plant shutdown.

If there are no statistically significant changes in moisture carryover for an operating cycle, then decreasing the moisture, carryover measurement frequency (e.g., from "once per week" to "once per month") may be considered, provided the highest operating power level is not significantly increased.

GE SIL-644, Rev. 1 (Nov. 2004), Appendix D at 32. As noted above, VY Operating Procedure OP 0631, Appendix F implements this guidance. This monitoring function is to continue for the balance of plant operations.

With respect to inspections, the GE guidelines establish a specific schedule for plants, like VY, that implement a power uprate:

In addition, for plants planning on increasing the operating power level above the OLTP or above the current established uprated power level (i.e., the plant has operated at the current power level for several cycles with no indication of steam dryer integrity issues), the recommendations presented in A (above) should be modified as follows:

B 1. Perform a baseline visual inspection of the steam dryer at the outage prior to initial operation above the OLTP or current power level. Inspection guidelines for each dryer type are provided in Appendix C.

B2. Repeat the visual inspection of all susceptible locations of the steam dryer during each subsequent refueling outage. Continue the inspections at each refueling outage until at least two full operating cycles at the final uprated power level have been achieved. After two full operating cycles at the final uprated power level, repeat the visual inspection of all susceptible locations of the steam dryer at least once every two refueling outages. For BWR/3-style steam dryers with internal braces in the outer hood, repeat the visual inspection of all susceptible locations of the steam dryer during every refueling outage.

B3. Once structural integrity of any repairs and modifications has been demonstrated and any flaws left "as-is" have been shown to have stabilized at the final uprated power level, longer inspection intervals for these locations may be justified.

GE-SIL-644 at 7.

22. Because VY has a BWR-3 steam dryer, the details of the visual inspection program to be implemented are set forth in the corresponding section of GE SIL-644, which is Appendix C,

p. 15-16. VY is implementing the above described applicable monitoring and visual inspection guidelines in GE-SIL-644.

B. Steam Dryer Monitoring and Inspection During License Renewal Period

23. The aging management program for the VY steam dryer during the twenty-year license renewal period will consist of well-defined monitoring and inspection activities that are defined in the GE SIL-644 guidelines and are identical to those being conducted during the current post-EPU phase. Steam dryer integrity will be monitored continuously via operator monitoring of certain plant parameters. VY Off-normal Procedure ON-3178 alerts the operators that any off the following events could be indicative of reactor internals damage and/or loose parts generation: a) sudden drop in main steam line flow >5%; b) >3 inch difference in reactor vessel water level instruments; c) sudden drop in steam dome pressure >2 psig. See Exhibit 5 hereto. In addition, periodic measurements of moisture carryover will be performed, and changes in moisture carryover will be evaluated in accordance with the requirements of GE-SIL-644. See Exhibit 3. This monitoring program will continue for the entire license renewal period.

The inspection activities will include visual inspections of the steam dryer every two refueling outages consistent with GE and BWR Vessel Internals Program (VIP) requirements. The inspections will focus on areas that have been repaired, those where flaws exist, and areas that have been susceptible to cracking based on reactor operating experience throughout the industry.

24. The aging management plan for the license renewal period, consisting of the monitoring and inspection activities described above, does not depend on, or use, the CFD and ACM computer codes or the FEM conducted using those codes.

25. License Renewal Application, § 3.1.2.2.11 also commits to "evaluate BWRVIP-139

.once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document."

BWRVIP-139 is a 2005 industry standard developed by Electric Power Research Institute that provides steam dryer inspection and flaw evaluation guidelines. Those guidelines, currently issued in draft, are essentially the same as the ones contained in the GE SIL standard.. BWRVIP-139 is currently under NRC Staff review, with an evaluation scheduled to be released in mid-2007. See http://www.nrc.gov/about-nrc/reyulatorL/licensing/topical-reports/under-review.html#boiling. If the guidelines in BWRVIP-139 are approved by the Staff, Entergy will evaluate any additional requirements that might result from the NRC's approval for applicability to VY. Any commitments made by Entergy will be consistent with the NRC regulatory requirements and guidance for aging management of plant components. VY has made a licensing commitment to "continue inspections in accordance with the Steam Dryer Monitoring Program, Revision 3 [i.e., the current inspection and monitoring program] in the event that the BWRVIP-139 is not approved prior to the period of extended operation." VY Licensing Renewal Commitment List, Commitment No. 37, Exhibit 6 hereto.

VI.

Response to issues raised by NEC

26. NEC's consultant Dr. Joram Hopenfeld has addressed the steam dryer aging management commitment in the VY License Renewal Application as follows: "The license renewal application states at paragraph 3.1.2.2.11, and Table 3.1.2-2, that the management of cracking in the steam dryer will be in accordance with current guidance per NUREG 1801, GE-SIL-644 and possibly future guidance from BWRVIP-139, if approved by the NRC. No matter which guidance Entergy follows, the status of the existing dryer cracks must be continuously monitored and assessed by a competent engineer." Declaration of Dr. Joram Hopenfeld, dated May 12, 2006 at ¶ 19. Entergy's steam dryer aging management plan, however, does exactly what Dr. Hopenfeld requires, since it is based on continuous monitoring of plant parameters whose value is indicative of potential dryer cracking and crack propagation.

27. Dr. Hopenfeld also asserts that "Entergy's monitoring equipment does not measure crack propagation directly (because the strain gages are a distance away from the dryer) and therefore analytical tools would be required to interpret the data." Second Declaration of Joram Hopenfeld, dated June 27, 2006 at ¶ 14. The purpose of the monitoring equipment that was utilized during the EPU power ascension phase (strain gages installed on the main steam lines) was not to measure crack propagation, but to monitor pressure fluctuations in the steam piping that translate to pressure loads and ultimately to stresses on the steam dryer, to ensure that values were below the maximum levels set by the ASME Code. The strain gages will not be used in the aging management program for the steam dryer during the license renewal period.

28. Dr. Hopenfeld also states that "Entergy has not demonstrated that the dryer will not fail and scatter loose parts in between the visual inspections, especially during design basis accidents, DBA." Id. at ¶ 15. The capability of the dryer to withstand design basis loads was demonstrated by the structural analyses and stress measurements performed as part of the EPU.

It is important to note that only superficial cracks have been observed in the VY steam dryer and those cracks have not shown any measurable growth in the successive dryer inspections.

Periodic visual examinations of the steam dryer in accordance with the license condition will continue to ensure that unacceptable flaw development or growth is not occurring.

29. It is also important to note that there are two types of loading imposed on the steam dryer (as well as other plant components.) There are the normal operating loads that are experienced day-in and day-out over the life of the plant. These loads are generally lower than the design basis accident loads, but because of the long time duration they can induce fatigue damage. The design basis loads are one-time loads. The purpose of the aging management process is to ensure that the condition of plant components is maintained in a status that is consistent with the design basis analyses for all plant conditions.

30. NEC asserts that "Entergy has previously used these computer models to establish a baseline for its steam dryer management program, and integrated code-based predictions into its aging management assessment. NEC's Contention 3 concerns regarding validity of these models are therefore current regardless of whether Entergy will make further use of them." New England Coalition, Inc's Opposition to Entergy's Request for Leave to File Motion for Reconsideration of NEC's Contention 3 (October 12, 2006) at 4. This assertion is incorrect. The purpose of the ACM and CFD analyses was to develop peak loads for the analysis of the steam dryer as a forward looking prediction that no unacceptable fatigue loadings would develop as a the power uprate was being implemented. The plant parameter monitoring and inspection program currently being conducted does not rely on the analyses performed during the implementation of the EPU and is sufficient to ensure satisfactory steam dryer performance during the license renewal period.

VII.

Summary and Conclusions

31. My testimony in this Declaration justifies the following conclusions: (1) the steam dryer aging management plan for license renewal period proposed by Entergy is consistent with the vendor recommendations and industry guidance; (2) the monitoring and inspection activities called for in the plan are the same that the NRC has approved for assuring the structural integrity of the steam dryer during current post-EPU operation; and (3) the steam dryer aging management plan will adequately assure that the dryer's structural integrity will be maintained for all plant normal and transient operating conditions during the license renewal period.

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

Executed on April 18, 2007

JOHN R. HOFFMAN, P.E.

SUMMARY

QUALIFICATIONS:

Mr. Hoffman has more than 37 years of experience in nuclear power plant engineering in support of both PWR and BWR operating reactors. He has directed mechanical, structural, and civil engineers for the Yankee, Maine Yankee, Vermont Yankee, and Seabrook Nuclear Power Stations. He retired from Entergy Nuclear Vermont Yankee in 2006.

EDUCATION, LICENSES AND CERTIFICATIONS:

Lesley College - M.S., Applied Management (1985)

University of Lowell-M.S., Nuclear Engineering (1977)

The Cooper Union for the Advancement of Science and Art - B.E., Mechanical Engineering (1967)

Registered Professional Engineer - Massachusetts, Vermont Plant Certification (SRO Level), Vermont Yankee Nuclear Power Corporation (1990)

PROFESSIONAL EXPERIENCE:

Entergy Nuclear Northeast (2002-2006)

Manager - Engineering Projects (2003-2006) - Manages company resources for VermontYankee Nuclear Power Station dry cask storage and license renewal projects. Also responsible for Entergy engineering procedure transition.

Manager - Design Engineering (2002-2003) - Managed design engineering resources for Vermont Yankee Nuclear Power Station, encompassing the mechanical, structural, electrical, instrument & control and fluid system technical disciplines.

Vermont Yankee Nuclear Power Corporation (1997-2002)

Superintendent of Design Engineering (2000-2002) - Managed design engineering resources for Vermont Yankee Nuclear Power Station, encompassing the mechanical, structural, electrical, instrument & control and fluid systemtechnical disciplines.

Director of Design Engineering (1999-2000) - Managed design engineering resources for Vermont Yankee Nuclear Power Station, encompassing the mechanical, structural, electrical, instrument & control and fluid system technical disciplines.

Manager - Spent Fuel Storage and Decommissioning (1998-1999) - Managed contractor and in-house personnel involved in preparation and review of spent fuel store and decommissioning planning activities for Vermont Yankee Nuclear Power Station.

Task Force Leader - Torus Temperature Analysis Project (1998) - Provided project management for a

multi-disciplinary team involved inperforming a torus temperature analysis for Vermont Yankee Nuclear Power Station.

Project Manager - Design Basis Document Project (1997-1998) - Managed contractor and in-house engineering personnel involved in preparation and review of design basis documents for Vermont Yankee Nuclear Power Station.

Yankee Atomic Electric Company (1971-1997)

Project Manager - Vermont Yankee Design Basis Document Project (1997) - Managed contractor and in-house engineering personnel involved in preparation and review of design basis documents for Vermont Yankee Nuclear Power Station.

Team Leader - Topical Area Reviews (1996-1997) - Managed contractor engineering personnel performing technical reviews for selected topical areas for the Millstone 3 Nuclear Power Station.

Project Manager - Reactor Vessel and Internals Project (1995-1996) - Managed contractor and in-house engineering personnel involved in evaluation of repair options and development of repairs for core shroud for the Vermont Yankee Nuclear Power. Station. Activities included manufacturing follow and USNRC licensing reviews.

Project Engineering Manager, Vermont Yankee Project (1989-1995) - Managed engineering department that provides dedicated engineering support to the Vermont Yankee Nuclear Power Station in the areas of electrical, mechanical, I&C, and systems engineering, Oversaw design changes, environmental qualification program, erosion/corrosion program, MOV engineering, and fracture mechanics evaluations.

Manager, Mechanical Services Group (1988-1989) - Managed inservice inspections, MOV testing services, materials engineering, and NDE engineering in support of BWRs and PWRs.

Principal Engineer, Vermont Yankee Project (1986-1988) - Provided project coordination for spent fuel pool expansion. Developed and licensed long-term application of weld overlays to core spray nozzles at Vennont Yankee Nuclear Power Station.

Engineering Supervisor, Recirc Pipe Replacement (1984-1986) - Directed engineering activities related to the design and installation of a replacement recirculation system at Vermont Yankee Nuclear Power Station. Controlled all contracted engineering activities.

Lead Mechanical Engineer, Vermont Yankee Project (1983-1984) - Directed a group of mechanical engineers assigned to the Vermont Yankee Project. Managed and performed seismic analyses, component evaluations to code requirements, and structural design.

Assistant to the Vice President (1982-1983) - Reported to the Vice President, Engineering and Operations. Provided technical consultation and project coordination for major plant modifications including seismic support upgrades, incore instrumentation system repair for the Yankee Nuclear Power Station, and weld overlay design and application for theVermont Yankee Nuclear Power Station. Helped license Vermont Yankee as the first plant authorized for multi cycle operation with weld overlays. Co-authored a computer program to develop plant heatup/cooldown curves.

2

Mechanical Engineering Manager (1975-1982) - Directed mechanical engineering staff in the fields of mechanical, structural, materials, and NDE engineering. Provided design and operating support for BWRs and PWRs. Responsible for IEB 79-02 and 79-14 resolution for the Yankee, Vermont Yankee, and Maine Yankee Nuclear Power Stations. Avoided plant shutdowns relative to seismic adequacy questions.

Engineer, Mechanical Engineering Group (1971-1975) - Provided engineering in support of the design, licensing, and operation of the Yankee plants.

Pratt and Whitney Aircraft (1969-1971)

Test Engineer - Developed, conducted, and evaluated tests to qualify aircraft engine bearings and seals.

Westinghouse Bettis Atomic Power Laboratory (1967-1969)

Engineer, Primary Coolant Systems - Provided technical support for plant modifications in the U.S.

Navy nuclear submarine program.

PROFESSIONAL AFFILIATIONS AND HONORS:-

American Society of Mechanical Engineers, Member (1968-2006)

Electric Power Research Institute (EPRI), Systems and Materials Task Force (1980-86); BWR Owners Group for IGSCC Research (1975-88); Plant Materials Subcommittee (1975-1998)

Atomic Industrial Forum National Environmental Study Program, Task. Force on BWR Repairs (1985-1986)

BWR Owners Group Committee on Internals Inspection and Repair (1990-1994)

Recipient of EPRI "First Use" Award for Temperbead Repair Using an Inconel Safe-End Overlay Procedure (1990)

Recipient of EPRI "Technology Transfer Award" for Application of EPRI-Developed IGSCC Resistant Materials (1990)

Recipient of EPRI "Innovator" Award for Application of EPRI-Developed Crack Growth Data to Evaluate Flaws (1993)

SELECTED PUBLICATIONS:

1.

"Field Application of a Non-Post Weld Heat Treat Weld Overlay Repair to an Alloy Steel Reactor Pressure Vessel Nozzle," invited paper at EPRI seminar on Repair Welding Alternatives for Nuclear Power Plant Components, Charlotte, North Carolina, co-authors L. E. Mullins, K. R. Willens, and B. K.

Darby, 1987.

2.

"Pipe Replacement Experience at Vermont Yankee Nuclear Power Station," invited paper at EPRI seminar on Pipe Repair and Replacement, Charlotte, North Carolina, 1987.

3.

"Pipe Replacement Experience at Vermont Yankee," invited paper at EPR IGSCC Countermeasures Seminar, Palo Alto, California, co-authors K. R. Willens and W. L. Wittmer, 1986.

4.

"Pipe Replacement Planning at Vermont Yankee," invited paper at 8th SMiRT Conference, Brussels, Belgium, 1985.

5.

"An Evaluation of IGSCC Remedies for Vermont Yankee Nuclear Power Station," YAEC-1382, August 1983.

6.

"Synopsis of lntergranular Stress Corrosion Experience at Vermont Yankee Nuclear Power Station,"

YAEC-1247, July 1981.

7.

"Development of a Fixed-Movable Incore Instrumentation System for Bottom Entry Pressurized Water Reactors in New England," YAEC-1 143, December 1977.

8.

"Ni-Cr-Fe Alloy 82 Weld Overlay of Nozzles Using Temperbead Technique," invited paper at 1991 American Welding Society Seminar on Maintenance and Repair Welding in Power plants, December 1991, Orlando, Florida.

4

March 2, 2006 Mr. Michael Kansler President Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White. Plains, NY 10601

SUBJECT:

VERMONT YANKEE NUCLEAR POWER STATION - ISSUANCE OF AMENDMENT RE: EXTENDED POWER UPRATE (TAC NO. MC0761)

Dear Mr. Kansler:

The Commission has issued the enclosed Amendment No. 229 to Facility Operating License No. DPR-28 for the Vermont Yankee Nuclear Power Station (VYNPS), in response to your application dated September 10, 2003, as supplemented by letters dated October 1, and October 28 (2 letters), 2003; January 31 (2 letters), March 4, May 19, July 2, July 27, July 30, August 12, August 25, September 14, September 15, September 23, September 30'(2 letters),

October 5, October 7 (2 letters), December 8, and December 9, 2004; February 24, March 10, March 24, March 31, April 5, April 22, June 2, August 1, August 4, September 10, September 14, September 18, September 28, October 17, October 21 (2 letters), October 26, October 29, November 2, November 22, and December 2, 2005; January 10, and February 22, 2006.

The amendment increases the maximum authorized power level for VYNPS from 1593 megawatts thermal (MWt) to 1912 MWt,. which isan increase of approximately 20 percent. The increase in power level is considered an extended power uprate (EPU). The amendment includes revisions to the VYNPS Operating License and Technical Specifications that are necessary to implement the EPU.

The related Safety Evaluation (SE) has been determined to contain proprietary information pursuant to Title 10 of the Code of Federal Regulations, Section 2.390. Accordingly, the NRC staff has prepared a redacted, publicly-available, non-proprietary version of the SE. Copies of the proprietary and non-proprietary versions of the SE are enclosed.

M. Kansler A copy of the "Notice of Issuance of Amendment to Facility Operating License and Final Determination of No Significant Hazards Consideration," which is being forwarded to the Office of the Federal Register for publication, is also enclosed.

Sincerely, IRA!

Richard B. Ennis, Senior Project Manager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-271

Enclosures:

1. Amendment No. 229 to License No. DPR-28.

2. Non-proprietary SE

3. Proprietary SE

4. Notice cc w/encls 1,2., and 4: See next page

M. Kansler A copy of the "Notice of Issuance of Amendment to Facility Operating License and Final Determination of No Significant Hazards Consideration," which is being forwarded to the Office of the Federal Reqister for publication, is also enclosed.

Sincerely, IRA/

Richard B. Ennis, Senior ProjectManager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-271

Enclosures:

1. Amendment No.. 229 to License No. DPR-28

2. Non-proprietary SE

3. Proprietary SE

4. Notice cc w/encls 1, 2, and 4: See next page DISTRIBUTION: See next page Accession Nos.:

Package: ML060050024 Cover letter, Amendment, and Notice: ML060050022 License* and TS pages: ML060390107 Non-proprietary SE: ML060050028 Drn rimfn, RAI flrflflnflO i

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1/4.#JJ*; **LLI; VJI*IJ OFFICE LPL1-2/PM CM Tech Editor*

LPL1-1/LA OGC NAME REnnis HChang SLittle STurk DATE 2/27/06 1/5/06 2/27/06 2/28/06 OFFICE LPL1-2/BC DORLJD NRR/D NAME DRoberts CHaney JDyer DATE 3/1/06 3/1/06 3/2/06 The following provided safety evaluation input by memos dated**

OFFICE EEIB-A/SC EEIB-B/SC EMCB-A/SC EMCB-B/SC EMCB-C/SC NAME E-Marinos R Jenkins SCoffin TChan L-Lund

[DATE**

9/27/04 7/1/04, 12/15/05, 11/24/04 8/9/04 9/9/04 9/29/04 i OFFICE EMEB/SC IPSB-A/SC IPSB/BC IROB-B/SC SPLB-A/SC(A)

NAME KManoly DThatcher TQuay DTrimble SJones DATE**

9/30/05 9/29/05 11/10/04 1/24/05 9/30/05 OFFICE SPLB-B/SC SPSB-A/SC SPSB-C/SC SRXB-A/SC NAME SWeerakkody MRubin RDennig FAkstulewicz DATE**

7/31/04 10/3/05 10/4/04, 10/6/04, 9/30/05,

, 9/30/05 10/11/05 OFFICIAL RECORD COPY

Distribution for letter dated: March 2, 2006

SUBJECT:

VERMONT YANKEE NUCLEAR POWER STATION - ISSUANCE OF AMENDMENT RE: EXTENDED POWER UPRATE (TAC NO. MC0761)

DISTRIBUTION:

PUBLIC LPL1-2 Reading JDyer RBorchardt BSheron BBoger CHaney CHolden EHackett DRoberts REnnis JShea CRaynor SLittle TAlexion QNguyen OGC ACRS GHill (2)

CAnderson, RGN I STurk, OGC VBucci, OIG HGarg NTrehan APal BElliot RDavis KParczewski TScarbrough PSekerak CWu RPettis RPedersen JCai JBongarra DReddy RGallucci MStutzke RLobel HWalker MHart MRazzaque ZAbdullahi GThomas LWard THuang

Vermont Yankee Nuclear Power Station cc:

Regional Administrator, Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406-1415 Mr. David R. Lewis Pillsbury, Winth rop, Shaw, Pittman, LLP 2300 N Street, N.W.

Washington, DC 20037-1128 Mr. David O'Brien,. Commissioner

.Vermont Department of Public Service 112 State Street Montpelier, VT 05620-2601 Mr. James Volz, Chairman Public. Service Board State of Vermont 112 State Street Montpelier, VT 05620-2701 Chairman, Board of Selectmen Town of Vernon P.O. Box 116

'Vernon, VT 05354-0116 Operating Experience Coordinator Vermont Yankee Nuclear Power Station 320 Governor Hunt Road Vernon, VT 05354 G. Dana Bisbee, Esq.

Depiuty-Attoi'iey Ge-nfl 33 Capitol Street Concord, NH 03301-6937 Chief, Safety Unit Office of the Attorney General One Ashburton Place, 19th Floor Boston, MA 02108 Ms. Carla A. White, RRPT, CHP Radiological Health Vermont Department of Health P.O. Box 70, Drawer #43 108 Cherry Street Burlington, VT 05402-0070 Mr.I James M. DeVincentis Manager, Licensing Vermont Yankee Nuclear Power Station P.O. Box 0500 185 Old Ferry Road Brattleboro, VT 05302-0500 Resident Inspector Vermont Yankee Nuclear Power Station U. S. Nuclear Regulatory Commission P.O. Box 176 Vernon, VT 05354 Director, Massachusetts Emergency Management Agency ATTN: James Muckerheide 400 Worcester Rd.

Framingham, MA 01702-5399 Jonathan M. Block, Esq.

Main Street P.O. Box 566 Putney, VT 05346-0566 Mr. John F. McCann Director, Licensing Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White Plains, NY 10601 Mr. Gary J. Taylor Chief Executive Officer.

Entergy Operations 1340 Echelon Parkway Jackson, MS 39213

Vermont Yankee Nuclear Power Station cc:

Mr. John T. Herron Sr. VP and Chief Operating Officer Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White Plains, NY 10601 Mr. Oscar Limpias Vice President, Engineering Entergy Nuclear Operations, Inc..

440 Hamilton Avenue White Plains, NY.10601 Mr. Christopher Schwarz Vice President, Operations Support Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White Plains, NY 10601 Mr. Michael J. Colomb Director of Oversight Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White Plains, NY 10601 Mr. Travis C. McCullough Assistant General Counsel Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White Plains, NY 10601 Mr. Jay K. Thayer Site Vice President Entergy Nuclear Operations, Inc.

Vermont Yankee Nuclear Power Station P.O. Box 0500 185,Old Ferry Road Brattleboro, VT 05302-0500 Ms. Stacey M. Lousteau Treasury Department Entergy Services, Inc.

639 Loyola Avenue New Orleans, LA 70113 Mr. Raymond Shadis New England Coalition*

Post Office Box 98 Edgecomb, ME 04556 Mr. James P. Matteau Executive Director Windham Regional Commission 139 Main Street, Suite 505 Brattleboro, VT 05301 Mr. William K. Sherman Vermont Department of Public Service 112 State Street Drawer 20 Montpelier, VT 05620-2601 Mr. Michael D. Lyster

5931 Barclay Lane Naples, FL 34110-7306 Ms. Charlene D. Faison Manager, Licensing 440 Hamilton Avenue White Plains, NY 10601 Mr. James H. Sniezek

.5486 Nithsdale Drive Salisbury, MD 21801

ENTERGY NUCLEAR VERMONT YANKEE. LLC AND ENTERGY NUCLEAR OPERATIONS, INC.

DOCKET NO. 50-271 VERMONT YANKEE NUCLEAR POWER STATION AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 229 License No. DPR-28

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment filed. by Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. (the licensee) on September 10, 2003, as supplemented by letters dated October 1, and October 28 (2 -letters), 2003; January 31 (2 letters), March 4, May 19, July 2, July 27, July 30, August 12, August 25, September 14, September 15, September 23, September 30 (2 letters), October 5, October 7 (2 letters), December 8, and December 9, 2004; February 24, March 10, March 24, March 31, April 5, April 22, June 2, August 1, August 4, September 10, September 14, September 18, September 28, October 17, October 21 (2 letters), October 26, October 29, November 2, November 22, and December.2, 2005; January 10, and February 22, 2006, complies with the standards and requirements of the Atomic Energy Act.of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission;.

C.

There is reasonable assurance: (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that.such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied;

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 3.B of Facility Operating License No. DPR-28 is hereby amended to read as follows:

(B)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 229, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

In addition, the license is amended to revise paragraph 3.A of Facility Operating License No. DPR-28 to reflect the new maximum licensed reactor core power level of 1912 megawatts thermal. The licensee is also amended to add new licenseconditions 3.K, 3.L, and 3.M as follows:

K. Minimum Critical Power Ratio When operating at thermal power greater than 1593 megawatts thermal, the safety limit minimum critical power ratio (SLMCPR) shall be established by adding 0.02 to the cycle-specific SLMCPR value calculated using the NRC-approved methodologies documented in General Electric Licensing Topical Report NEDE-2401 1-P-A, "General Electric Standard Application for Reactor Fuel," as amended, and documented in the Core Operating Limits Report.

L. Transient Testing

1. During the extended power uprate (EPU) power ascension test program and prior to exceeding 168 hours0.00194 days 0.0467 hours 2.777778e-4 weeks 6.3924e-5 months of plant operation at the nominal full EPU reactor power level, with feedwater and condensate flow rates stabilized at approximately the EPU full power level, Entergy Nuclear Operations, Inc. shall confirm through performance of transient testing that the loss of one condensate pump will not result in a complete loss of reactor feedwater.

2. Within 30 days at nominal full-power operation following.successful performance of the test in (1) above, through performance of additional transient testing and/or analysis of the results of the testing conducted in (1) above, confirm that the loss of.

one reactor feedwater pump will not result in a reactor trip.

M. Potential Adverse Flow Effects This license condition provides for monitoring, evaluating, and taking prompt action in response to potential adverse flow effects as a result of power uprate operation on plant structures, systems, and components (including verifying the continued structural integrity of the steam dryer).

1. The following requirements are placed on operation of the facility above the original licensed thermal power (OLTP) level of 1593 megawatts thermal (MWt):

a. Entergy Nuclear Operations, Inc. shall monitor hourly the 32 main steam line (MSL) strain gages during power ascension above 1593 MWt for increasing pressure fluctuations in the steam lines.

b. Entergy Nuclear Operations, Inc. shall hold the facility for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at 105%,

110%, and 115% of OLTP to collect data from the 32 MSL strain gages required by Condition M.1.a, conduct plant inspections and walkdowns, and evaluate steam dryer performance based on these data; shall provide the evaluation to the NRC staff by facsimile or electronic transmission to the NRC project manager upon completion of the evaluation; and shall not increase power above each hold point until 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months after the NRC project manager confirms receipt of the transmission.

c. If any frequency peak from the MSL strain gage data exceeds the limit curve established by Entergy Nuclear Operations, Inc. and submitted to the NRC staff prior to operation above OLTP, Entergy Nuclear Operations, Inc. shall return the facility to a power level at which the limit curve is not exceeded. Entergy Nuclear Operations, Inc. shall resolve the uncertainties in the steam dryer analysis, document the continued structural integrity of the steam dryer, and provide that documentation to the NRC staff by facsimile or electronic transmission to the NRC project manager prior to further increases in reactor power.

d. In addition to evaluating the MSL strain gage data, Entergy Nuclear Operations,.

Inc. shall monitor reactor pressure vessel water level instrumentation or MSL piping accelerometers on an hourly basis during power ascension above OLTP.

If resonance frequencies are identified as increasing above nominal levels in proportion to strain gage instrumentation data, Entergy Nuclear Operations, Inc.

shall stop power ascension, document the continued structural integrity of the steam dryer, and provide that documentation to the NRC staff by facsimile or electronic transmission to the NRC project manager prior to further increases in.

reactor power.

e. Following start-up testing, Entergy Nuclear Operations, Inc. shall resolve the uncertainties in the steam dryer analysis and provide that resolution to the NRC staff by facsimile or electronic transmission to the NRC project manager. If the uncertainties are not resolved within 90 days of issuance of the license amendment authorizing operation at 1912 MWt, Entergy Nuclear Operations, Inc. shall return the facility to OLTP.

2. As described in Entergy Nuclear Operations, Inc. letter BVY 05-084 dated September 14, 2005, Entergy Nuclear Operations, Inc. shall implement the following actions:

a. Prior to operation above OLTP, Entergy NuclearOperations, Inc. shall install 32 additional strain gages on the main steam piping and shall enhance the data acquisition system in order to reduce the measurement uncertainty associated with the acoustic circuit model (ACM).

b. In the event that acoustic signals are identified that challenge the limit curve during power ascension above OLTP, Entergy Nuclear Operations, Inc. shall evaluate dryer loads and re-establish the limit curve based on the new strain gage data, and shall perform a frequency-specific assessment of ACM uncertainty at the acoustic signal frequency.

c. After reaching 120% of OLTP, Entergy Nuclear Operations, Inc. shall obtain measurements from the MSL strain gages and establish the steam dryer flow-.

induced -vibration load fatigue margin for the facility, update the dryer stress report, and re-establish the steam dryer monitoring plan (SDMP) limit curve with the updated ACM load definition and revised instrument uncertainty, which will be provided to the NRC staff.

d. During power ascension above OLTP, if an engineering evaluation is required in accordance with the SDMP, Entergy Nuclear Operations, Inc. shall perform the structural analysis to address frequency uncertainties up to :10% and assure that peak responses that fall within this uncertainty band are addressed.

e. Entergy Nuclear Operations, Inc. shall revise the SDMP to reflect long-term monitoring of pla'nt parameters potentially indicative of steam dryer failure; to reflect. consistency of the facility's steam dryer inspection program with General Electric Services Information Letter 644, Revision 1; and to identify the NRC Project Manager for the facility as the point of contact for providing SDMP information during power ascension.

f.

Entergy Nuclear Operations, Inc. shall submit the final extended power uprate (EPU) steam dryer load-definition for the facility to-the NRC upon completion of the power ascension test program.

g. Entergy Nuclear Operations, Inc. shall submit the flow-induced vibration related portions of the EPU startup test procedure to the NRC, including methodology for updating the limit curve, prior to initial power ascension above OLTP.

3. Entergy Nuclear Operations, Inc. shall prepare the EPU startup test procedure to include the (a) stress limit curve to be applied for evaluating steam dryer performance; (b) specific hold points and their duration during EPU power ascension; (c) activities to be accomplished during hold points; (d) plant parameters to be monitored; (e) inspections and walkdowns to be conducted for steam, feedwater, and condensate systems and components during the hold points; (f) methods to be used to trend plant parameters; (g) acceptance criteria for monitoring and trending plant parameters, and conducting the walkdowns and inspections; (h) actions to be taken if acceptance criteria are not satisfied; and (i).verification of the completion of commitments and planned actions specified in its application and all supplements to the application in support of the EPU license amendment request pertaining to the steam dryer prior to power increase above OLTP. Entergy Nuclear Operations, Inc. shall provide the related EPU startup test procedure sections to the NRC by facsimile or electronic transmission to the NRC project manager prior to increasing power above OLTP.

4. When operating above OLTP, the operating limits, required actions, and surveillances specified in the SDMP shall be met. The following key attributes of the SDMP shall not be made less restrictive without prior NRC approval:

a. During initial power ascension testing above OLTP, each test plateau increment shall be approximately 80 MWt;

b.

Level 1 performance criteria; and

c. The methodology for establishing the stress spectra used for the Level 1 and.

Level 2 performance criteria.

Changes to other aspects of the SDMP may be made in accordance with the guidance of NEI 99-04.

5. During each of the three scheduled refueling outages (beginning with the spring.

2007 refueling outage), a visual inspection shall be conducted of all accessible, susceptible locations of the steam dryer, including flaws left "as is" and modifications.

6. The results of the visual inspections of the steam dryer conducted during the three scheduled refueling outages (beginning with the spring 2007 refueling outage) shall be reported to the NRC staff within 60 days following startup from the respective refueling outage. The results of the SDMP shall be submitted to the NRC staff in a report within 60 days following the completion of all EPU power ascension testing.

7. The requirements of paragraph 4 above for meeting the SDMP shall be implemented upon issuance of the EPU license amendment and shall continue until.

the completion of one full operating cycle at EPU. If an unacceptable structural flaw (due to fatigue) is detected during the subsequent visual inspection of the steam dryer, the requirements of paragraph 4 shall extend another full operating cycle until the visual inspection standard of no new flaws/flaw growth based on visual inspection is satisfied.

8. This license condition shall expire upon satisfaction of the requirements in paragraphs 5, 6, and 7 provided that a visual inspection of the steam dryer does not reveal any new unacceptable flaw or unacceptable flaw growth that is due to fatigue.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 120 days.

FOR THE NUCLEAR REGULATORY COMMISSION IRAi J. E. Dyer, Director Office of Nuclear Reactor Regulation

Attachment:

Changes to the Operating License and Technical Specifications Date of Issuance: March 2, 2006

ATTACHMENT TO LICENSE AMENDMENT NO. 229 FACILITY OPERATING LICENSE NO. DPR-28 DOCKET NO. 50-271 Replace the following pages of the Facility Operating License and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Facility Operatina. License Remove 3.

9 Insert 3

9 10 11 12 13 Technical Specifications Remove 3

6 7

10 12 13 14 15 17 21 24 30 83 90 92 94 97 98 135 136 137 138 142 224 225 226 228 Insert 3

6.

7 10 12 13 14 15 17 21 24 30 83 90 92 94 97 98 135 136 137 138 142 224 225 226 228

7590-0.1 -P U.S. NUCLEAR REGULATORY COMMISSION ENTERGY NUCLEAR VERMONT YANKEE, LLC AND ENTERGY NUCLEAR OPERATIONS, INC.

DOCKET NO. 50-271 NOTICE OF ISSUANCE OF AMENDMENT TO FACILITY OPERATING LICENSE AND FINAL DETERMINATION OF NO SIGNIFICANT HAZARDS CONSIDERATION The U.S. Nuclear Regulatory Commission (Commission) has issued Amendment No. 229 to Facility Operating License No. DPR-28, issued to Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. (the licensee), which revised the Technical Specifications (TSs) and License for operation of the Vermont Yankee. Nuclear Power Station (VYNPS) located in Windham County, Vermont. The amendment was effective as of the date of itsissuance.

The amendment increases the maximum authorized power level for VYNPS from 1593 megawatts thermal (MWt) to 1912 MWt, which is an increase of approximately 20 percent. The increase in power level is considered an extended power uprate.

The application for the amendment complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations.

The Commission has made appropriate findings as required bythe Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.

The Commission published a "Notice of Consideration of Issuance of Amendment to Facility Operating License and Opportunity for a Hearing" related to this action in the FEDERAL REGISTER on July 1, 2004 (69FR 39976)1 This Notice provided 60 days for the public to request a hearing. On August 30, 2004, the Vermont Department of Public Service and the New England Coalition filed requests for hearing in connection with the proposed amendment.

By Order dated November 22, 2004, the Atomic Safety and Licensing Board (ASLB) granted those hearing requests and by Order dated December 16, 2004, the ASLB issued its decision to conduct ahearing using the procedures in 10 CFR Part 2, Subpart L, "Informal Hearing Procedures for NRC Adjudications."

The Commission published a "Notice of Consideration of Issuance of Amendment to Facility Operating License and Proposed No Significant Hazards Consideration Determination" related to this action in.the FEDERAL REGISTER on January 11, 2006 (71 FR 1744). This Notice provided 30 days for public comment. The Commission received comments. on the

proposed no significant hazards consideration as discussed below.

Under its regulations, the Commission may issue and make an amendment immediately effective, notwithstanding the pendency before it of a request for a hearing from any person, in

.advance of the holding and completion of any required hearing, where it has determined that no significant hazards consideration is involved.

The Commission has applied the standards of 10 CFR 50.92 and has made a final determination that the amendment involves no significant hazards consideration. Public comments received on the proposed no significant hazards consideration determination were considered in making the final determination.

The basis for this determination is contained in the Safety Evaluation related.to this action. Accordingly, as described above, the amendment has been issued and made immediately effective and any hearing will be held after issuance.

The Commission published an Environmental Assessment related to the action in the.

FEDERAL REGISTER on January 27, 2006 (71 FR 4614). Based on the Environmental Assessment, the Commission concluded that the action will not have a significant effect on the quality of the human environment. Accordingly, the Commission determined not to prepare an environmental impact statement for the proposed action.

For further details with respect to this action, see the application for amendment dated September 10, 2003, as supplemented by letters dated October 1, and October 28 (2 letters),

2003; January31.(2 letters), March 4, May 19, July 2, July 27, July 30, August 12, August 25, September 14, September 15, September 23, September 30 (2 letters), October 5, October 7 (2 letters), December 8, and December 9,.2004; February 24, March 10, March 24,. March 31, April 5, April 22, June 2, August 1, August 4, September 10, September 14, September 18, September 28, October 17, October 21 (2 letters), October 26, October 29, November 2, November 22, and December 2, 2005; January 10, and February 22, 2006, which is available for public inspection at the Commission's PDR, located at One White Flint North, Public File Area 01 F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available records will be accessible electronically from the Agencywide Documents Access and Management System's (ADAMS) Public Electronic Reading Room on the Internet at the NRC Web site, http://www.nrc.qov/reading-rm/adams.html.

Persons who do not have access to ADAMS or who encounter problems in accessing the documents located in ADAMS, should contact the NRC-PDR Reference staff by-telephoneat 1-800-397-4209;-301-415-4737, or by e-mail to pdrc)nrcogov:

Dated at Rockville, Maryland, this 2nd day of March, 2006.

FOR THE NUCLEAR REGULATORY COMMISSION IRA!

Richard B. Ennis, Senior Project Manager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

VERMONT YANKEE NUCLEAR POWER STATION OPERATING PROCEDURE OP 0631 REVISION 19 RADIOCHEMISTRY USE CLASSIFICATION: INFORMATION RESPONSIBLE PROCEDURE OWNER: Superintendent, Chemistry REQUIRED REVIEWS Yes/No E-Plan 10CFR50.54()

No Security 10CFR50.54(p)

No Probable Risk Analysis (PRA)

No Reactivity Management No LPC Effective A

No.

Date Affected Pages 1

05/02/06 Appendix D pg 1 & 6 of 6; Appendix E pg 1 of 3; Appendix F pgs 1, 2, 3, & 5 of 5; VYOPF 0631.02 pg I of I I Implementation Statement: N/A I

Issue Date:

03/23/06 OP 0631 Rev. 19 Page.1 of 4

TABLE OF CONTENTS P U R P O S E..........................................................................................................................................

3 D ISC U S SIO N................................................................

....... 3 ATTACHMENTS 3

QA REQUIREMENTS CROSS REFERENCE......

4 REFERENCES AND COMMITMENTS.......................................

4 PRECAUTIONS/LIMITATIONS..........................................................................................

................ 4 P R E R E Q U ISIT E S...........................................................................................................................................

4 P R O C E D U R E....................................................................................................................................................

4 F IN A L C O N D IT IO N S.................................................

4 OP 0631 Rev. 19 Page 2 of 4

PURPOSE To enable Chemistry personnel to properly perform necessary Radiochemical Analyses.

The following sections include methodologies used to perform Technical Specification (TS) or Off-Site Dose Calculation Manual (ODCM) required surveillances:

1.

Fission Product Analysis for Noble Gases and Iodines SURVEILLANCE Reactor Coolant Noble Gases (SJAE):

Iodine:TS 3.6.B.1, 4.6.B.1 TS 3.8.K.1 to 3, 4.8.K.1 to 2 and ODCM Table 4.3.1

2.

Alpha and Gamma Determinations SURVEILLANCE Reactor Coolant Isotopic TS 4.6.B. L.b

3.

Tritium Measurement SURVEILLANCE Stack Tritium ODCM Table 4.3.1

4.

Calculation of Sample Activity and MDA SURVEILLANCE Waste Samples As Needed ODCM Table 4.2.1 DISCUSSION For additional Discussion, see the individual appendices.

ATTACHMENTS 1.

2.

3.

4.

5.:

6.

7.

8.

Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F VYOPF 0631.01 VYOPF 0631.02 Fission Product Analysis for Noble Gases and Iodines Alpha and Gamma Determinations Tritium Measurement Preparation and Accountability of Radioactive Standards Calculation of Sample Activity and MDA Moisture Carryover/Iodine Transport Determinations Radioactive Standard Accountability Moisture Carryover/Iodine Transport Calculations OP 0631 Rev. 19 Page 3 of 4

QA REQUIREMENTS CROSS REFERENCE

1.

None REFERENCES AND COMMITMENTS

1.

See individual appendices.

PRECAUTIONS/LIMITATIONS

1.

See individual appendices.

PREREQUISITES

1.

See individual appendices.

PROCEDURE

1.

See individual appendices.

FINAL CONDITIONS

1.

See individual appendices.

OP 0631 Rev. 19 Page 4 of 4

APPENDIX A FISSION PRODUCT ANALYSIS FOR NOBLE GASES AND IODINES DISCUSSION Fission product analysis will be done to detect the effect of tramp U235 and U 23 in the reactor or any defects that may occur in the fuel thereby releasing fission products into the reactor coolant.

REFERENCES AND COMMITMENTS

1.

Technical Specifications and Site Documents

a.

TS Sections 3.6.B.1, 4.6.B.l.a,c,d and e

b.

TS Sections 3.8.K.1 to 3 and 4.8.K.I to 2

c.

ODCM Section 3/4

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

None

4.

Supplemental References

a.

"Radiolytic Gases" by General Electric

b.

General Electric SIL No. 524, "Analysis for Radioisotopes in GE BWR Reactor Water"

c.

OP 0630, Water Chemistry

d.

OP 2611, Stack Effluent Sampling and Analysis

-e.-

OP 2613, Sampling and Analysis of the Off Gas System

f.

RP 2614, Sampling and Analysis of the AOG System

g.

OP 2615, Sampling and Analysis of the CST for Iodine

h.

DP 2631, Radiochemical Instrumentation

i.

OP 4612, Sampling and Treatment of the Reactor Water System Appendix A OP 0631 Rev. 19 Page 1 of 3

APPENDIX A (Continued)

PRECAUTIONS/LIMITATIONS

1.

Do not exceed 10% dead time when using the MCA.

2.

Wear lab coat, protective glasses, and proper gloves when handling hazardous material.

3.

Do not put hot (thermal) samples on germanium or sodium iodide detectors.

4.

Notify Chemistry supervision when:

a.

Reactor coolant reaches 0.011 microcuries of 1-131 dose equivalent per gram of water

b.

There is a 25% increase or 5,000 *tCi/sec in SJAE activity during steady state operation PREREQUISITES

1.

Apparatus as required:

a.

Noble Gases 14 ml sample vials Multi-channel analyzer with a Germanium crystal

b.

lodines 23 ml scintillation vial Graduated cylinder or pipette Vacuum flask and filter apparatus Multi-channel analyzer with Germanium crystal Millipore and cation filter papers Other approved geometry containers as needed PROCEDURE A.

Noble Gases

1.

Collect an appropriate volume of sample for analysis.

2.

Count the sample as soon as possible on the multi-channel analyzer.

3.

Calculate the activity of each noble gas isotope manually or using the computer program.

Appendix A OP 0631 Rev. 19 Page 2 of 3

APPENDIX A (Continued)

B.

lodines NOTE The method outlined below is to be used when counting liquid samples that contain high levels of corrosion and activation products; i.e.,reactor coolant. All other samples should be counted without filtering (straight sample). However, DEAD TIME on the MCA should not exceed 10%.

I

1.

Collect an appropriate volume of sample for analysis.

2.

Filter a portion of the sample through a 0.45 micron filter and one Toray cation filter paper unless otherwise directed by Supervision.

3.

Decant the filtrate into a 23 ml vial or other approved geometry container and dilute as necessary to achieve a MCA dead time of <10%.

4.

Using the MCA analyzer, count the sample for a minimum of 1000 seconds approximately two (2) hours after collection.

5.

If the 2-hour decay count fails to yield I-131, the sample may be saved as directed by supervision and counted approximately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months later. The total Iodine activity and 1131 Dose Equivalent may then be calculated by adding the 1131 to the iodine*

isotopes from the previous analysis.

FINAL CONDITIONS.

1.

Results recorded and forms completed per AP 0658, OP 2611, OP 2613, RP 2614, OP 2615 and OP 4612 as applicable.

Appendix A OP 0631 Rev. 19 Page 3 of 3

APPENDIX B ALPHA AND GAMMA DETERMINATIONS DISCUSSION An alpha activity measurement is used to indicate the presence of uranium or other alpha emitters. Since the presence of alpha activity may indicate a fuel element defect, contaminated core, or a ruptured source, knowledge of such activity is essential to early implementation of corrective action.

The purpose of monitoring the gamma emitting nuclides is to determine if a trend exists in the build-up of radioactive materials in the water being surveyed.

The reactor coolant samples during power operation will be counted for isotopic analysis two hours after they are taken. This is a standard time that will allow for the decay of very short-lived isotopes and allows comparison between BWRs. They will then be stored for eight days and counted again to aid in the determination of long-lived isotopes.

REFERENCES AND COMMITMENTS

1.

Technical Specifications and Site Documents

a.

TS 4,6.B.l.b

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

None

4.

Supplemental References

a.

ASTM Standards, Water, Atmospheric Analysis, Part 23, Nov., 1969

b.

"Radionuclide Analysis by Gamma Spectroscopy", published by Training Branch Division of Radiological Health, H.E.W.

c.

OP 0630, Water Chemistry

d.

AP 0658, Chemistry Department Practices

e.

DP 2631, Radiochemical Instrumentation

f.

OP 4612, Sampling and Treatment of the Reactor Water System Appendix B OP 0631 Rev. 19 Page 1 of 7

APPENDIX B (Continued)

PRECAUTIONS/LIMITATIONS

1.

Notify Chemistry supervision when alpha activity in the vessel reaches 3 x 10-8 fiCi/ml.

2.

Be sure the bias setting on the well counter is correct as listed on the detector, the daily calibration check and background have been performed, and the appropriate Control Chart indicates the instrument is functioning properly.

3.

When approaching the well counter detector with high activity samples, have the counter counting so that you can tell if the counter is going to saturate. This is noticeable if counter exceeds 5x 1 05 cpm.

4.

Do not exceed 10% dead time when using the MCA.

5.

Do not keep excess sources in the Counting Area.

6.

Always make sure you record the required data on the count record log sheet.

7.

Be sure to label all samples and dispose of them properly after the analysis is completed.

8.

Wear lab coat, protective glasses and proper gloves when handling hazardous material,

9.

Do not put hot (thermal) samples on germanium or sodium iodide detectors.

PREREQUISITES 1.

Apparatus as required:

a.

Alpha 2" planchets Alpha counting instrument Hot plate Silicone grease

b.

Gamma Sodium iodide scintillation detector (NaI(Tl)) and associated electronics Multi-channel analyzer system (MCA)

High purity Germanium detector(s) and associated electronics Tape, plastic wrap or parafilm 2-dram vials I 1-liter or 0.5 liter Marinelli beakers 23 ml scintillation vial.

Appendix B OP 0631 Rev. 19 Page 2 of 7

APPENDIX B (Continued)

PROCEDURE A.

Alpha

1.

Sample preparation for samples with high solids:

a.

Filter the sample using a 0.45 micron filter.

b.

If sample is still not clear, notify supervision.

2.

Prepare planchets for counting in the following manner:

a.

Wash planchet with acetone, then

b.

Grease inside vertical edges of planchet with silicon grease.

c.

Reduce sample volume as needed by boiling, then

d.

Pipet approximately 2 ml of sample into the planchet.

3.

Slowly dry the 2" planchet using the hot plate in the lab hood. Avoid rapid boiling. Excessive heat will cause the sample to bubble and affect recovery of radionuclides.

4.

If sample is highly radioactive, as in Reactor Coolant, put the sample into a petri dish, label and store in a desiccator for approximately 30 days prior to counting.

5.

After the sample has cooled, count for approximately 30 minutes or 1000 gross counts using the Ludlum 2600 alpha counter.

6.

Calculate alpha activity (ýtCi/ml) according to "Calculation of Sample Activity and MDA" section of this procedure.

B.

Gamma I.

Specific Activity (ptCi/ml).

a.

Obtain sample.

b.

Measure an appropriate volume into container.

1)

Dilute or filter as required.

c.

Wrap the container in parafilm (not for beakers).

d.

Count the sample in the NaI(TI) well counter.

Appendix B OP 0631 Rev. 19 Page 3 of 7

APPENDIX B (Continued)

e.

Calculate the specific activity (RCi/mil) according to "Calculation of Sample Activity and MDA" section of this procedure.

f.

Save labeled samples as needed for additional analysis (future counts).

C.

Isotopic I1.

General Isotopic Analysis NOTE Marinelli beakers are usually used to count samples with very low activity (i.e., environmental releases).

a.

Obtain a sample to be analyzed and place it in an appropriate sample container.

b.

Seal the sample and cover the detector with parafilm or plastic wrap to avoid contaminating the detector.

c.

Place the sample on the detector using the appropriate geometry and spacer.

d.

Start the MCA analysis utilizing the method specified in DP 2631, "Multichannel Analyzer" Section.

1)

If the "1-Sigma % Error" percentage error for a nuclide is greater than 50%, do not log that isotope as being present. (A longer count time may be necessary for better counting statistics.)

2)

When performing analysis of liquids for release from the RCA, do not log the isotope as being present if the 1 -Sigma % Error in C.1d.1) is greater than 33%.

Appendix B OP 0631 Rev. 19 Page 4 of 7

APPENDIX B (Continued)

2.

Reactor Coolant Isotopic

a.

Obtain the following 47mm filters:

One 0.45 micron Millipore filter One Toray cation filter One Toray anion filter

b.

Rinse the filter assembly with demineralized water.

c.

Arrange filters in the filter assembly such that the 0.45 micron filter is on top and the anion filter is on the bottom.

d.

Obtain a Reactor Coolant sample. (Step may be done previously.)

e.

Shake the sample bottle vigorously just prior to decanting.

f.

Filter 100 ml or other suitable volume through the filters. Adjust volume as needed to achieve a MCA dead time of <1 0%.

g.

Rinse filtration funnel.

h.

Separate the anion and cation filters into individual labeled petri dishes.

i.

Return the 0.45 micron filter to the filtration funnel.

j.

Shake the sample bottle vigorously just prior to decanting.

k.

Filter up to an additional 900 ml depending on coolant activity and resultant detector dead time through the 0.45 micron filter.

1.

Rinse the sample bottle and filtration funnel with approximately 200 ml of deionized water.

m.

Remove the 0.45 micron filter and place it in a labeled petri dish.

n.

Allow samples to decay 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months before counting (if sampled during power operations).

o.

Analyze on the MCA using the appropriate computer program.

1)

Log sample data on VYOPF 4612.02.

Appendix B OP 0631 Rev. 19 Page 5 of 7

APPENDIX B (Continued)

p.

Store the labeled samples and VYOPF 4612.02 for eight days and then recount.

q.

Log 8-day sample data on VYOPF 4612.02 started for the 2-hour count.

r.

The following guide should be used when logging results:

Do not log an isotope as being present if the "1-Sigma % Error" percentage error for that nuclide is greater than 50%. A longer count time may be necessary for better counting statistics.

Log nuclides with half-lifes <24 hours from the two hour count.

Log nuclides with half-lives >24 hours from the eight day count that are not otherwise routinely identified (i.e., I131).

Log only those nuclides which are not otherwise accounted for (i.e., iodines and gases).

3.

Screening of Environmental Sediment Samples in 1 Quart Metal Cans NOTE This procedure provides an approximation of the source activity of sediment or other non-homogenous samples in 1 quart metal cans only.

These corrected results should be used under the direction of Chemistry supervision to report sample activity to the Radwaste Coordinator for use in preparing shipping documentation.

a.

Obtain a sample to be counted and place it in a I quadi metal can.

b.

Analyze sample on the MCA using:

NOTE Using a sample volume of 0.25 forces the analysis results to be multiplied by a factor of 4, thus ensuring a close approximation of sample activity for this type of sample.

0 S

S 2" filter geometry with spacer sample volume of 0.25

sourcel" as units minimum 1000 second count time Appendix B OP 0631 Rev. 19 Page 6 of 7

C.

d.

APPENDIX B (Continued)

Label the sample as "radioactive material" if appropriate.

Give corrected sample analysis print-out to the Chemistry Environmental Program Lead - Radiological for processing.

FINAL CONDITIONS

1.

Results recorded and forms completed per DP 0641 and OP 4612 as appropriate.

Appendix B OP 0631 Rev. 19 Page 7 of 7

APPENDIX C TRITIUM MEASUREMENT DISCUSSION Tritium is produced in the reactor by fission in small but significant quantities, and by the absorption of a neutron by deuterium.

1H 2 + onI = 1H3 The beta radiation from H3 isso low in energy that it will not penetrate any window on a standard detector and windowless detectors are contaminated easily with H3 samples. Also, if the sample were dried the H3 would go off with H20 vapor. The challenge is to get the H3 as close to the detecting medium as possible, and still retain a reasonable efficiency. Liquid scintillation does this very well since the sample and scintillation fluid are mixed together in a homogeneous solution.

Several scintillation fluids or "cocktails" are available both commercially and through on-site laboratory production. The Chemistry Superintendent will select and approve the scintillation cocktails that satisfy the criteria for scintillation counting and will assess the value and efficiency of the various available mixtures.

REFERENCES AND COMMITMENTS

1.

Technical Specifications and Site Documents

a.

ODCM Tables 4.2.1 and 4.3.1

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

None

4.

Supplemental References

a.

Beckman LS-6500 TA Manual

b.

OP 0630, Water Chemistry

c.

DP 0641, Logging Results of Chemical Analysis

d.

DP 2631, Radiochemical Instrumentation Appendix C OP 0631 Rev. 19 Page 1 of 3

APPENDIX C (Continued)

PRECAUTIONS/LIMITATIONS

1.

Standard laboratory safety procedures should be used for chemicals specified in this procedure.

2.

Wear lab coat, protective glasses, and proper gloves when handling hazardous material.

PREREQUISITES

1.

Apparatus required:

a.

Liquid Scintillation Counter LS-6500TA

b.

Distillation apparatus

c.

Low background counting vials

2.

Reagents

a.

Prepared counting solutions approved by the Chemistry Superintendent.

PROCEDURE NOTE If the sample is high purity water with no color or other organic interferences or phosphors, step 1 may be eliminated.

Distill the sample(s) to be analyzed.

NOTE The actual volumes of sample(s) and cocktail vary with the geometry for the minimum detectable activity level required.

I.

2.

Pipet an appropriate aliquot of the cooled distillate (sample) to be counted into the counting vial(s).

Label vial covers appropriately.

Appendix C OP 0631 Rev. 19 Page 2 of 3

APPENDIX C (Continued)

NOTE Background not required if performed previously (as routine).

3.

Pipet an equal amount of demineralized water into another counting vial to be used as background.

4.

Add scintillation cocktail solution to each vial.

5.

Mix the vial contents completely by shaking.

6.

Count background (as needed) and sample(s) as follows:

a.

Open LID and place sample in sample tray. BE SURE ALL SAMPLES ARE WIPED CLEAN.

b.

Close lid.

c.

Operate the LS-6500TA to count samples according to DP 2631.

7.

Calculate tritium concentration (ýiCi/ml) according to "Calculation of Sample Activity and MDA" section of this procedure.

FINAL CONDITIONS

1.

Results recorded per DP 0641.

Appendix C OP 0631 Rev. 19 Page 3 of 3

APPENDIX D PREPARATION AND ACCOUNTABILITY OF RADIOACTIVE STANDARDS DISCUSSION To properly calibrate the counting instrumentation, it is necessary to make standards of various disintegration rates (activity). Primary standards are usually nuclides which have a relatively long half-life, an uncomplicated decay spectrum, and are traceable to the National Institute of Standards and Technology (NIST).

Secondary radioactive standards are made up from primary standards of known disintegration rates. The secondary standards are made up so they don't exceed the limitations of the counter and are of a geometry similar to the unknown container.

At times there is a need. for standards that are lower in activity than secondary standards.

Due to the small amount of primary standard needed, it is more accurate to make a secondary standard and then use this standard to make a tertiary standard.

It may be necessary to order radionuclides which do not have long half-lives; therefore, it is important to order the nuclide in sufficient quantity to be used for instrument calibrations.

Chemistry sources utilized per this procedure section will be inventoried annually. Such sources are not considered Tech Spec licensed "sealed sources."

REFERENCES AND COMMITMENTS

1.

Technical Specifications and Site Documents

a.

None

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

None

4.

Supplemental References

a.

DP 2630, Analytical Instrumentation

-1~-.

\\

b.

EN-AD-103, Document Control and Records Management Activities Appendix D OP 0631 Rev. 19 Page 1 of 6 LPC#1

APPENDIX D (Continued)

PRECAUTIONS/LIMITATIONS

1.

Wear lab coat, protective glasses, and proper gloves when handling hazardous material.

2.

Make sure the glassware is disposed of properly after use.

3.

Use only certified standards traceable to NIST for primary standards.

4.

Standards should be corrected for radioactive decay.

PREREQUISITES

1.

Apparatus required:

a.

Radionuclide standard

b.

Analytical balance

c.

Heat Lamp or hot plate

d.

Hypodermic syringes

e.

Planchets, vials, Marinelli beakers with covers

f.

Parafilm and plastic wrap

g.

Epoxy adhesive and plastic tape

h.

Charcoal cartridges

i.

Gloves

j.

Silicone grease

k.

Glass filter papers

1.

Petri dishes

2.

Reagents

a.

The solutions used in preparing the secondary standards should be the same chemical strength and composition as the primary standard, e.g., 10% nitric acid.

Appendix D OP 0631 Rev. 19 Page 2 of 6

APPENDIX D (Continued)

PROCEDURE A.

Preparation of Liquid Radioactive Standards

1.

Planchets

a.

Grease the vertical inside edge of the planchet with silicone grease.

b.

Don gloves.

c.

Wash and dry gloved hands to remove any powder.

d.

Fill a syringe with standard.

e.

Weigh the filled syringe on the analytical balance.

f.

Dispense the desired amount of standard into the planchet.

g.

Re-weigh the syringe.

h.

Calculate the weight of standard by subtracting the weight determined in Step g. from that measured in Step e.

i.

Add water or solution similar to that in which the standard was shipped to cover bottom of the planchet and evenly disperse standard.

j.

Place planchet under heat lamp or on a hot plate and evaporate to dryness.

k.

Wrap planchet with parafilm after it has cooled (unless planchet is an alpha standard).

1.

Label planchet with preparation date and Control Number. (See Section B. - Recording Procedures)

Vials and Marinelli Beakers

a.

Don gloves.

b.

Wash and dry gloved hands to remove any powder.

c.

Fill a syringe with standard.

d.

Weigh the filled syringe on the analytical balance.

e.

Dispense the desired amount of standard into the vial or beaker.

2.

Appendix D OP 0631 Rev. 19 Page 3 of 6

APPENDIX D (Continued)

f.

Re-weigh the syringe.

g.

Calculate the weight of standard by subtracting the weight determined in Step F. from that measured in Step d.

h.

Add water or solution similar to that in which the standard was shipped to fill the vial or beaker to the normal volume for that container, i.e. 8 ml in a 2 dram vial or 1000 ml in a 1 liter Marinelli.

i.

Secure cover or stopper on container using epoxy or similar adhesive and tape to seal against leaks.

j.

Label container with preparation date and Control Number. (See Section B. - Recording Procedures) 3, Charcoal Cartridges (Face Loaded)

a.

Remove screening from one end of the charcoal cartridge.

b.

Remove approximately 1/4 inch of charcoal.

c.

Install a glass fiber filter in the cartridge to cover remaining charcoal.

d.

Deposit a thin layer of charcoal in the cartridge.

e.

Don rubber gloves.

f.

Wash and dry gloved hands to remove any power.

g.

Fill a syringe with standard.

h.

Weigh the filled syringe on the analytical balance.

i.

Proportionally dispense the standard onto the charcoal in layers until the cartridge is filled to its normal level.

j.

Re-weigh the syringe.

k.

Calculate the weight of standard by subtracting the weight determined in Step j. from that measured in Step h.

1.

Install the screening removed in Step a.

m.

Wrap the cartridge with parafilm.

n.

Label cartridge with preparation date and Control Number. (See Section B. - Recording Procedures)

Appendix D OP 0631 Rev. 19 Page 4 of 6

APPENDIX D (Continued)

4.

Filter Papers

a.

Place filter paper(s) in a plastic petri dish.

b.

Don rubber gloves.

c.

Wash and dry gloved hands to remove any powder.

d.

Fill a syringe with standard.

e.

Weigh the filled syringe on the analytical balance.

f.

Dispense the desired amount of standard onto the filter paper.

g.

Re-weigh the syringe.

h.

Calculate the weight of standard by subtracting the weight determined in Step g. from that measured in Step e.

i.

If standard does not saturate filter paper, add water or solution similar to that in which the standard was shipped to cover the bottom of the petri dish and evenly disperse standard.

j.

Allow petri dish to evaporate to near dryness.

k.

Cover petri dish and wrap with parafilm after it has cooled.

1.

Label petri dish with preparation date and Control Number. (See Section B. - Recording Procedures)

B.

Recording Procedures (perform steps as needed)

Complete VYOPF 0631.01 of this procedure with the information requested.

Where:

Primary standard bottle number = Isotope/Year produced/Month/Day Example:

A mixed radionuclide standard was produced by Amersham on March 15, 1999. The primary standard number will be MR 99/3/15.

2.

Secondary standards will be recorded as follows: Primary standard bottle number/number of the first standard produced from the primary standard.

Example:

MR 99/3/15/1 Appendix D OP 0631 Rev. 19 Page 5 of 6

APPENDIX D (Continued)

3.

Tertiary standards will be recorded as follows: secondary standard bottle number/number of standards produced from the secondary standard.

Example:

MR 99/3/15/1/1. Where a MR 99/3/15/1 tertiary standard was made from the secondary standard. This standard in turn was prepared from the primary (NIST traceable) standard MR 99/3/15.

4.

File all current source accountability forms (VYOPF 0631.01) and standard certificates in the Chemistry Lab file drawer. When the standards are discarded, the completed forms and attached certificates will be sent to the Chemistry supervision for review and filing.

5.

Annually, or as otherwise directed by Chemistry supervision, physically locate all primary, secondary and tertiary standards listed on current VYOPF 0631.01.

FINAL CONDITIONS

ý_

k 1.

Information recorded on VYOPF 0631.01 and records retained per EN-AD-i103.

Appendix D OP 0631 Rev. 19 Page.6 of 6 LPC*I

APPENDIX E CALCULATION OF SAMPLE ACTIVITY AND MDA DISCUSSION This procedure details the methods for Chemistry Department personnel to calculate sample activities as microcuries per milliliter (j.&i/ml) from tritium, alpha and gross gamma (well counter) instrumentation data. Instructions are included to calculate minimum detectable (MDA) activity from minimum detectable counts at the 95% confidence level.

REFERENCES AND COMMITMENTS

1.

Technical Specifications and Site Documents

a.

ODCM Table 4.2.1 as "LLD"

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

None

4.

Supplemental References T-", -

a.

b.

NCRP Report No. 58 EN-AD-103, Document Control and Records Management Activities Appendix E OP 0631 Rev. 19 Pagel1 of 3 LPC*I

APPENDIX E (Continued)

PROCEDURE

1.

Obtain analysis data:

Sample gross counts per minute (Rg)

Background cpm (Rb)

Counting efficiency (E) of the sample Sample volume in ml or cc (V)

Sample count time in minutes (tQ)

Background count time in minutes (tb)

Conversion factor dpm/ýtCi (K) = 2.22 e6

2.

Calculate sample specific activity and I sigma standard deviation as needed as follows:

(g)

+ (Rb)

Specific Activity (tCi/ml)= (Rg) - (Rb) +

(t.)

(tb)

(E)(V)(K)

3.

For those samples with gross cpm approximately equal to background cpm, report sample activity as less than the minimum detectable activity (MDA) from the minimum detectable count rate (MDCR) as follows:

NOTE Background and sample count times must be equal to apply the following MDCR formula.

a.

For background count rates of less than 10 cpm:

MDCR = 2.71 +4.66 A-tb tb

b.

For background count rates of greater than or equal to 10 cpm.

MDCR = 4.66 Fb A-b Appendix E OP 0631 Rev. 19 Page 2 of 3

APPENDIX E (Continued)

These equations yield values for lower levels of detectability with a 95% level of confidence for false detection and false rejection.

c.

Use the MDCR from 3.a or b. above to calculate MDA according to Step 2 by substituting MDCR for [(Rg - (Rb)]. It is not necessary to calculate the standard deviation of MDA values.

FINAL CONDITIONS

1.

None.

Appendix E OP 0631 Rev. 19 Page 3 of 3

APPENDIX F MOISTURE CARRYOVER/IODINE TRANSPORT DETERMINATIONS DISCUSSION This Appendix provides directions on how to determine steam moisture carryover and iodine transport from the reactor to the turbine.

Steam moisture content is defined as the portion of liquid phase water in the steam-water mixture leaving the BWR pressure vessel. The BWR steam separators and steam dryers, positioned in series, are designed to remove a significant amount of liquid from the steam-water mixture exiting the reactor core. Moisture carryover can be measured to verify performance characteristics of the steam dryer under a variety Of operating conditions. Steam Quality is measured by simultaneously monitoring Sodium-24 in the reactor coolant and in the main condenser hotwell, following a period of equilibrium. Steam moisture measurements from BWR!4 and later design plants indicate that moisture content is almost an order of magnitude below the dryer design specification of 0.1% based on Original Licensed Power (OLP).

The normal concentration of Na-24 in the reactor coolant is near the mid I OE-4 range while the concentration in the hotwell (CPD) is in the upper 1 OE-8 range. For this reason it is imperative that good counting statistics are used when measuring the CPD Na-24 concentration as well as ensuring that this sample is not contaminated with any reactor coolant. The 1 sigma error for the CPD cation measurement can be reduced to approximately-15% and an overall counting error of 22% by filtering a 2 liter volume through a cation paper and counting the cation paper on the MCA for a minimum of 3,000 seconds after approximately a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months decay time. A 1 sigma error of >33% for the CPD Na-24 activity voids the analysis. Decay time for the CPD I

pc_

sample should be <4 hours due to the short half-life of this nuclide. Refer to procedure section k

for specific analysis recommendations.

Moisture carryover measurements are typically performed twice per week but may need to be performed more often under power uprate conditions. Elevated moisture carryover values IT._

of >0.16% to 0.3% maybe indicative of a problem with the steam dryer and require a CR to be written.

Iodine transport calculations will be performed as requested by supervision. It is normally about 2-3% in a BWR and is measured by comparing one or more of the common iodine radionuclides (1-131-1-135) in the reactor coolant to those found in the CPD. The data is useful in analyzing fuel failure data to determine the size of the leaks.

Appendix F OP 0631 Rev. 19 Page. 1 of 5 LPCI1

APPENDIX F (Continued)

REFERENCES AND COMMITMENTS

1.

Technical Specifications and Site Documents

a.

None

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

CR-VTY-2006-00201 CA-0001, Contaminated sample resulted in a high moisture carryover calculation.

_b.

CR-VTY-2006-1260 CA-1, Operability Evaluation

4.

Supplemental References

a.

GE Nuclear Energy, SIL No. 639, Steam Moisture Content

b.

GE Nuclear Energy, SIL No. 644 R1 BWR, Steam Dryer Integrity, 11/09/2004

c.

Strategic Plan for Mitigation Chemistry, 11/29/2004

d.

DP 0641, Logging Results of Chemical Analysis

e.

ON 3178, Increased Moisture Carryover PRECAUTIONS/LIMITATIONS

1.

Label samples and dispose of them properly after analysis is completed.

2.

Do not use a CPD Na-24 value where the "1 sigma % error" is >33%.

3.

Ensure that dedicated equipment is used to filter the CPD sample to prevent cross-contamination. (CR-VTY-2006-00201)

PREREQUISITES

1.

Vacuum flask and filter apparatus

2.

Millipore and cation filter papers

3.

Graduated cylinder

4.

500 ml Marinelli Appendix F OP 0631 Rev. 19 Page 2 of 5 LPC_#1

APPENDIX F (Continued)

PROCEDURE A.

Moisture Carryover

1.

Obtain a Reactor Coolant sample (250ml minimum for this analysis or as required by MCA % dead time).

2.

Obtain a CPD Sample (2 liters minimum) within one hour of collecting the reactor coolant sample.

NOTES 0

Steps 3 through 9 are performed for both RV and CPD samples.

When processing CPD samples, use dedicated lab equipment to prevent contamination of the sample. (CR-VTY-2006-0201)

3.

Rinse dedicated filter assembly with demineralized water.

4.

Arrange filters in dedicated filter assembly with the 0.45 micron filter on top and the cation filter on bottom.

5.

Shake sample bottle vigorously just prior to decanting.

6.

Filter required volume of sample through dedicated filter funnel.

7.

Rinse filtration funnel.

8, Place cation filter into a labeled petri dish.

9, Discard 0.45 micron filter, unless otherwise needed (i.e., metals, isotopic).

10.

Allow sample to decay for approximately 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

11.

Analyze on MCA using the appropriate computer program:

CPD for 3,000 seconds or less to achieve 1 sigma error *33% for Na-24 RV for a minimum of 1,000 seconds

12.

Verify 1 sigma error for the CPD Na-24 analysis is <33%.

13.

Complete VYOPF 0631.02.

Appendix F OP 0631 Rev. 19 Page. 3 of 5 LPC_#1

APPENDIX F (Continued)

B.

Iodine Transport

1.

Obtain a Reactor Coolant sample.

NOTE Condensate Pump Discharge sample shall be collected within one hour of collection of the reactor coolant sample.

2.

Obtain a Condensate Pump Discharge sample.

NOTE Steps 3 through 7 are for both the reactor coolant and the Condensate Pump Discharge samples.

3.

Filter a portion of each sample through a 0.45 micron filter and one Toray cation filter paper.

NOTE It may be necessary to dilute the filtrate with demineralized water to ensure dead time does not exceed 10%.

4.

Decant the filtrate into a 500 ml Marinelli beaker or other approved geometry container and dilute as necessary.

I

5.

Using the MCA analyzer, count the samples for a minimum of 1000 seconds approximately two (2) hours after collection.

6.

Calculate Iodine Transport % =

1-131 CPD x 100 1-131RV

7.

Complete VYOPF 0631.02.

Appendix F OP 0631 Rev. 19 Page 4 of 5

APPENDIX F (Continued)

FINAL CONDITIONS L7_\\

1.

Information recorded on VYOPF 0631.02 and records retained per EN-AD-103.

2.

Issue a CR and notify the Shift Manager if the moisture carryover is determined to be

Ž>0.16%. (Control Room actions are in ON 3178)

3.

Notify a Chemistry Supervisor if the 1 sigma error for the CPD Na-24 measurement is

>33%.

Appendix F OP 0631 Rev. 19 Page 5 of 5 LPC_#1

RADIOACTIVE STANDARD ACCOUNTABILITY PRIMARY/SECONDARY STANDARD (Circle One)

1.

Isotope

2.

Date Prepared_

Vendor Name

3.

Primary/Secondary Standard Control No.

4.

Total Grams

5.

Total Activity

6.

Activity/gram

7.

Date Discarded To (location)

8.

Inventory of Primary Amount Date/Init SECONDARY/TERTIARY STANDARDS (Circle One)

Grams of Grams of Date Date Control Standard Standard Prepared/

Inventory Discarded/

Location Number Used Geometry Remaining Initials Date/Init Initials Discarded Reviewed By:

/

Chemistry Supervision (Print/Sign)

Date VYOPF 0631.01 OP 0631 Rev. 19 Page 1 of I

MOISTURE CARRYOVER/IODINE TRANSPORT CALCULATIONS Sample Date:.

Time:

Sample Spectrum Numbers:

1-Sigma Error of CPD Na-24 measurement =

MOISTURE CARRYOVER Moisture Carryover % =

Moisture Carryover % =

Na24 CPD CATION X 100 Na24 RV CATION x 100=

IODINE TRANSPORT Iodine Transport % =

Iodine Transport% =

1-131 CPD x 100 1-131 RV x 100=

,TAcceptance Criteria = moisture carryover <0.16%

Performed By:.

Reviewed By:

Date:

(Print/Sign)

Date:

Chemistry Supervision (Print/Sign)

VYOPF 0631.02 OP 0631 Rev. 19 Page -1 of 1 LPC.#1

GE Nuclear Energy

.SIL Services Information Letter SIL No. 644 Revision 1 November 9, 2004 BWR steam dryer integrity SIL No. 644 ("BWR/3 steam dryer failure'),

issued August 21, 2002, described an event at a BWR/3 that involved the failure of a steam dryer cover plate resulting in the generation of loose parts, which were ingested into a main steam line (MSL). The most likely cause of this event was identified as high cycle fatigue caused by a flow regime instability that resulted in localized high frequency pressure loadings near the MSL nozzles. SIL No. 644 Supplement I, issued September 5, 2003, described a second steam dryer failure that occurred at the same BWR/3 approximately one year following the initial steam dryer failure. This second failure:

occurred at a different location with the root cause identified as high cycle fatigue resulting from low frequency pressure loading. SIL No.

644 included focused recommendations. For BWR/3-style steam dryers, it recommended monitoring steam moisture content (MC) and other reactor parameters, and for those plants operating at greater than the original licensed thermal power (OLTP), it recommended inspection of the cover plates at the next refueling outage. SIL No. 644 Supplement 1 broadened the earlier recommendations for BWR/3-style steam dryer plants and provided additional recommendations for BWR/4 and later steam dryer design plants planning to or already operating at greater than OLTP.

Following this revised guidance, inspections were performed on plants operating at OLTP, stretch uprate (5%), and extended power uprate conditions. These inspections indicate that steam dryer fatigue cracking can also occur in plants operating at OLTP.

The purpose of this Revision I to SIL No. 644 is to describe additional significant fatigue cracking that has been observed in steam dryer hoods subsequent to the issuance of SIL No. 644 Supplement 1 and to provide inspection and monitoring recommendations for all BWR plants based on these observations. In that the occurrence of fatigue cracking. has been observed in several BWRs, this revision contains inspection and monitoring recommendations. that apply to all plants.. SIL No. 644 Revision 1 voids and supercedes SIL No. 644 and SIL No.

644 Supplement 1.

Discussion Instances of fatigue cracking in the steam dryer hood region have been observed recently in several BWR plants. The cracking has led to failure of the hood and thegeneration of loose parts in two BWR/3 plants. Details of the cracking in these plants are described below.

These observations have potential generic significance for all BWR steam dryers that will be discussed in the generic implications section below.

B WR/3-Style Dryer Observations Lower horizontal cover plate failure occurred in a BWR/3 in 2002. In this failure, almost the entire lower horizontal cover plate came completely loose, with some large pieces falling down onto the steam separators and one piece being ingested into the main steamline and lodging in the flow restrictor. This failure was accompanied by asignificant increase in moisture content, along.withchanges in other monitored reactor parameters. The cause of this failure was attributed to the higher fluctuating pressure loads at extended power uprate (EPU) operation. In particular, there may have been a potential resonance condition. between a high frequency fluctuating pressure loading (in the 120-230 Hz range) and the natural frequency of the cover plate. Appendix A provides a more detailed description of this event.

The same BWR/3 experienced extensive*

through-wall cracking in the outer bank hood on

SIL No. 644 Revision I

page 2 the 900 side in May 2003. On the opposite side of the steam dryer (270' side), incipient cracking*

was observed on the inside of the outer hood cover plate. Several internal braces were detached and found on top of the steam separators. Nodamage Was found on the inner banks of the dryer. Again, the failure was accompanied by a significant increase in moisture content. Of the other monitored reactor parameters, only the flow distribution between the individual steamlines was affected.

The cause of this failure was attributed to high cycle fatigue resulting from low frequency oscillating pressure loads (<50 Hz) of higher amplitude at EPU operation and the local stress concentration introduced by the internal brackets

that anchor the diagonal internal braces to the dryer hoods. Appendix B provides a more detailed description of this event.

InNovember 2003, a hood failure occurred in the sister unit to the BWR/3 that had

.experienced the previously noted failures. This unit was also operating at EPU conditions. The observed hood damage and associated root cause determination were virtually the same as the May 2003 failure described above. During the event, the moisture content exceeded the previously defined action level. However, the monitored plant parameters (primarily individual steamline flow rates) showed only subtle

'changes and were well within the previously defined action levels for the plant. This failure

.resulted" in the generation of loose parts from the outer vertical hood plate. In addition, inspections during the repair outage showed fatigue cracking in the inner hood vertical braces below where the lower ends of the diagonal braces were attached. The cracking of these*

braces was attributed to poor fit-up of the parts during the dryer fabrication. The diagonal braces should have terminated on the vertical braces. where they were butted up against the drain trough, which' would have transferred the diagonal brace loads directly to the drain trough.

Instead, the diagonal braces terminated on the vertical braces above the top of the drain trough and the 'diagonal brace loads were transmitted through the unsupported section of the vertical braces, thus overstressing the vertical braces.

In October 2003 and December 2003, inspections were made of the steam dryers of the sister units to the BWR/3s described above at another site. These units had also been operating at EPU conditions. Incipient cracking was observed on the inside of the outer hood.

vertical plates on each of the* outer dryer banks.

At one location, the cracking had grown through-wvall. The cracking' was also attributed to high cycle fatigue resulting from low frequency pressure loading.

In March 2004, inspections were performed of

.the repairs made to the BWR/3 dryer in 2003.

Incipient fatigue cracks were found at'the tips of the external reinforcing gussets that were added as part of the 2003 repairs. Fatigue cracks were also found in tie bars that were reinforced during the 2003 repairs. The cracking in these repairs was attributed to local stress concentration introduced by the as-installed repairs.. In both cases, the local stress concentrations had not been modeled in sufficient detail in the analyses that supported the repair design.' Fatigue cracks were also found in perforated plate insert modifications that were made in 2002 as part of the extended power uprate implementation.

These cracks were also attributed to the displacements and stresses imposed by the dryer banks that caused the tie bar cracking.

In April 2004, inspections were made of a BWR/3-style dryer (square hood) in a BWR/4 plant in preparation for implementing an extended power uprate during the upcoming cycle. This inspection found cracking at two diametricallyopposed locations on the exterior steam dam near the lifting lug. Both cracks were similar in length. The cause of the cracking was not identified. It has been postulated that the crack initiation was.due to high residual stresses generated during the dryer fabrication process. The structural analysis of the steam dryer for EPU conditions did not predict these locations as highly susceptible to fatigue cracking. Two other symmetrical

SIL No. 644 Revision 1. page 3 locations in the steam dryer that experienced the same loading conditions did not exhibit any evidence of cracking. These observations point to the likelihood of the presence of an additional contributing factor aside from the pressure loads during normal operation. Specifically, the

.evidence indicates that a high residual stress condition was probably developed by. the original dryer fabrication welding sequence.

Other "cold spring" type loading could also have been generated during the fabrication process.

After the cracking developed, the residual stresses would have been relieved and the crack growth would have subsided.

B WR/5-Style Dryer Observation In March 2004, inspection of the steam dryer at a BWR/5 revealed a fatigue crack in the hood panel to end plate weld. The hood crack occurred in the weld joint between the 1/8" curved hood and the 1/4" end plate on the.

second dryer bank. This particular weld location is vulnerable to fatigue cracking because.of the small weld size associated with the thin 1/8" hood material. Fabrication techniques (e.g.,

feathering the 1/8" plate during fit-up) may further reduce the weld size. Fatigue cracking has been observed in the second bank hood-end plate weld at several other plants with the curved BWR/4-5 hood design at OLTP power levels.

An undersized weld was determined to be the root cause of the cracking observed in at least two of the plants. Incorporating lessons learned from the weld cracks at the other plants, the dryer for this BWR/5 was built with an additional 1/4" fillet weld on the inside of the hood-end plate joint. This weld extended as high up in the hood as was practical for the welder to make (approximately 50") and spanned the probable initiation location for the earlier cracks. The weld crack at the subject BWR!5 occurred in the upper part of the 1/8" weld, above this reinforced section.

The weld joint between the 1/8" curved hood and the 1/4" end plate on the second dryer bank is a known high stress location for the BWR/4-5 curved hood dryer design; therefore, periodic inspection of this location was recommended by SIL No. 644 Supplement 1. The hood cracks at the other four plants occurred early in plant life,*

within the first three or four cycles of operation.

In-plant vibration testing of one of the cracked dryers showed. that the dynamic pressure oscillations were high enough that the 1/8" hood to end plate weld was vulnerable to fatigue*

cracking at pre-uprate power levels. The hood crack at the subject BWR/5 occurred after approximately 16 years of operation, the last nine of which were at a 5%/6 stretch uprate power level. While power uprate operation does increase the loading on the dryer, the length of operatingtime at uprated power levels before the cracking was observed indicates that the weld was not grossly overstressed and that power uprate was only a secondary factor in the cracking observed at the subject BWR/5.

B WR Fleet Operating History Steam dryer cracking has been observed throughout the BWR fleet operating history..

The operating environment has a significant influence on the susceptibility of the dryer to cracking. Most of the steam dryer is located in the steam space withthe lower half of the skirt immersed in reactor water at saturation temperature. These environments are highly oxidizing and increase the susceptibility to IGSCC cracking. Average steam flow velocities through the:dryer vanes at rated conditions are relatively modest (2 to 4 feet per second).

However, local regions near the steam outlet nozzles may be continuously exposed to steam flows in excess of 100 feet per second. Thus, there is concern forfatigue cracking resulting from flow-induced vibration and fluctuating pressure loads acting on the dryer.

In addition to the recent instances described above, steam dryer cracking has been observed in the following components at several BWRs:

dryer hoods, dryer hood end plates, drain channels, support rings, skirts, tie bars, and.

lifting rods. These crack experiences have predominately occurred during OLTP conditions, and are briefly described below.

SIL No. 644 Revision 1 - page 4 Dryer Hood Cracking As discussed above, outer hood cracking has occurred recently in square hood design dryers.

Additionally, other hood cracking has occurred in the BWR operating fleet. Cracking of this type was first found in BWRI2s in the inner banks. These hood cracks were attributed to high cycle fatigue. Other cracking has since been observed in other types of dryers including BWR/4s and attributed to high cycle fatigue as well. Susceptible plants were typically reinforced with weld material or plates.

Dryer End Plate Cracking Cracking has been detected in end plates. of the dryer banks at several BWRs. These cracks have been attributed to IGSCC based on the location and morphology of the cracks. These cracks have been followed over several cycles and shown to be stable when operating conditions (power levels) are not changed.

Typically no repairs have been necessary.

Drain Channel Cracking Drain channel cracking has been found in all types of BWRs. This cracking has been primarily categorized as being attributable to fatigue, although many cracks have been attributed to IGSCC. The steam dryers were originally fabricated using Type 304 stainless steel, a material susceptible to sensitization by welding processes and prone to crack initiation in the presence of cold work. Drain channel cracking has been associated with at least 17 plants. The occurrence of the cracking prompted GE to issue SIL No. 474 ("Steam Dryer Drain Channel Cracking" issued October 26, 1988) after cracks were discovered in the drain Channel attachment welds during routine visual examination of dryers at several BWR/4, 5 and 6 plants. The cracks generally were through the throat of vertical welds that attach the side of the drain channel to the exterior of the 0.25-inch thick dryer skirt. The cracks were as long as 21 inches. The cracks are thought to have originated at the bottom of the drain channel where there is maximum stress in the welds. The appearance of the cracking and analysis of potential sources of stress on the welds indicate that high cycle fatigue initiated the cracks in drain channel welds. With the internal dryer inspections performed following the issuance of SIL No. 644, similar cracking has been observed in the internal drain channels of BWR/3-type steam dryers. Typically, drain channel cracks have been repaired by replacing and adding rqinforcement weld material, stop-drilling the crack tip, or by replacing the drain, channels.

Support Ring Cracking Support ring cracking has been found in many BWRs. Cracking has been found in at least 19 plants, ranging from BWR/4s to BWR/6s. The cause of cracking has been IGSCC with a potential contributor being the cold working of the support ring during the fabrication process.

These cracks are typically monitored for growth.

To date, no repairs have been necessary since cracks havereached an arrested state.

Skirt Skirt cracking has been found along with drain Channel cracking. These cracks are either due to IGSCC or could be related to fatigue due to imposed local loads on the dryer. The cracking has also been found in the formed channel section of the dryer. The complex structural dynamic mode shapes of the dryer skirt, the stiffness added by the drain and guide channels, and residual weld stresses all contribute to the.

cracking observed in these components.

Cracking in the dryer skirt region has been observed in plants operating at both OLTP and uprated power levels. Typically, repairs have been implemented at the time that cracking was.

found.

Tie Bar Cracking Fatigue cracking has been observed in tie bars of plants operating at both OLTP and uprated power levels. In most cases, the potential for cracking is related to the crOss section of the tie bar itself because the tie bar must withstand the displacements and stresses imposed by the dryer banks. Typically, repairs have been

SIL No. 644 Revision 1.

page 5 implemented at the time that cracking was found.

Lifting Rod Several plants have exhibited damage in the lifting rods. This cracking has often been in tack welds or in lateral brackets and has been attributed to fatigue, Other Crack Locations Other locations have also exhibited cracking.

These locations include the level' screws or leveling screw Welds, seismic blocks, dryer bank end plates and internal attachment welds,'

vertical internal hood angle brackets and bottom plates.

Generic Implications The steam dryer is a non-safety component.

However, the structural integrity of the dryer must be maintained such that the generation of loose parts is prevented during normal operation, transients, and accident events. With the exception of the significant outer hood cracking at the two BWR/3 plants, the dryer cracking observed in the BWR fleet to date is unlikely to result in the generation of loose parts provided that a periodic inspection program is in place.

However, given that the steam, dryers operate in an environment that is conducive to crack initiation and that many plants are pursuing power uprates and operating license extensions, further cracking in steam dryers should be anticipated. Therefore, the material condition of the dryer should be actively managed to ensure that structural integrity is maintained throughout the life of the dryer.

Theexperience described above has several generic implications with respect to the susceptibility of steam dryers to fatigue or IGSCC cracking.

o Fatigue cracking may result from stress concentrations inherent in the design of the dryer. The design of the BWR/3-style steam dryers with a square hood and internal braces results in maximum stresses where the internal braces attach to the outer hood.

The hood crack initiation at the BWR/3s described above occurred at these high stress locations. Also, the undersized hood-to-end plate welds on the BWR/5 curved hood dryers have cracked in several plants.

o The actual dryer fabrication may have introduced stress concentrations that may, lead to fatigue cracking. The poor fit-up of the diagonal and vertical braces in the BWR/3 dryer led to the cracking of the vertical braces. Feathering of the 1/8" plate during fit-up, and the corresponding reduction* in weld area, was considered a contributing factor in the through-wall cracking of the hood-end plate weld in one of the BWR/5-style dryers. Residual.

stresses or "cold spring" introduced during the fabrication sequence may also lead to crack initiation.

o The fabrication quality for each dryer may vary from one unit to the next, even if the dryers were built by the same fabricator-to the same specifications.

o. The design of dryer repairs and modifications should consider the local stress concentrations that may be introduced by the modification design or installation.

Repairs and modifications to the dryer should be inspected at each outage following the installation until structural integrity of the repairs and modifications can be confirmed.

o Steam dryers. are susceptible to IGSCC due, to the material and fabrication techniques used in the dryer construction. Weld heat affected zone material is likely to be sensitized. Many dryer assembly welds have crevice areas at the weld root, which were not'sealed from the reactor environment. Cold formed 304 stainless steel dryer parts were generally not solution annealed after forming and welding.

Therefore, steam dryers are susceptibleto IGSCC.

SIL No. 644 Revision I

page 6 Parameter monitoring *programs had been previously recommended with the intent of detecting structural degradation of the steam dryer during plant operation. The experience described above also has generic implications with respect to monitoring reactor system parameters during operation for the purposes of detecting steam dryer degradation.

o The November 2003 BWR/3 hood failure demonstrated that monitoring steam moisture content and other reactor parameters does not consistently predict imminent dryer failure nor will it preclude the generation of loose parts. Monitoring is still useful in that it does allow identification of a degraded dryer allowing appropriate action to be taken to minimize the damage to the dryer and the potential for loose parts generation.

o Monitoring the trends in parameter values may be more important than monitoring the parameter values against absolute action

thresholds. An unexplained change in the trend or value of a parameter, particularly steam moisture content or the flow distribution between individual steamlines may be an indication of a breach in the dryer.

hood, even though the absolute value of the parameter is still within the normal experience range.

o Statistical smoothing techniques such as calculating running averages using a large quantity of samples may be necessary to eliminate the process noise and allow the changes in the trend to be identified.

o An experience base should be developed for.

each plant that correlates the changes in monitored parameters to changes in plant operation (rod patterns, core flow, etc.) in order to be able to distinguish the indications of a degraded dryer from normal variations that occur during the operating cycle.

Recommended Actions:

GE Nuclear Energy recommends that owners of.

GE BWRs consider the following:

A. For all plants:

A L. Perform a baseline visual inspection of all susceptible locations of the steam dryer, within the next two scheduled refueling outages. Inspection guidelines showing the susceptible locations for each dryer type are provided in Appendix C.

a. Repeat the visual inspection of all susceptible locations of the steam dryer at least once eyery two refueling outages.

b. For B WR/3-style steam dryers with internal braces in the outer hood that are operating above OLTP, repeat the visual inspection of all susceptible locations of the steam dryer during every refueling outage.

.c. Flaws left "as-is" should be inspected.

during each scheduled refueling outage until it has been demonstrated that there is no further crack growth and the flaws have stabilized.

Note:

This recommendation does not supercede the inspection schedules for existing flaws for which plant-specific evaluations already exist.

d. Modifications and repairs to cracked components should be inspected during each scheduled refueling outage until the structural integrity of the modifications and repairs hasbeen demonstrated. Once structural integrity of any modifications and repairs has been demonstrated, longer inspection intervals for these locations may be justified.

Note:

This recommendation does not supercede. the inspection schedules for existing modifications or repairs for which plant-specific evaluations already exist.

SIL No. 644 Revision I

page 7 A2* Implement a plant parameter monitoring program that measures moisture content and other plant parameters that may be influenced by steam dryer integrity. Initial monitoring should be performed at least weekly. Monitoring guidelines are provided in Appendix D.

A3. Review drawings of the steam dryer to determine if the lower cover plates are less than 3/8 inch thick or if the attachment welds are undersized (less than the lower cover plate thickness). If this is the case, and the plant has operated above OLTP, review available visual inspection records to determine if there are any pre-existing flaws in the cover plate and/or the attachment welds.

B. In addition, for plants planning on increasing the operating power level above the OLTP or above the current established uprated power level (i.e., the plant has operated at the current power level for several cycles with no indication of steam dryer integrity issues), the recommendations presented in A (above) should be modified as follows:

BI. Perform a baseline visual inspection of the steam dryer at the outage prior to initial

-operation above the OLTP or current power level. Inspection guidelines for each dryer type are provided in Appendix C.

B2. Repeat the visual inspection of all susceptible locations of the steam.dryer during each subsequent refueling outage.

Continue the inspections at each refueling outage until at least two full operating cycles at the final uprated power level have been achieved. After two full operating cycles at th:e final uprated power level, repeat the visual inspection of all susceptible locations of the steam dryer at least once every, two refueling outages. For BWR/3-style steam dryers with internal braces in the outer hood, repeat the visual inspection of all susceptible locations of the steam dryer during every refueling outage..

B3. Once structural integrity.of any repairs and modifications has been demonstrated and any flaws left "as-is" have been shown to have stabilized at the final uprated power level, longer inspection intervals for these locations may be justified.

To receive additional information on this subject or for assistance in implementing a recommendation, please contact your local GE Nuclear Energy Representative.

This SIL pertains only to GE BWRs. The conditions under which GE Nuclear Energy issues SILs are stated in SIL No. 001 Revision 6, the provisions of which are incorporated into this SIL by reference.

Product reference B I I -

Reactor Assembly B 13 )-

Reactor System Issued by Bernadette Onda Bohn, Program Manager Service Information Communications GE Nuclear Energy 3901 Castle Hayne Road M/C LI 0 Wilmington, NC 28401

SIL No. 644 Revision I

page 8 Appendix A 2002 BWR/3 Event On June7, 2002, while operating at approximately 113% of OLTP, the BWR/3 experienced a mismatch between the "A" and "B" reactor vessel level indication channels, a loss of approximately 12 MWt, and a reactor pressure decrease. Following the event, measurement indicated that the moisture content had increased by a factor of 10 (to a value of 0.27%). The reactor pressure decrease, reactor vessel level indication mismatch, and increase in moisture 6ontent comprised a set. of concurrent indications suggesting a possible failure of the steam dryer. It was evaluated that there were no safety concerns associated with the observed conditions, and the plant continued to operate after implementing several compensatory measures,(e.g., reactor water level setpoint adjustments, increased frequency of moisture content measurements).

Following the* initial event, additional short duration (several minutes to 1/2A hour) perturbations occurred and the moisture content continued to increase. When the moisture content increased to approximately 0.7%, the power level was reduced to approximately 97% of OLTP. At this reduced power, the frequency of the plant perturbations decreased, along with the moisture content. Given the stable plant response at this lower power, the power was increased to 100% OLTP approximately one week later.

On June 30, subsequent to the power reduction to the OLTP level, a step change increase in the reactor steam dome pressure was noted. No changes in turbine control valve positions or pressure in the turbine steam chest were observed. Several additional perturbations occurred over the following week with the reactor steam dome pressure continuing to increase (to a total of 15 to 20 psi above normal. conditions) along with a divergence of the measured total main steam line (MSL) flows compared to the total feedwater flow. The plant was shut down on July 12 to inspect the steam dryer.

Inspection Results:

Inspection of the steam dryer revealed that a 1/4-inch stainless steel cover plate measuring approximately 120" x 15" had failed near the MSL "A" and "B" nozzles (Figure A-I). The failure of this cover plate allowed steam to bypass the dryer banks and exit through the reactor MSL nozzles, causing the observed increase in moisture content. The majority of the cover plate was found as a single piece on top of steam separators. However, a piece of the cover plate (approximately 16"x 6")

had failed and was found lodged in and partially blocking the MSL "A" flow venturi contributing to the MSL flow imbalance and water level perturbations. Several smaller loose pieces (believed to have come from a startup pressure sensor bracket which may have been knocked off by the cover.

plate) were located at the turbine, stop valve strainer basket. Minor gouges and scratches from the transport of foreign material were noted in the "A" steam nozzle cladding, the main steam piping and the MSL "A" flow venturi. All loose pieces were recovered. No collateral damage to other reactor vessel components was observed.

The cover plate was welded in place as part of the original equipment dryer assembly. No known prior repairs had been made to the cover plate. The cover plate is not connected or adjacent to the dryer modification performed at the previous outage; all flow distribution plates installed as part of the dryer modification were intact in the as-installed condition.

SIL No. 644 Revision 1

page 9 Metallurgical Evaluation:

Preliminary laboratory analysis has been completed. The main crack originated from the bottom side of the cover plate and propagated upward through both the plate base metal and weld metal. The transgranular, as opposed to intergranular, nature of the fracture surface and the relative lack of crack branching indicated that the failure was not caused by stress-corrosion cracking. The lack of macro and micro ductility features in and near the fracture indicated the cracking occurred over a period of time and not due to a mechanical overload. Additionally, there was no evidence that the failure was a result of an original manufacturing defect. Based on the available evidence, the most probable cause of the cover plate cracking was mechanical, high cycle fatigue.

Root Causes:

The results of the metallurgical analysis confirmed that the failure mechanism is.high cycle fatigue. The cause of this high cycle fatigue is believed to be flow induced vibration. At this time there are two probable root causes of the cover plate failure:

1. Increased pressure oscillations on the steam dryer due to the increased steam flows at extended power uprate conditions, aggravated by the potential presence of a pre-existing crack in the cover plate.

2. A flow regime instability that results in localized, high cycle pressure loadings near the MSL nozzles. When the natural frequency of the installed cover plate coincides or nearly coincides with the frequency of the cyclic pressure forcing function, and the acoustic natural frequency of the steam zone, the resulting resonance or. resonances can lead to high vibratory stresses and eventual high cycle fatigue failure of the cover plate.

Corrective Actions:

The cover plates on both sides of the dryer have been replaced with '/2-inch continuous plates (this eliminates two intermediate welds on the original plates). The fillet weld connecting the plate to the support ring was increased to %-inch and the weld to the vertical face of the dryer. hood was increased to 'h-inch. The plant has been returned to service with interim, enhanced monitoring of moisture.

content, reactor steam dome pressure, MSL flow rates and reactor water level. As an additional measure, the plant has implemented dynamic response monitoring of the MSLs to determine if higher flow induced vibration occurs as the steam flow is increased.

SIL No. 644 Revision 1 - page 10 Drain Pipe J Support Ring Lower!

Guide Rod Channel Skirt to Skirt Welds (2X)-

Figure A-I: Location of the 2002 Lower Cover Plate Failure

SIL No. 644 Revision I

page 14 Appendix B 2003 BWR/3 Event On April 16, 2003,. with the plant operating at extended power uprate (EPU) conditions, an inadvertent opening of a pilot operated relief valve (PORV) occurred. The unit was shut down and the PORV replaced.. On May 2, 2003, following return to EPU conditions, a greater than four-fold increase in the moisture content was measured. 'The moisture content continued to gradually increase until it exceeded a pre-determined threshold of 0.35% on May 28, 2003. The-power level was reduced to pre-EPU conditions that resulted in a moisture content reduction to 0.2%. The moisture content remained steady at this value following the power reduction with no significant changes in.

other reactor operating parameters observed by the operators.

A detailed statistical evaluation of key plant parameters concluded that a subtle change in the MSL flows had occurred following the April 16, 2003 PORV event. Based on this information, concurrent with the moisture content increase, the utility elected to shut down the unit on June 10,.20.03 and perform a steam dryer inspection.

inspection results A detailed visual inspection of the accessible external and internal areas of the steam dryer revealed significant steam dryer damage. The damage was most severe on the 90-degree side of the steam dryer, the side that Was closest to the PORV that had opened. On the 90-degree side, a through-wall crack approximately 90 inches long and up to three inches wide was observed in the top of the outer hood cover plate and the top of the vertical hood plate (refer to Figures B-I and B-2). Three internal braces in the outer hood were detached and one internal brace in the outer hood was severed. The detached braces were found on top of the steam separator. All detached parts Were accounted for and retrieved. On the opposite, side of the steam dryer (270-degree side), incipient cracking was observed on the inside of the outer hood cover plate and one vertical brace in the outer hood was cracked. No damage was found in the cover plates that had been replaced following the first steam dryer failure in 2002.

Three tie bars on top of the steam dryer connecting the steam dryer banks were also cracked. Tie bar cracking has been observed on several other steam dryers (including plants that have not implemented EPU); therefore, tie bar cracking is believed to be unrelated to the other damage noted above.

Root cause of steam dryer failure Extensive metallurgical and analytical evaluations (e.g., detailed finiteelement analyses, flow induced vibration analyses, computational fluids dynamics analyses, 1/ 16th scale model testing and acoustic circuit analyses). concluded that the root cause of the steam dryer failure was high cycle fatigue resulting from low frequency pressure loading. There are two potential contributing factors to the failure:

1. Continued operation for approximately I month following the failed cover plate in 2002 which resulted in additional stress loading on the vertical hood plate, and

2.

Inadvertent opening of the PORV resulting in a decompression wave, which subjected the steam dryer to two to three times the normal pressure loading. (It is believed that there was incipient cracking in the steam dryer and the PORV event caused the cracks to open up).

The root cause identified in the first steam dryer failure was high cycle fatigue cause by high frequency pressure loading. The low frequency pressure loading was identified as the dominant cause

SIL No. 644 Revision 1, page 12 in this failure. The low frequency pressure loading may have also been a significant contributing factor in the first failure.

Corrective Actions:.

The following repairs and pre-emptive modifications were made to both the 90 and 270-degree sides of the steam dryer:

1. replaced damaged /1/2 inch outer hood plates with 1 inch plates

2.

removed the internal brackets that attached the internal braces to the outer hood

3. addedgussets at the outer vertical hood plate and cover plate junction

4. added stiffeners to the vertical welds and horizontal welds on the outer hood The combined effect of these modifications was to increase the natural frequency of the outer hood, reduce the maximum stress by at least a factor of two, and reduce the pressure loading by reducing the magnitude of vortices in the steam flow near the MSLs.

Following the steam dryer modifications, the unit was returned to service on June 29, 2003.

SIL No. 644 Revision 1

page 13 Figure B-I: Location of the 2003 Outer Hood Failure

SIL No. 644 Revision 1 - page 14 Figure B-2: Steam Dryer Damage 90 Degree Side

SIL No. 644 Revision 1 o page 15 Appendix C Inspection Guidelines Overview The steam dryers have been divided into four broad types with fourteen sub-groups: BWR/2 design, square hood design, slanted hood design and the curved hood design. The focus of the inspections for each dryer type is divided into two categories. The first category is directed at the outer surfaces of the dryer that are subject to fluctuating pressure loads during normal operation and are potentially susceptible to fatigue cracking. The second category is directed at the cracking that has been found in the drain channels and in inner bank end plates. These latter locations are not associated with any near term risk of loose part generation. They have often been associated with IGSCC cracking in the heat-affected-zones of stainless steel welds.

Inspection Techniques Based on the current experience in inspecting the dryer components, VT-I is the recommended technique to be employed for the inspections. VT-I resolution, distance, and. angle of view requirements should be maintained to the extent practical. In instances where component geometry or remote visual examination equipment limitations preclude the ability to maintain the VT-I requirements over the entire length ofthe different weld seams, "best effort" examinations should be performed. In that cracking will be expected to have measurable length (several inches), field experience has confirmed that "best effort" approaches are sufficient to find the cracking that is present.

Steam Dryer Integrity Inspection Recommendations**

The recommendations are divided into three categories: BWR/2 and square hood taken together; slanted hood and curved hood steam dryers. The inspection recommendations for each type of dryer will be detailed using schematics of the outer dryer structure. The key weld seams that must be inspected are outlined in red or green. High stress locations associated with structural integrity are outlined in red. Locations associated with field dryer cracking experience are outlined in green.

Typical horizontal and vertical welds are shown thereby providing guidance for establishing a plant specific inspection plan. The weld numbering approach shown in the figures is only given as an example. Due to the many welds and size differences, each plant should employ their own weld numbering system. If an indication is detected, care should be exercised when inspecting the symmetrical locations on the dryer. If an indication is detected on the external surface of a plate or weld, consideration should be given to inspecting the location from the inside of the dryer in order to determine if the indication is through-wall.

Square Hood Design: applicable to B WR/2 plants and B WR/3 plants Several square hood dryers were built with interior brackets and diagonal braces. These structures produce stress concentration locations, which have been found to aid in the initiation of fatigue cracking. These brackets exist in both the outer and the inner dryer banks. The recommended inspections follow.

Steam Dryer Bank Inspections Figure C-I provides the overview of the square dryer design. These dryers will require both an external and internal inspection. All dryers are symmetrical from this perspective. Outlined in red

SIL No. 644 Revision 1

page 16 are the key weld seams that must be inspected. These welds, both horizontal and vertical outline the outer dryer bank. These locations considered as high stress locations. Figure C-2 displays a cross-section of the BWR/2 steam dryer with the outer bank peripheral welds highlighted. This.

configuration has no lower cover plate.. However, the external locations that match those shown in Figure C-I need to be inspected in a similar fashion to the other square hood dryers. Figures C-3 and C-4 provide the details of the weld seams as viewed from the dryer bank interior.. As shown in Figure C-3, the outer bank welds need to be inspected from both the dryer exterior and the dryer interior. In addition, for the dryers Where there are interior brackets that were present in the original design and are still present, the interior inspection must be conducted of the weld region where the bracket is joined to the hood vertical and top plates. Figure C-3 shows these locations for the outer banks hoods. Figure C-4 shows the brackets for the inner hood. In addition, Figure C-5 provides a cross section of the bracket-diagonal brace substructure. The intersection locations between the. bracket and the top and outer hood are also outlined in red in these figures. In that the concern is primarily fatigue cracking, several inches of base material adjacent to welds should be examined as well as any obvious discontinuity, e.g., the exterior base material should be examined in the general area where there is an internal weld. This inspection examination region includes the heat-affected-zone and will therefore detect any IGSCC cracking. This figure also shows locations in green that exhibited cracking in the field. The region of inspection should be the same.

Tie Bar Inspections In addition to the outer bank and interior bracket locations, tie bars also require inspection. Figure C-6 provides a schematic of the tie bars. These are located between each set of dryer banks.

.Inspections Based on Field*Experience The other locations of interest are primarily associated with IGSCC in drain channels (shown for information in Figures C-7 and C-8). These components will be part of the. internal examination.

While these indications have been historically associated with BWR/4 through BWR/6 plants (SIL No. 474 "Steam Dryer Drain Channel Cracking" issued October 26, 1988), recent findings indicate that cracking can occur in these locations in square hood dryers. The additional weld seams associated with the outer side of the next set of inner banks should also be inspected in that this represents a steam path through the dryer. These areas are shown in green in Figure C-1. Cracking has been detected in these end panels in later design dryers. Finally, cracking at the steam dams as indicated in green in Figure C-6 has occurred in one BWR/4. These locations need to be included in the inspection plan for all of these plants. Finally, bank inner surface welds have cracked in the BWR/2. These locations, shown in Figure C-2 in green, also need to be inspected.

Slanted Hood Design: applicable to B WR/4 plants The slanted hood steam dryers fall into three categories for which the primary difference is diameter and the number of banks. These dryers use 2 or.3 stiffener plates to strengthen each dryer bank. All inspections are on the external surface of the dryer. However, if an indication is detected on the external surface of a plate or weld, consideration should be given to inspecting the location from the inside of the dryer in order to determine if the indication is through-wall. The recommended inspections follow.

Steam Dryer Bank Inspections Figure C-9 provides the overview of the slanted dryer design. All dryers are symmetrical from this perspective. Outlined in red are the key weld seams that must be inspected from the external surface.

These welds, both horizontal and vertical outline the outer dryer bank as well as the cover plate

SIL No. 644 Revision I

page 17 between the outer hood vertical plate and the support ring. Additional red lines represent the outside projected location where the stiffener plates are welded to the outer hoodvertical plate..These locations are considered as high stress locations. The man-way welds (on one side) are also shown as locations requiring inspection.

Tie Bar Inspections In addition to the outer bank and interior bracket locations, tie bars also require inspection. Figure C-10 provides a schematic of the tie bar locations joining the tops of each set of banks. The primary concern is the presence of fatigue cracking through the bar base material cross-section at axial location where the tie bar is attached to the bank.

Inspections Based on Field Experience Cracking has been detected in these end panels in later design dryers. Therefore, these additional weld seams associated with the outer side of the inner banks should also be inspected in that this represents a steam path through the dryer. These areas are shown in green in Figure C49. Cracking has been observed in these locations in dryers of this design. The other locations of interest are primarily associated with IGSCC in drain channels (refer to SIL No. 474 "Steam Dryer Drain Channel Cracking" issued October 26, 1988), support ring, and lifting rod attachments.

Curved Hood Design: applicable to B WR/4-B WRI6 and AB WR plants The curved hood steam dryers fall into five categories for which the primary differences are diameter and inner bank hood thickness. Similar to the slanted hood dryers, these dryers also have 2 or 3 interior stiffener plates to strengthen each dryer bank. All inspections are on the external surface of the dryer. However, if an indication is detected. on the external surface of a plate or weld, consideration should be given to inspecting the location from the inside of.the dryer in order to determine if the indication is through-wall. The recommended inspections follow.

Steam Dryer Bank Inspections Figure C-1I1 provides the overview of the curved hood dryer design. All dryers are symmetrical from this perspective. Outlined in red are the key weld seams that must be inspected from the external surface. These welds, both horizontal and vertical outline the outer dryer bank as well as the cover plate between the outer hood vertical plate and the support ring. Additional red lines represent the outside projected location where the stiffener plates are welded to the outer hood vertical plate.

Inspection locations also include outer plenum end plates and inner hood vertical weld seams for BWR/4 and BWR/5 plants with 1/8 inch thick hood plates on the inner banks. The location shown is the region where these thinner hood plates are attached to the stiffeners. All of these locations are considered as relative high stress locations. The man-way welds (on one side) are also shown as locations requiring inspection.

Tie Bar Inspections In addition to the outer bank and interior bracket locations, tie bars also require inspection. Figure C-II provides a schematic of the tie bar locations joining the tops of each set of banks. In that the attachment of the tie bars may have employed high heat input welds, the inspection should also include the entire welded region to assess the presence of IGSCC on the bank top plate. This region is adjacent to the region shown in red around the end of the inner bank tie bars.

SIL No. 644 Revision I

page 18 Inspections Based on Field Experience Cracking has been detected in the end panels in later design dryers. Therefore, these additional weld seams associated with the outer side of the inner banks should also be inspected in that this represents a steam path through the dryer. These areas are shown in green in Figure C-11. Cracking has been observed in these locations in dryers of this design. The other locations of interest are primarily associated with IGSCC in drain channels (refer to SIL No. 474 "Steam Dryer Drain Channel Cracking" issued October 26, 1988) and lifting rod attachments.

SIL No. 644 Revision I

page 19 0O Ia 90° 900 1800 Vtl 1800 V8!

V7 V9y 900 H2 H1 RI' V6 90*j QO

\\-

9--V Figure C-I : Inspections: Outer Dryer Hood and Cover Plate (Square Hood Dryer)

SIL No. 644 Revision I

page 20 Vane-to-Hood Brace --I Tie Bar --

Lifting Eye Ring Figure C-2: Cross-Section of BWR/2 Steam Dryer

SIL No. 644 Revision I page 21 Vane To End Panel -I

-H A -V6 H -V 3 -.

H -PL5 H_-PL3 H-PL1 H_-H4J

- 13-H _-H2 Figure C-3: Weld layout for interior of outer banks (Square Hood Dryer)

The brackets shown only exist in those plants where they were part of the original design and were not removed as part of dryer modifications.

SIL No. 644 Revision I

page 22 H--PL4 H_-PL3 H_-PL2 H_-PLI 00 1800 H -PL#

Plate (Bank B, C, D or E) (Ex. HB-PL1)

Internal View - View Is Looking Away From Vane Assembly Figure C-4: Weld Rollout - Inner banks with internal brackets (Square Hood Dryer)

The brackets shown only exist in those plants where they were part of the original design and were not removed as part of dryer modifications.

SIL No. 644 Revision I -.page 23 Vertical Brace Upper Exam Area Diagonal Brace Upper Exam Area Dryer Vane p-Bank Hood

_Brace Lower Exam Area

-. v:(..i

,/./

Dank Trough Figure C-5: Dryer Brace Detail (Square Hood Dryer)

SIL No. 644 Revision 1

page 24 TB-06 270" Figure C-6: Inspection Locations: Tie Bars and Steam Dam Inspections (Square Hood Dryer)

SIL No. 644 Revision 1

page 25 Figure C-7: Drain Channel Locations (Square Hood Dryer)

SIL No. 644 Revision 1 -page 26 R

I, AA

_A1 F l10.1 DC-A-18_

8 I

DC--C--10 DC-0-i

`0C-E-1-10 1800 D--

o Figure C-8: Dryer Drain Channel, Guide channels and Guide Rod - Bottom View (Square Hood Dryer)

SIL No. 644 Revision I - page 27 DC - Drain Channel R1 5

-DC-V14

-DC-V1 3

-DC-V12 DC-V09-D DC-V1 1

Figure C-9: Inspection Locations (Slanted Hood Dryer)

SIL No. 644 Revision 1

page 28 90' TB-06 0*

TB-07 TB-03 TB-##: Tie Bar No.

270 Figure C-10: Tie Bar Locations (Slanted Hood Dryers)

SIL No. 644 Revision I

page 29 BankC BankB.

FBafkA Inner Hood Weld Inspection

.Bank D \\*

Applicable to BWR 415 Only Bank E Bank F-.-

SV3 HS3 --

SH8 -i P1-,

SH7 DC-V4-'-

'1 I

V Figure C-I 1: Inspection Locations (Curved Hood Dryer)

SIL No. 644 Revision 1

page 30 Appendix D Monitoring Guidelines Applicability In general, it is good practice to have access to as much performance data as practicable in order to make informed operational decisions. Therefore, GE recommends that all BWRs implement the moisture carryover and operational response guidance described here. However, plants that have sufficient baseline data and operating experience may elect to consider a-less stringent monitoring program.

Background

A moisture carryover greater than 0.1% at the licensed power level is an indication of potential steam dryer damage, unless a higher threshold is established. A higher threshold may be warranted for a BWR with an unmodified square dryer hood (i.e., no addition of perforated plates) and/or operating with MELLLA+ at off-rated core flow.

If plants are reporting measured moisture carryover values of "less than" a value because of inability to measure Na-24 in the condensed steam sample and the "less than" value is greater than 0.025%,

then the moisture carryover measurement process should be modified to reduce the minimum detectable threshold (preferably such that "less than" values are never reported). Without quantitative data, the plant staff will be unable to develop operational recommendations based on statistically valid moisture carryover and other plant data.

BWR moisture carryover may be impacted by: (1) reactor power level, (2) core flow and power distributions, (3) core inlet subcooling (which is related to final Feedwater temperature), and (4) reactor Water level.

Moisture carryover is very sensitive to power level. Therefore, data should be collected during steady state operations at the highest possible power levels.

Moisture carryover has increased in cases where steam flow is increased towards the center of the core.

Moisture carryover has increased in cases where core inlet sub-cooling is decreased (i.e., final Feedwater temperature is increased).

Moisture carryover has increased in cases where reactor water level is increased (due to degraded separator performance).

Note that the standard deviation of moisture carryover measurements is not expected to change significantly following power distribution changes. However, if a significant condenser tube leak occurs, then the standard deviation of moisture carryover measurements may change significantly due to the resulting increased Na-24 concentrations.

Plants are recommended to accurately. determine the flow distribution between individual steam lines.

If significant steam dryer damage occurs, steam line flow distribution changes may result..

It may be helpful to have pressure data at each main steam flow element (venturi) to better understand the pressure drops and possible pressure changes due to moisture content changes in the steam line flow. This pressure data would have been beneficial at Quad Cities to help identify the flow blockage

SIL No. 644 Revision I

page 31 upstream of the flow element following significant steam dryer damage. Note that flow element performance calculations are based on the RPV steam dome pressure.

An increased feed-to-steam mismatch (i.e., total Feedwater flow plus CRD flow minus total steam flow, with reactor water level constant) may validate an increase in moisture carryover. Plant application has confirmed. this correlation exists when the initial moisture carryover value is low

(-0.0 1%), however the correlation showed significant scatter at higher initial moisture carryover values (0.04% to 0.10%).

Baseline Data NOTE Data should be collected during steady state operations at the highest possible power levels.

Moisture Carryover Measure moisture carryover daily to obtain at least five (5) measurements.

Statistically evaluate the moisture carryover data (e.g., determine the mean and standard deviation for the data) to determine if there is a significant increasing trend. Qualitatively reviewthe data to ascertain if there is a significant increasing trend. If there is an increasing trend in moisture carryover, review the changes in plant operational parameters to determine if there is an operational basis for the trend.

If an unexplained increasing trend is evident, then collect additional moisture carryover data with consideration for increasing the measurement frequency (e.g., from "once per day" to "once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ").

If an unexplained increasing trend is not evident, then begin collecting periodic data for moisture carryover.

Plant Operational Parameters NOTE Most plant operational data is available from the process computer, which can normally be input into an Excel spread sheet for evaluation and storage.

The following parameters should be measured under the same (or similar) plant conditions that existed during collection of moisture carryover baseline data:

Reactor power (M Wt)

Core flow (Mlb/hr)

Core inlet sub-cooling (deg F)

Reactor water level, average of at least 1000 data points over a one to three hour time period.

Individual main steam line flows (Mlb/hr), average of at least 1000 data points over a one to three hour time period. Include pressure data at each MSL flow element (venturi), if available.

SIL No. 644 Revision I - page 32 total Feedwater flow (Mlb/hr), average of at least 1000 data points over a one to three hour time period.

CRD flow (Mlb/hr)

Periodic Data and Operational Response NOTE Data should be collected during steady state operations at the highest possible power levels.

If a moisture carryover measurement is suspect (e.g., less than "mean minus 2-sigma'), then repeat the moisture carryover measurement to verify sampling and analysis were performed correctly.

Consider eliminating data shown to be incorrect/invalid.

Moisture carryover should be monitored weekly.

Statistically evaluate the moisture, carryover data and qualitatively determine if there is a significant increasing trend that cannot be explained by changes in plant operational parameters.

If an unexplained increasing trend is evident, then collect additional moisture carryover data with consideration for increasing the measuriement frequency (e.g., from "once per week" to "once per day").

If the latest moisture carryover measurement is greater than "mean plus 2-sigma" and this increase cannot be explained by changes in plant operational parameters, then obtain a complete set of data for the plant operational parameters (identified above). Compare the current plant operational data with the baseline data to explain. the increased moisture carryover (i.e., is there steam dryer damage or not).

If an increase in moisture carryover occurs immediately following a rod swap, additional moisture carryover data should be obtained to assure that an increasing trend does not exist. Note that occurrence of steam dryer damage immediately following a rod swap would be highly unlikely.

If the increasing trend of moisture carryover cannot be explained by evaluation of the plant operational data, then initiate plant-specific contingency plans for potential steam dryer damage.

If the evaluation of plant data confirms that significant steam dryer damage has most likely occurred, then initiate a plant shutdown.

If there are no statistically significant changes in moisture carryover for an operating cycle, then decreasing the moisture carryover measurement frequency (e.g., from "once per week" to "once per month") may be considered, provided the highest operating power level is not significantly increased.

VERMONT YANKEE NUCLEAR POWER STATION OFF-NORMAL PROCEDURE ON 3178 ORIGINAL INCREASED MOISTURE CARRYOVER USE CLASSIFICATION: REFERENCE RESPONSIBLE PROCEDURE OWNER: Manager, Operations REQUIRED REVIEWS Yes/No E-Plan 10CFR50.54( )

Security 10CFR50.54(p)

Probable Risk Analysis (PRA)

Reactivity Management._____I LPC Effective No.

Date Affected Pages 1

02/16/06 Pg 1 of 6 2

02/16/06 Pgs 2-5 of 6 3

05/02/06 Pgs 2, 3, 4, 5, & 6 of 6 I Implementation Statement: N/A j.Effective Date:

01/19/2006 L-C-..

ON 3178 Original Page 1 of 6 LPQý#1

SYMPTOMS

1.

Any of the following may be indications of vessel internals damage and potential debris generation (loose parts). (SIL 644 Revision 1)

Sudden drop (*1 minute) in Main Steam Line steam flow of>5%. (B064, B065, B066, B067)

RPV water level difference >3 inches step change between level instruments from different reference legs. (B040, B041, B047 versus B021, B042, B043)

Sudden drop (*1 minute) in steam dome pressure of>2 psig. (B048, B049)

Unexpected trends in parameters (listed in Appendix A) that may be indicative of loss of steam dryer integrity, particularly unexplained changes in trends.

2.

Moisture carryover >0.16%.

AUTOMATIC ACTIONS

1.

None OPERATOR ACTIONS

1.

Request Chemistry to perform moisture carryover sampling and analysis per OP 0631, Radiochemistry, Appendix F.

a.

For moisture carryover values <0.16%, no action is required, exit this procedure.

b.

For moisture carryover values >0.16% and <0.35%, GOTO Step 2.

c.

For moisture carryover values >0.35%, GOTO Step 3.

2.

IF moisture carryover is >0.16% and <0.35%, THEN perform the following:

a.

Submit a Condition Report.

b.

Notify:

General Manager Operations Management System Engineering Reactor Engineering Design Engineering Mechanical ON 3178 Original Page 2 of 6 LPC.#3

NOTE The occurrence of steam dryer damage due to a rod adjustment would be highly unlikely. However, moisture carryover is sensitive to rod patterns and power levels.

c.

IF >25% increase in moisture carryover value occurs following a rod adjustment, THEN request Chemistry to perform another moisture carryover sample after 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of completion of the rod adjustment.

d.

IF the moisture carryover increase can not be attributed to a rod adjustment, THEN promptly suspend any power increases until an evaluation concludes that

-9 further power ascension is permitted. The steam dryer performance data shall be reviewed as part of an engineering evaluation to assess whether further power ascension can be made without exceeding 0.35% moisture carryover.

5,

e.

Review Tech. Spec. license conditions for the steam dryer.

PC --4f.

If not attributed to rod adjustment, suspend any power increases until an evaluation concludes that further power ascension is permitted.

g.

Request Engineering to perform an Operability Evaluation per EN-OP-i 04, Operability Determinations.

h.

Evaluate the moisture carryover data and pressure data (Appendix A). to determine if there is a significant increasing trend or step change that cannot be explained by changes in plant operational parameters.

Request Chemistry to perform moisture carryover sample analysis per OP 0631, Appendix F, and continue sampling every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months nominal until otherwise directed by plant management.

j.

IF the engineering evaluation of plant data confirms that steam dryer damage may have occurred, THEN:

Initiate a plant shutdown per OP 0105.

Place the plant in a cold shutdown condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Evaluate Reportability per AP 0156.

k.

IF the results of the evaluation does not support continued plant operation, THEN commence a power reduction and achieve hot shutdown condition within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

1.

IF the results of the engineering evaluation cannot conclude the current power level is justified, THEN reduce power in accordance with OP 0105 as required by the engineering evaluation.

ON 3178 Original Page 3 of 6 LPC.J3

'K.-Z

3.

IF moisture carryover >0.35% THEN:

a.

Submit a Condition Report

b.

Notify:

0 0

0 S

0 General Manager Operations Management System Engineering Reactor Engineering Design Engineering Mechanical

c.

Promptly initiate a reactor power reduction of 10% within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months IAW OP 0105, and have Chemistry resample. If greater than 0.35%, repeat until moisture carryover <0.16%, unless an engineering evaluation concludes that continued power operation or power ascension is acceptable.

d.

Review Tech. Spec. license conditions for the steam dryer.

e.

Suspend any power increases until the engineering evaluation concludes that further power ascension is justified. The steam dryer performance shall be reviewed as part of an engineering evaluation to assess steam dryer integrity.

f.

Request Engineering to perform an Operability Evaluation per EN-OP-104, Operability Determinations.

g.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , re-measure moisture carryover and perform an engineering evaluation of the steam dryer integrity.

1)

IF the engineering evaluation of plant data confirms that steam dryer damage may have occurred, THEN:

0 0

0 Initiate a plant shutdown per OP 0105.

Place the plant in a cold shutdown condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Evaluate Reportability per AP 0156.

I)

2)

IF the results of the evaluation does not support continued plant operation, THEN the reactor shall be placed in a hot shutdown condition within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

3)

IF the results of the engineering evaluation cannot conclude the current power level is justified, THEN reduce power in accordance with OP 0105 to a previously acceptable power level as determined by Engineering and Operations management ON 3178 Original Page 4 of 6 LPC.#3

ATTACHMENTS

1.

Appendix A, GE SIL 644 Rev I Moisture Carryover Parameter Monitoring and Affects REFERENCES

1.

Technical Specifications and Site Documents

a.

Proposed Tech. Spec. Change 263, Supplement 33, Revised Steam Dryer Monitoring Plan, Attachment 6 to BVY 05-084

b.

Proposed Tech. Spec. Change 263, Supplement 21

c.

Proposed Tech. Spec. Change 263, Supplement 36

2.

Codes, Standards, and Regulations

a.

None

3.

Commitments

a.

CR-VTY-2005-00778 CA-00002, Issue Off-Normal Procedure for Increased Moisture Carryover

4.

Supplemental References a.

b.

C.

d.

e.

GE SIL 0639 Steam Moisture Content GE SIL 0644 Rev. 1, BWR Steam Dryer Integrity EN-OP-104, Operability Determinations OP 063 1, Radiochemistry (Appendix F)

CR-VTY-2006-1-260 CA-1, Operability Evaluation ON 3178 Original Page 5 of 6 LPC #3

DISCUSSION Steam dryer cracking has been observed throughout the BWR fleet operating history. The operating environment has a significant influence on the susceptibility of the dryer to cracking.

Most of the steam dryer is located in the steam space with the lower half of the skirt immersed in reactor water at saturation temperature. These environments are highly oxidizing and increase the susceptibility to IGSCC cracking. Thus, there is concern for fatigue cracking resulting from flow-induced vibration and fluctuating pressure loads acting on the dryer.

Per GE SIL 644 Revision 1, parameter monitoring programs had been recommended with the intent of detecting structural degradation of the steam dryer during plant operation.

The November, 2003 BWR/3 hood failure demonstrated that monitoring steam moisture content and other reactor parameters does not consistently predict imminent dryer failure nor will it preclude the generation of loose parts. Monitoring is still useful in that it does allow identification of a degraded dryer allowing appropriate action to be taken to minimize the damage to the dryer and the potential for loose parts generation.

A moisture carryover greater than 0.16% at the licensed power level is an indication of potential steam dryer damage, unless a higher threshold is established.

Moisture carryover is very sensitive to power level. Moisture carryover has increased in cases when steam flow is increased towards the center of the core, when inlet sub-cooling is decreased (i.e., final Feedwater temperature is increased) and when reactor water level is increased (due to degraded separator performance). If significant steam dryer damage occurs, steam line flow distribution changes may result.

Note that the standard deviation of moisture carryover measurements is not expected to change significantly following power distribution changes. However, if a significant condenser tube leak occurs, then the standard deviation of moisture carryover measurements may change significantly due to the resulting increased Na-24 concentrations.

An increased feed-to-steam mismatch (i.e., total Feedwater flow plus CRD flow minus total steam flow, with reactor water level constant) may validate an increase in moisture carryover.

Plant application has confirmed this correlation exists when the initial moisture carryover value is low (-0.01 %); however the correlation showed significant scatter at higher initial moisture carryover values (0.04% to 0.10%).

If significant steam dryer damage occurs, steam line flow distribution changes may or may not result.

ON 3178 Original Page 6 of 6 LPC#3.

APPENDIX A GE SIL 644 REV 1 MOISTURE CARRYOVER PARAMETER MONITORING AND AFFECTS A

Look for an explanation of the increased moisture carryover and confirmation of dryer failure by evaluating:

1.

Differences (5% or more) in the steam flow distribution between the steam lines B064 Main Steam Line Flow A B065 Main Steam Line Flow B B066 Main Steam Line Flow C B067 Main Steam Line Flow D

2.

Changes in or differences among MSL venturi pressures DPT 2-116A/B/C/D Master (M) Units (MSL "A"),

DPT 2-117A/B/C/D Master (M) Units (MSL "B"),

DPT 2-118A/B/C/D Master (M) Units (MSL "C"),

0 DPT 2-119AiB/C/D Master (M) Units (MSL "D")

3.

Differences in feedwater flow versus total steam flow 0

B015 Feedwater Inlet Flow A B016 Feedwater Inlet Flow B Cool Total Feedwater.Flow 0

B022 Total steam flow

4.

Changes in reactor water level (3 inches) at each reference leg 0

B040 Reactor water level 72B B041 Reactor water level 57A B047 Reactor water level 68B B021 Reactor water level 72A B042 Reactor water level 58B 0

B043 Reactor water level 68A

5.

Changes in feedwater temperature and subcooling B030 Reactor feedwater inlet temp Al 0

B032 Reactor feedwater inlet temp B 1 C110 Core inlet subcooling

6.

Changes in rod patterns Appendix A ON 3178 Original Page 1 of 1

. t 4

Entergy Nuclear Operations, Inc.

Vermont Yankee P.O. Box 0500 Entergy185 Old Ferry Road Brattleboro, VT 05302-0500 Tel 802 257 5271, August 22, 2006 Docket No. 50-271 BVY 06-079 TAC No. MC 9668 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

Reference:

1. Letter, Entergy to USNRC, 'Vermont Yankee Nuclear Power Station, License No.

DPR-28, License Renewal Application," BVY 06-009, dated January 25, 2006.

Subject:

Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271)

License Renewal Application. Amendment 11 On January 25,'2006, Entergy Nuclear Operations, Inc. and Entergy Nuclear Vermont Yankee, LLC (Entergy) submitted the License Renewal Application for the Vermont Yankee Nuclear Power Station (VYNPS) as indicated by Reference 1. This amendment provides the following updated information.

: VYNPS License Renewal Commitments List, Revision 1, 0 Attachment 2: VYNPS LRA Amendment List, Revision 1,

: Time Limited Aging Analysis (TLAA) Tables, Revision 1.

Should you have any questions concerning this letter, please contact Mr. James DeVincentis at (802).

258-4236.

I declare under penalty of perjury that the foregoing is true and correct. Executed on August 22, 2006.

Sincerely, Site Vice resident Vermont Yankee Nuclear Power Station Enclosed: Attachment 1, 2, 3.

cc: See next page.

BVY 06-079 Docket No. 50-271 Page 2 of 2 cc:

Mr. James Dyer, Director U.S. Nuclear Regulatory Commission Office 05E7 Washington, DC 20555-00001 Mr. Samuel J. Collins, Regional Administrator U.S. Nuclear Regulatory Commission, Region 1 475 Allendale Road King of Prussia, PA 19406-1415 Mr. Jack Strosnider, Director U.S. Nuclear Regulatory Commission Office T8A23 Washington, DC 20555-00001 Mr. Jonathan Rowley, Senior Project Manager U.S. Nuclear Regulatory Commission 11555 Rockville Pike MS-O-1 1 F1 Rockville, MD 20853 Mr. James J. Shea, Project Manager U.S. Nuclear Regulatory Commission Mail Stop 08G9A Washington, DC 20555 USNRC Resident Inspector Entergy Nuclear Vermont Yankee, LLC P.O. Box 157 (for mail defivery)

Vernon, Vermont 05354 Mr. David O'Brien, Commissioner VT Department of Public Service 112 State Street - Drawer 20 Montpelier, Vermont 05620-2601

t BVY 06-079 Docket No. 50-271 Vermont Yankee Nuclear Power Station License Renewal Application - Amendment 11 License Renewal Commitment List, Revision 1

VERMONT YANKEE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENT LIST REVISION 1 During the development and review of the Vermont Yankee Nuclear Power Station License Renewal Application, Entergy made commitments to provide aging management programs to manage the effects of aging on structures and components during the extended period of operation. The following table lists these license renewal commitments, along with the implementation schedule and the source of the commitment.

ITEM COMMITMENT IMPLEMENTATION SOURCE Related LRA SCHEDULE Section NoJ Comments 1

Guidance for performing examinations of buried piping will be enhanced to March 21, 2012 BVY 06-009 B.1.1/Audit specify that coating degradation and corrosion are attributes to be Items 5 & 130 evaluated.

2 Fifteen (15) percent of the top guide locations will be inspected using As stated in the BVY 06-009 B.1.7/Audit enhanced visual inspection technique, EVT-1, within the first 18 years of commitment Item 14 the period of extended operation, with at least one-third of the inspections to be completed within the first 6 years and at least two-thirds within the first 12 years of the period of extended operation. Locations selected for examination will be areas that have exceeded the neutron fluence threshold.

3 The Diesel Fuel Monitoring Program will be enhanced to ensure ultrasonic March 21, 2012 BVY 06-009 B.1.9 thickness measurement of the fuel oil storage tank bottom surface will be performed every 10 years during tank cleaning and inspection.

4 The Diesel Fuel Monitoring Program will be enhanced to specify UT March 21, 2012 BVY 06-009 B.1.9 measurements of the fuel oil storage tank bottom surface will have acceptance criterion > 60% Tnom.

5 The Fatigue Monitoring Program will be modified to require periodic update March 21, 2012 BVY 06-009 B.1.11 of cumulative fatigue usage factors (CUFs), or to require update of CUFs if the number of accumulated cycles approaches the number assumed in the design calculation.

6 A computerized monitoring program (e.g., FatiguePro) will be used to March 21,2012 BVY 06-009 B.1.11 directly determine cumulative fatigue usage factors (CUFs) for locations of interest.

7 The allowable number of effective transients will be established for March 21, 2012 BVY 06-009 B.1.11 monitored transients. This will allow quantitative projection of future margin.

Page 1 of 6 BVY 06-079

VERMONT YANKEE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENT LIST REVISION 1 ITEM COMMITMENT IMPLEMENTATION SOURCE Related LRA SCHEDULE Section No./

Comments 8

Procedures will be enhanced to specify that fire damper frames in fire March 21, 2012 BVY 06-009 B.1.12.1/Audit barriers will be inspected for corrosion. Acceptance criteria will be Items 35, 151, enhanced to verify no significant corrosion.

152, 153 and 159 9

Procedures will be enhanced to state that the diesel engine sub-systems March 21, 2012 BVY 06-009 B.1.12.1/Audit (including the fuel supply line) will be observed while the pump is running.

Items 33, 150 Acceptance criteria will be enhanced to verify that the diesel engine did not

& 155 exhibit signs of degradation while it was running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.

10 Fire Water System Program procedures will be enhanced to specify that in March 21, 2012 BVY 06-009 B.1.12.2 accordance with NFPA 25 (2002 edition), Section 5.3.1.1.1, when sprinklers have been in place for 50 years a representative sample of sprinkler heads will be submitted to a recognized testing laboratory for field service testing.

This sampling will be repeated every 10 years.

11 The Fire Water System Program will be enhanced to specify that wall thickness evaluations of fire protection piping will be performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.

March 21, 2012 BVY 06-009 B. 1.12.2/Audit Items 37 & 41 12 Implement the Heat Exchanger Monitoring Program as described in LRA Section B.1.14.

March 21, 13 Implement the Non-EQ Inaccessible Medium-Voltage Cable Program as March 21, 2012 described in LRA Section B.1.17.-

14 Implement the Non-EQ Instrumentation Circuits Test Review Program as described in LRA Section B.1.18.

March 21, 2012 15 Implement the Non-EQ Insulated Cables and Connections Program as

-]

March 21, 2012 described in LRA Section B.1.19.1 Page 2 of 6 BVY 06-079

VERMONT YANKEE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENT LIST REVISION 1 ITEM COMMITMENT IMPLEMENTATION SOURCE Related LRA SCHEDULE Section No.1 Comments 16 Implement the One-Time Inspection Program as described in LRA Section March 21, 2012 BVY 06-009 B.1.21 B.1.21. Include destructive or non-destructive examination of one (1)

Audit Items socket welded connection using techniques proven by past industry 239, 240, 330, experience to be effective for the identification of cracking in small bore 331 socket welds. Should an inspection opportunity not occur (e.g., socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destructively or non-destructively prior to entering

..... the period of extended operation.

17 Enhance the Periodic Surveillance and Preventive Maintenance Program to March 21,2012 BVY 06-009 B.1.22 assure that the effects of aging will be managed as described in LRA Audit Item 377 Section B. 1.22.

18 Enhance the Reactor Vessel Surveillance Program to proceduralize the March 21, 2012 BVY 06-009 B.1.24 data analysis, acceptance criteria, and corrective actions described in the program description in LRA Section B.1.24.

19 Implement the Selective Leaching Program as described in LRA Section March 21, 2012 BVY 06-009 B.1.25 B.1.25.

20 Enhance the Structures Monitoring Program to specify that process facility March 21, 2012 BVY 06-009 B. 1.27.2 crane rails and girders, condensate storage tank (CST) enclosure, CO 2 Audit Item 377 tank enclosure, N2 tank enclosure and restraining wall, CST pipe trench, diesel generator cable trench, fuel oil pump house, service water pipe trench, man-way seals and gaskets, and hatch seals and gaskets are included in the program.

21 Guidance for performing structural examinations of wood to identify loss of March 21, 2012 BVY 06-009 B.1.27.2 material, cracking, and change in material properties will be added to the Structures Monitoring Program.

22 Guidance for performing structural examinations of elastomers (seals and March 21, 2012 BVY 06-009 B.1.27.2 gaskets) to identify cracking and change in material properties (cracking when manually flexed) will be enhanced in the Structures Monitoring Program procedure.

Page 3 of 6 BVY 06-079

VERMONT YANKEE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENT LIST REVISION 1 ITEM COMMITMENT IMPLEMENTATION SOURCE Related LRA SCHEDULE Section No./

Comments 23 Guidance for performing structural examinations of PVC cooling tower fill to March 21, 2012 BVY 06-009 B.1.27.2 identify cracking and change in material properties will be added to the Structures Monitoring Program procedure.

24 System walkdown guidance documents will be enhanced to perform March 21, 2012 BVY 06-009 B.1.28 periodic system engineer inspections of systems in scope and subject to Audit Items aging management review for license renewal in accordance with 10 CFR 187,188 & 190 54.4 (a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject system will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4 (a)(2).

25 Implement the Thermal Aging and Neutron Irradiation Embrittlement of Cast March 21, 2012 BVY 06-009 B.1.29 Austenitic Stainless Steel (CASS) Program as described in LRA Section B.1.29.

26 Procedures will be enhanced to flush the John Deere Diesel Generator March 21, 2012 BVY 06-009 B.1.30.1 cooling water system and replace the coolant and coolant conditioner every Audit Items 84 three years.

& 164 Page 4 of 6 BVY 06-079

VERMONT YANKEE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENT LIST REVISION 1 I

ITEM COMMITMENT IMPLEMENTATION SOURCE Related LRA SCHEDULE Section No./

___Comments 27 For each location that may exceed a CUF of 1.0 when considering March 21, 2012 BVY-06-058 4.3.3 environmental effects, VYNPS will implement one or more of the following:

Audit Items 29, (1) further refinement of the fatigue analyses to lower the predicted CUFs to March 21, 2010 for 107 & 318 less than 1.0; performing a fatigue (2) management of fatigue at the affected locations by an inspection analysis that program that has been reviewed and approved by the NRC (e.g., periodic addresses the effects non-destructive examination of the affected locations at inspection intervals of reactor coolant to be determined by a method acceptable to the NRC);

environment on (3) repair or replacement of the affected locations.

fatigue (in accordance with an NRC Should VYNPS select the option to manage environmental-assisted fatigue approved version of during the period of extended operation, details of the aging management the ASME Code) program such as scope, qualification, method, and frequency will be provided to the NRC two years prior to the period of extended operation for review and approval.

28 Revise program procedures to indicate that the Instrument Air Program will March 21, 2012 BVY 06-009 B.1.16 maintain instrument air quality in accordance with ISA S7.3 Audit Item 47 29 VYNPS will perform one of the following:

March 21, 2012 BVY 06-009 B.1.7/ Audit

1. Install core plate wedges, or, Item 9

2. Complete a plant-specific analysis to determine acceptance criteria for continued inspection of core plate hold down bolting in accordance with BWRVIP-25 and submit the inspection plan to the NRC two years prior to the period of extended operation for NRC review and approval.

30 Revise System Walkdown Program to specify C02 system inspections March 21, 2012 BVY 06-009 B.1.28 every 6 months.

Audit Items 30, 141,146 & 298 31 Revise Fire Water System Program to specify annual fire hydrant gasket March 21, 2012 BVY 06-009 B.1.12.2 inspections and flow tests.

Audit Items 39

& 40 Page 5 of 6 BVY 06-079

VERMONT YANKEE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENT LIST REVISION 1 ITEM COMMITMENT IMPLEMENTATION SOURCE Related LRA SCHEDULE Section No./

Comments 32 Implement the Metal Enclosed Bus Program.

March 21,2012 BVY 06-058 Audit Item 97 (Details to be provided in a LRA Amendment) 33 Include within the Structures Monitoring Program provisions that will ensure March 21,2012 BVY 06-009 B.1.27 an engineering evaluation is made on a periodic basis of groundwater Audit Item 77 samples to assess aggressiveness of groundwater to concrete.

34 Implement the Bolting Integrity Program.

March 21,2012 BVY 06-058 Audit Items Details to be provided in a LRA Amendment with specific locations in the 198, 216, 218, LRA referenced.

237, 331 & 333 35 Provide within the System Walkdown Training Program a process to March 21, 2012 BVY 06-058 Audit Item document biennial refresher training of Engineers to demonstrate inclusion 384 of the methodology for aging management of plant equipment as described in EPRI Aging Assessment Field Guide or comparable instructional guide.

36 If technology to inspect the hidden jet pump thermal sleeve and core spray March 21, 2010 BVY06-058 Audit Item 12 thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate plant-specific action to resolve this issue. That plant specific action may be I justification that the welds do not require inspection.

37 Continue inspections in accordance with the Steam Dryer Monitoring March 21, 2010 BVY 06-079 Audit Item 204 Program, Revision 3 in the event that the BWRVIP-139 is not approved prior to the period of extended operation.

Page 6 of 6 BVY 06-079

BVY 06-079 Docket No. 50-271 Vermont Yankee Nuclear Power Station License Renewal Application - Amendment 11 License Renewal Application Amendment List, Revision 1

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 11: LRA Section B.1.7 is revised as follows.

1. Delete the exception to the BWR vessel internals program related to the core shroud (page B-27).

2. Delete exception Note #1 on page B-29.

Audit item 26: Add the following text to LRA Section B.1.10 to include the "EQ Component Reanalysis Attributes" specified in NUREG-1801 Vol. 2 Section X.E1.

EQ Component Re-analysis Attributes The re-analysis of an aging evaluation is normally performed to extend the qualification by reducing excess conservatism incorporated in the prior evaluation. Reanalysis of an aging evaluation to extend the qualification of a component is performed on a routine basis pursuant to 10 CFR 50.49(e) as part of an EQ program. While a component life limiting condition may be due to thermal, radiation, or cyclical aging, the-vast majority of component aging limits are based. on thermal conditions. Conservatism may exist in aging evaluation parameters, such as the assumed ambient temperature of the component, an unrealistically low activation energy, or in the application of a component (de-energized versus energized). The re-analysis of an aging evaluation is documented according to the station's quality assurance program requirements that require the verification of assumptions and conclusions. As already noted, important attributes of a re-analysis include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). These attributes are discussed below.

Analytical Methods The analytical models used in the re-analysis of an aging evaluation are the same as those previously applied during the prior evaluation. The Arrhenius methodology is an acceptable thermal model for performing a thermal aging evaluation. The analytical method used for a radiation aging evaluation is to demonstrate qualification for the total integrated_ dose (that is, normal radiation dose for the projected installed life plus accident radiation dose). For license renewal, one acceptable method of establishing the 60-year-normal radiation dose is to multiply the 40-year normal radiation dose by 1.5 (that is, 60 years/40 years). The result is added to the accident radiation dose to obtain the total integrated dose for the component. For cyclical aging, a similar approach may be used. Other models may be justified on a case-by-case basis.

Data Collection and Reduction Methods Reducing excess conservatism in the component service conditions (for example, temperature, radiation, cycles) used in the prior aging evaluation is the chief method used for a re-analysis. Temperature data used in an aging evaluation is to be conservative and based on plant design temperatures or on actual plant temperature data. When used, plant temperature data can be obtained in several ways, including monitors used for Technical Specification compliance, other installed monitors, measurements made by plant operators during rounds, and temperature sensors on large motors (while the motor is not running). A representative number of temperature measurements are conservatively evaluated to establish the temperatures used in an BVY 06-079 Page 1 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 aging evaluation. Plant temperature data may be used in an aging evaluation in different ways, such as; (a) directly applying the plant temperature data in the evaluation, or (b) using the plant temperature data to demonstrate conservatism when using plant design temperatures for an evaluation. Any changes to material activation energy values as part of a re-analysis are to be justified on a plant-specific basis. Similar methods of reducing excess conservatism in the component service conditions used in prior aging evaluations can be used for radiation and cyclical aging.

Underlying Assumptions EQ component aging evaluations contain sufficient conservatism to account for most environmental changes occurring due to plant modifications and events. When unexpected adverse conditions are identified during operational or maintenance activities that affect the normal operating environment of a qualified component, the affected EQ component is evaluated and appropriate corrective actions are taken that may include changes to the qualification bases and conclusions.

Acceptance. Criteria and *Corrective Actions The re-analysis of an aging evaluation could extend the qualification of the component. If the qualification cannot be extended by re-analysis, the component is to be refurbished, replaced, or re-qualified prior to exceeding the period for which the current qualification remains valid. A re-analysis is to be performed in a timely manner (that is, sufficient time is available to refurbish, replace, or re-qualify the component if the re-analysis is unsuccessful).

Audit items 30, 141, 146 and 298: LRA Section B.1.28 is revised to include an enhancement to perform C02 system inspections every 6 months under the System Walkdown Program. The required inspections will be initiated prior to the period of extended operation. Commitment 30.

Audit item 39: LRA Section B.1.12.2 is revised to delete the exception to the annual fire hydrant gasket inspections. Commitment 31.

Audit item 40: LRA Section B.1.12.2 is revised to delete the exception to the annual fire hydrant flow tests. Commitment 31.

Audit item 48: LRA Section B.1.17 is revised as follows. "VYNPS inspection for water accumulation in manholes is conducted in accordance with a plant procedure. An evaluation per the Corrective Action Process will be used to determine the need to revise manhole inspection frequency based on inspection results."

Audit item 51: LRA Section B.1.18 is revised. as follows. 'The first test of neutron monitoring system cables that are disconnected during instrument calibrations shall be completed before the period of extended operation and subsequent tests will occur at least once every 10 years.

In accordance with the corrective action program, an engineering evaluation will be performed when test acceptance criteria are not met and corrective actions, including modified inspection frequency, will be implemented to ensure that the intended functions of the cables can be maintained consistent with the current licensing basis for the period of extended operation."

BVY 06-079 Page 2 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 53: To clarify the technical basis for sampling, the sampling discussion in LRA Section B.1.19 for the Non-EQ Insulated Cables and Connections Program is revised to read as follows. "Most cables and connections installed in adverse localized environments are accessible. This program is a sampling program. Selected cables and connections from accessible areas will be inspected and represent, with reasonable assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspection sample, a determination will be made as to whether the same condition or situation is applicable to other accessible cables or connections.

The sample size will be increased based on an evaluation per the Corrective Action Process."

Audit items 76, 80, 81, 243, 266, and 270: Aging effects on the drywell moisture barrier will be managed under the Containment Inservice Inspection Program instead of the Structures Monitoring Program. In support of this, the LRA is revised as follows.

1. In the LRA Table 3.5.2-1 line item for "Drywell floor liner seal" change the aging management program from "Structures Monitoring" to "CII-IWE". For clarification, change "drywell floor liner seal" to "drywell shell to floor seal (moisture barrier)." The clarification of this terminology also applies to Table 2.4-1 and Section B.1.27.2.

2. In LRA Table 3.5.1 line Item 3.5.1-16 the Discussion column is revised to read: 'The aging effects cited in the NUREG-1 801 item are loss of sealing and leakage. Loss of sealing is a consequence of the aging effects "cracking" and "change in material properties." For VYNPS, the Containment Leak Rate Program manages cracking and changes in material properties for the primary containment seal and gaskets. The Inservice Inspection -IWE Program manages cracking and changes in material properties for the drywell shell to floor seal (moisture barrier)."

3. In LRA Table 3.5.1, Line Item 3.5.1-5, the Discussion column last paragraph is revised to read "The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program."

4.. LRA-Section.3.5.2.2.1.4 is-revised to-delete-from the end of the first paragraph, the phrase "and Structures Monitoring Program". The drywell to floor moisture barrier will be inspected under the Containment Inservice Inspection (IWE) Program only. The Structures Monitoring Program is not used.

Audit item 77: LRA Section B.1.27.2 for the Structures Monitoring Program is revised to include an enhancement to perform at least once every five years an engineering evaluation of groundwater samples to assess for groundwater being aggressive to concrete. Commitment 33.

Audit items 85, 86, 87, 166, 200, 227, 232, 233, 239, 240, 295, 297, 310, 312, 313, and 359:

The effectiveness of the Water Chemistry Control - Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. To provide further clarification, LRA Appendix A is revised for these three water chemistry control programs to include the sentence 'The One-Time Inspection Program will confirm the effectiveness of the program".

BVY 06-079 Page 3 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 93: In order to address transmission connections, in LRA Table 3.6.2-1, change line item Transmission conductors to Transmission conductors and connections. Revise Section 3.6.2.2.3 to include the following text after the second paragraph.

The aging effects for transmission conductors evident in industry operating experience are loss of conductor strength and loss of material (wear).

The prevalent mechanism contributing to loss of conductor strength of an aluminum conductor steel reinforced (ACSR) transmission conductor is corrosion, which includes corrosion of the steel core and aluminum strand pitting. Corrosion in ACSR conductors is a very slow acting mechanism, and the corrosion rates depend on air quality, which includes suspended particles chemistry, S02 concentration in air, precipitation, fog chemistry and meteorological conditions. Air quality in rural areas generally contains low concentrations of suspended particles and S02, which keeps the corrosion rate to a minimum. Tests performed by Ontario Hydroelectric showed a 30% loss of composite conductor strength of an 80 year old ACSR conductor due to corrosion.

VYNPS transmission conductors include ACSR and aluminum conductor alloy reinforced (ACAR) conductors. ACAR conductors are aluminum conductors reinforced with alloy steel. ACAR conductors are more resistant to loss of conductor strength since the core of the conductor is a more corrosion resistant alloy steel. AMR conclusions regarding ACSR conductors conservatively bound ACAR conductors.

The National Electrical Safety Code (NESC) requires that tension on installed conductors be a maximum of 60% of the ultimate conductor strength. The NESC also sets the maximum tension a conductor must be designed to withstand under heavy load requirements, which includes consideration of ice, wind and temperature. These requirements are reviewed-concerning the specific conductors included in scope at VYNPS.

The 4/0 ACSR conductors have the lowest initial design margin of any transmission conductors included in the AMR. The Ontario Hydro test and the NESC requirements illustrate with reasonable assurance that transmission conductors will have ample strength through the period of extended operation.

Therefore, loss of conductor strength due to corrosion of the transmission conductors in not an aging effect requiring management for the period of extended operation.

Loss of material due to mechanical wear can be an aging effect for strain and suspension insulators that are subject to movement caused by transmission conductor vibration or sway from wind loading. Design and installation standards for transmission conductors consider sway caused by wind loading. Experience has shown that transmission conductors do not normally swing and that when they do swing because of substantial wind, they do not continue to swing for very long once the wind has subsided. Wear has not been identified during routine inspection; therefore, loss of material due to wear in not an aging effect requiring management.

Audit item 97: The VYNPS Metal-Enclosed Bus program ten element comparison to NUREG-1801 (excerpt from the Aging Management Program Evaluation Report LRPD-02) will be provided in later correspondence along with associated revisions to the LRA.

BVY 06-079 Page 4 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 118: LRA Section B.1.17 is revised to replace the last sentence in the Program Description with; 'The specific type of test to be performed will be determined prior to the initial test and is to be a proven test for detecting deterioration of the insulation system due to wetting as described in EPRI TR-1 03834-PI -2, or other testing that is state-of-the-art at the time the test is performed."

Audit item 120: LRA Section B.1.17 Program Description is revised to state that medium-voltage cables include cables with operating voltage level from 2kV to 35kV.

Audit item 124: LRA Section B.1.19 Program Description is revised to include the following.

"The program applies to accessible electrical cables and connections within the scope of license renewal that are installed in adverse localized environments caused by heat or radiation in the presence of oxygen."

Audit Item 159: LRA Section B.1.12.1 is revised to add fire dampers to the list of components in the Program Description that require a periodic visual inspection.

Audit item 165: Line Items 3.3.1-50 and 3.3.1-51 in LRA Table 3.3.1 are revised to replace the Water Chemistry Control - Auxiliary Systems program in the Discussion column with the Water Chemistry Control - BWR Program Audit item 187: LRA section B.1.28 is revised to add the following enhancements. The System Walkdown Program implementing procedure will be enhanced to specify that systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 50.54 (a)(1) and (a)(3) shall be inspected. In addition, the implementing procedure will be enhanced to provide guidance to inspect nearby systemsmwith the potential for spatial interaction.. These enhancements will be implemented as shown in Commitment 24.

Audit item 198, 216, 218, 237, 331 and 333: The VYNPS Bolting Integrity Program ten element comparison to NUREG-1801 (excerpt from the Aging Management Program Evaluation Report LRPD-02) will be provided in later correspondence along with associated changes to the LRA.

The Bolting Integrity Program will be implemented prior to the period of extended operation in accordance with Commitment 34.

Audit item 203: LRA Table 3.1.2-3 is revised to indicate that with the exception of the head seal leak detection line, the Inservice Inspection Program applies to all component types of Piping and fittings < 4" NPS with an aging effect of cracking in addition to the Water Chemistry Control

- BWR and One-Time Inspection Programs.

Audit Item 209 and 291: LRA Table 3.1.2-1 on page 3.1-52 is revised to remove all the line items for the component type of-Thermal Sleeves Feedwater Inlets-(N4). The thermal sleeves are not subject to aging management review since they perform no intended function for license renewal. The sleeves are installed with an interference fit rather than welded so they have no impact on the reactor coolant pressure boundary.

Audit items 224, 225, 226, 229, 293, 294, 315, and 369: LRA Section B.1.21and the associated table, are revised to state that the One-Time Inspection program will verify effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs by confirming the absence of loss of material, cracking and fouling, where applicable.

BVY 06-079 Page 5 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 235: In LRA Table 3.3.2-10 for the NUREG-1801 Vol. 2 Item for component types "humidifier housing" and "piping", change item VIII.F1-8 to item VII.F1-8. The incorrect number was entered due to a typographical error.

Audit item 242: LRA Table 3.5.2-1 is revised to delete line items for "Bellows (reactor vessel and drywell)". Also the corresponding line item in Table 2.4-1 is deleted.

Audit item 244: LRA Table 3.5.2-6 is revised to indicate that Note "A" applies to component seals and gaskets (doors, man-ways and hatches) with the aging management program of Structures Monitoring Program.

Audit item 248: LRA Table 3.5.2-6 is revised to change Note "A" to Note "C" for electrical and instrument panels and enclosures with a material of galvanized steel in a protected from weather environment. Aging effect and associated aging management program are unchanged.

Audit item 249: LRA Table 3.5.2-6 is revised to change Note "A" to Note "C" for flood curb with a material of galvanized steel in a protected from weather environment. Aging effect and associated aging management program are unchanged.

Audit item 250: LRA Table 3.5.2-1 is revised to change Note "E" to Note "A" for torus shell with an aging effect of cracking-fatigue. Aging effect and associated aging management program are unchanged.

Audit items 255, 257, 258, 259, 263, and 278: The LRA is revised to indicate loss of material as an aging effect requiring management with the Structures Monitoring Program as the aging management program and the NUREG-1801 Vol. 2 Item as III.B4-7 with a Note C in the following cases.

.1-. Ta-ble3.5.2-5fortans-mss-n-t-wer-s-wiha-materialI of galvanized steel in an exposed to weather environment

2. Table 3.5.2-6 for conduit with a material of galvanized steel in an exposed to weather environment

3. Table 3.5.2-6 for conduit support with a material of galvanized steel in an exposed to weather environment

4. Table 3.5.2-6 for electrical and instrument panels and enclosures with a material of galvanized steel in an exposed to weather environment

5. Table 3.5.2-6 for structural bolting with a material of galvanized steel in an exposed to weather environment LRA Table 3.5.1, item 3.5.1-50 is revised to include the following in the Discussion column: "Consistent with NUREG-1 801 for galvanized steel components in outdoor air.

The Structures Monitoring Program will manage loss of material."

BVY 06-079 Page 6 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 267:

LRA Table 3.5.2-1 is revised to add the following line.

Torus 1

PB, Carbon Protected Cracking TLAA-111.14-4 mechanical SSR steel from (fatigue) metal (C-13) penetrations weather fatigue LRA Table 3.5.2-1 is revised to delete the following line.

Drywellto PB, Carbon Protected Cracking TLAA" 11.1.1.1-4 3.5.1-8 A

torus vent ISSR steel from (fatigue) metal system weather fatigue (C-21)

The Discussion column for LRA Table 3.5.1 item 3.5.1-8 is revised to read as follows.

"Fatigue analysis is a TLAA for the torus shell. Fatigue of the torus to drywell vent system is event driven and the analysis is not a TLAA. See Section 3.5.2.2.1.6.

The Discussion column of LRA Table 3.5.1 item 3.5.1-9 is revised to read as follows.

"Fatigue analysis is a TLAA for the torus penetrations. See Section 3.5.2.2.1.6.

The Discussion column of LRA Section 3.5.2.2.1.6 is revised to read as follows. 'TLAA

.are evaluated in accordance with 10 CFR 54.21(c) as documented in Section 4. Fatigue TLAAs for the torus and associated penetrations are evaluated and documented in Section 4.6.

LRA Section 3.5.2.3, Time-Limited Aging Analyses, is revised to read as follows. 'TLAA identified for structural components and commodities include fatigue analyses for the torus and torus penetrations. These topics are discussed in Section 4.6."

Audit items 268 and 269: The LRA is revised as follows.

1. For clarification, the Discussion column of Table 3.5.1, line items 3.5.1-12 and 3.5.1-13 is revised to add the following statement at the end of the existing information.

"See Section 3.5.2.2.1.8".

2. LRA Section 3.5.2.2.1.8 is revised to read as follows. "Cyclic loading can lead to cracking of steel and stainless steel penetration bellows, and dissimilar metal welds of BWR containments and BWR suppression pool shell and downcomers. Cracking due to cyclic loading is not expected to occur in the drywell, torus and associated penetration bellows, penetration sleeves, un-braced downcomers, and dissimilar metal welds. A review of plant operating experience did not identify cracking of the components, and primary containment leakage has not been identified as a concern.

Nonetheless the existing Containment Leak Rate Program with augmented ultrasonic exams and Containment Inservice Inspection - IWE, will continue to be used to detect cracking. Observed conditions that have the potential for impacting an intended function. are evaluated or corrected in accordance with the corrective action process. The Containment Inservice Inspection - IWE and Containment Leak Rate programs are described in Appendix B."

Audit item 279: For clarification, LRA Table 3.5.1, Item 3.5.1-52 discussion is revised to read as follows. "Loss of mechanical function due to the listed mechanisms is not considered an aging BVY 06-079 Page 7 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 effect. Such failures typically result from inadequate design or operating events rather than from the effects of aging. Failures due to cyclic thermal loads are rare for structural supports due to their relatively low temperatures."

Audit item 280: For clarification, LRA Table 3.5.1, Item 3.5.1-54 discussion is revised as follows. "Loss of mechanical function due to distortion, dirt, overload, fatigue due to vibratory, and cyclic thermal loads is not considered an aging effect requiring management. Such failures typically result from inadequate design or events rather than the effects of aging. Loss of material due to corrosion, which could cause loss of mechanical function, is addressed under Item 3.5.1-53 for Groups B1.1, B13.2, and B13.3 support members."

Audit item 282: For clarification, LRA Table 3.5.1, Line Item 3.5.1-34 discussion is revised to add "See Section 3.5.2.2.2.4(1)".

Audit item 283: LRA Table 3.5.1, Item 3.5.1-35 discussion is revised to replace ACI 301 with ACI 318 and add "See Section 3.5.2.2.2.4(2)" at the end of the existing discussion.

Audit item 284: LRA Table 3.5.1, Line item Number 3.5.1-36 discussion column is revised as follows. "Reaction with aggregates is not an applicable aging mechanism for VYNPS concrete components. See Section 3.5.2.2.2.1(5) (although for Groups 1-5, 7, 9 this discussion is also applicable for Group 6). See Section 3.5.2.2.2.4(3) additional discussion. Nonetheless, the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components."

To correct an administrative error, the heading of LRA Section 3.5.2.2.2.4 (3) is revised to begin with "Cracking Due to Expansion, Reaction with Aggregates...". The term stress corrosion cracking is deleted from the heading as it does not apply to this section.

Audit item 285: The Discussion column of LRA Table 3.5.1, Item Number 3.5.1-37, is revised to state the following. "Not applicable. Nonetheless the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components.

See Section 3.5.2.2.2.4(3)".

Audit item 286: For clarification, LRA Table 3.5.1, Item Number 3.5.1-40 discussion column is revised to add "See Section 3.5.2.2.2.6(1)".

Audit Item 300 and 304: LRA Table 3.3.2.13-32 is revised to replace the aging management program of One-Time Inspection with Periodic Surveillance and Preventive Maintenance for all line items containing carbon steel and copper alloy with an environment of untreated water.

I Audit item 309 and 321: LRA Section 3.1, 3.2, 3.3 and 3.4 tables will be revised to remove

'TLAA-metal fatigue" from all line items for which Section 4 does not discuss evaluation of a TLAA. Line by line changes to the tables are provided in Attachment 3 to this letter.

Audit item 318: LRA Table 4.3-1 is revised to remove the NUREG/CR-6260 values for core spray safe end, feedwater piping, RHR return piping, and RR piping tee and replace them with N/A. Commitment 27 requires an analysis that addresses the effects of reactor coolant environment on fatigue performed to an NRC-approved version (year).of the ASME code.

BVY 06-079 Page 8 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Audit item 319: The last paragraph of LRA Section 4.3.1.1 is replaced with the following. 'The VYNPS Fatigue Monitoring Program will assure that the allowed number of transient cycles is not exceeded. The program requires corrective action if transient cycle limits are approached.

Consequently, the TLAA (fatigue analyses) based on those transients will remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). However, when the effects of reactor coolant environment on fatigue are considered in the existing fatigue analyses, several locations have a projected cumulative usage factor in excess of 1.0. See Section 4.3.3 for further discussion of the effects of reactor water environment on fatigue."

Audit item 320: LRA Reference 4.3.1 on page 4.3-9 is revised as follows; "4.3-1 Sojka, R. E.

(VYNPS), to USNRC Document Control Desk, "Response to Request for Additional Information Regarding Vermont Yankee Core Shroud Modification," BVY 96-96, letter dated August 7, 1996."

Audit item 322: LRA Section 4.3.1.3 is replaced with the following.

"VYNPS replaced reactor recirculation (RR) system piping in 1986. Also replaced were connecting portions of the residual heat removal (RHR) system piping. The new piping was designed and analyzed to ANSI B31.1 but was inspected and tested to ASME Section III requirements. Stress analyses for the reactor recirculation system were performed to B31.1 requirements. B31.1 does not require a detailed fatigue analysis that calculates a CUF, but allows up to 7000 cycles with a stress reduction factor of 1.0 in the stress analyses. The 7000 thermal cycle assumption is valid and bounding for 60 years of operation. Therefore, the pipe stress calculations are valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

There are no TLAA for Class 1 non-piping components other than the reactor vessel as none of them are designed to codes that require fatigue analyses.

UFSAR Section 4.6.3 states that the main steam isolation valves are designed for 40 years based on 100 cycles of operation the first year and 50 cycles of operation per year thereafter. This statement may be interpreted to imply a TLAA. This TLAA will remain valid through the period of extended operation per 10 CFR 54.21(c)(1)(i). The MSIVs will not exceed 2050 cycles in 60 years (34 cycles per year)."

In addition LRA section 4.3.2 is replaced with the following.

'The design of safety class 2 and 3 piping systems incorporates the Code stress reduction factor for determining acceptability of piping design with respect to thermal stresses. The design of ASME B31.1 Code piping also incorporates stress reduction factors based upon an assumed number of thermal cycles. In general, 7000 thermal cycles are assumed, leading to a stress reduction factor of 1.0 in the stress analyses.

VYNPS evaluated the validity of this assumption for 60 years of plant operation. The results of this evaluation indicate that the 7000 thermal cycle assumption is valid and bounding for 60 years of operation. Therefore, the pipe stress calculations are valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

There are no TLAA for any non-Class 1, non-piping components as they are not built to codes that require fatigue analyses.

BVY 06-079 Page 9 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 Some applicants for license renewal have estimated that piping in the primary sampling system will have more than 7000 thermal cycles before the end of the period of extended operation. The sampling system is used to take reactor coolant samples every 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months during normal operation. However, the normal samples are taken from the RWCU filter influent, where the water has already been cooled. Thus normal sampling does not cause a thermal cycle. Alternate samples may be taken directly from the B discharge header of the reactor recirculation system via containment penetration X-41; however, this is an infrequently performed procedure and this piping, designed to ASME B31.1, will not exceed 7000 cycles prior to 60 years of operation."

Audit item 335: LRA Table 3.5.2-6 lists the aging effects for component Penetration sealant, material elastomer in a protected from weather environment as "cracking" and "change in material properties." For clarification, the LRA is revised to separate this component line item into two line items as follows:

1. Delete line item:

Penetration EN, Elastomer Protected

Cracking, Fire I,,.A6-3.5.1-C sealant FB, from Change protection, 12 44

FLB, weather in Structures (fire, flood,i PB, material Monitoring radiation)

SNS properties

2. Add line item:

Penetration EN, Elastomer -Protected

Cracking, Fire VII.G-1 3.3.1-B sealant FB, from Change in protection (A-19) 61 PB, weather material (fire)

SNS properties

3. Add line item:

Penetration EN, Elastomer Protected

Cracking, Structures III.A6-3.5.1-C sealant

FLB, from Change Monitoring 12 44 (flood, PB, weather in (TP_7) radiation) material properties Audit item 336: LRA Table 3.5.2-6 lists the aging effects for the Seismic isolation joint, with a material of elastomer in a protected from weather environment as "cracking" and "change in material properties." For clarification, the LRA is revised to make the following changes.

1. Note C is changed to Note E for this line item.

2. The discussion in Table 3.3.1 line Item 3.3.1-61, Page 3.3-49 is revised to read as

follows. 'This line item was not used in the auxiliary systems tables. Fire barrier BVY 06-079 Page 10 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 seals are evaluated as structural components in Section 3.5. Cracking and change in material properties of elastomer seals, including seismic isolation joints located in fire barriers, are managed by the Fire Protection Program."

3. An additional line item is added to read as follows.

Seismic SSR Elastomer Protected

Cracking, Structures Ill.A6-3.5.1-C isolation from Change in Monitoring 12 344 joint.

weather material (TP-7) properties Audit item 337: LRA Table 3.5.2-6 lists the aging effect for Fire doors, with a material of carbon steel in a protected from weather environment as "loss of material." For clarification, the LRA is revised to change 'Note C' to 'Note B' for this line item.

Audit item 342: LRA Section 3.3.2.2.13 Loss of Material due to Wear is revised to state the following:

'Wear is the loss of surface layers due to relative motion between two surfaces. AtVYNPS, in the auxiliary systems, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems."

Audit item 345: LRA Table 3.3.2-13 lists the aging effect for component type of bolting, with a material of stainless steel in an air - outdoor (ext) environment as "none." The LRA is revised to identify loss of material as an aging effect for this line item as shown below.

IBolting Pressure StainlessJ Airr oss-of SystemG boundary steel outdoor material walkdown Audit item 350: LRA Section A.2.1.31 Structures Monitoring-Vernon Dam FERC Program is replaced with the following. "The Vernon dam is subject to the Federal Energy Regulatory Commission (FERC) inspection program. This program consists of visual inspections in accordance with FERC guidelines and complies with Title 18 of the Code of Federal Regulations, Conservation of Power and Water Resources, Part 12 (Safety of Water Power Projects and Project Works) and Division of Dam Safety and Inspections Operating Manual.

The operation inspection frequency for licensed and exempt low hazard potential dams is biennially. As indicated in NUREG-1801 for water control structures, NRC has found that FERC

/ US Army Corp of Engineers dam inspections and maintenance programs are acceptable for aging management.

Audit item 354: The LRA is revised to delete Sections 4.7.2.5, 4.7.2.6, A.2.2.7 and A.2.2.8.

Also the component type of vessel ID attachment welds and instrument penetrations in LRA Table 4.1-1 is deleted. The items discussed in these sections do not meet the definition of time-limited aging analyses.

BVY 06-079 Page 11 of 12

ATTACHMENT 2 LICENSE RENEWAL APPLICATION SUPPLEMENT AMENDMENT LIST, Revision 1 In LRA table 3.1.2-1 (page 3.1-54) for the component type of internals attachments the line with the aging effect of cracking-fatigue and TLAA-metal fatigue as the aging management program is deleted. Cracking managed by the BWR Vessel ID Attachment Welds Program remains in the table.

I n LRA table 3.1.2-1 (page 3.1-44) for the component type of nozzles, instrumentation, Ni1 and N12, the line item with the aging effect of cracking-fatigue and TLAA-metal fatigue as the aging management program is deleted. Cracking managed by the BWR Penetrations Program remains in the table.

Audit item 371: LRA Section B.1.11 is revised as follows. 'The VYNPS Fatigue Monitoring Program includes counting of the cycles incurred by the plant. Five transients are monitored by plant operations and recorded as they occur. It is projected that less 60% of the design cycles for these five transients will be used through the first 60 years of operation, including the period of extended operation. The remaining transients are monitored by plant engineering based on review of operating data at the end of each fuel cycle. These remaining transients are summarized in the Fatigue Monitoring Program as the sixth transient (reactor startups and shutdowns). Engineering evaluates these transients and advises operations if the number of design cycles is being approached."

Audit item 373: LRA Section 3.3.2.2.13 Loss of Material due to Wear is revised to state, 'Wear is the removal of surface layers due to relative motion between two surfaces. At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems."

Audit item 376: LRA Table 3.3.1 line item 3.3.1-69 is revised to remove the reference to the One-Time Inspection-Program.

Audit item 379: LRA Table 3.5.1 line item 3.5.1-16 discussion is revised to add the following paragraph. "For reactor building seals and gaskets, the Periodic Surveillance and Preventive Maintenance Program manages cracking and change in material properties for the railroad inner and outer lock doors elastomer seals."

Audit item 382: The operating experience discussion in LRA Appendices 8.1.17, B.1.18, and B.1.19 is replaced with the following.

"This program is a new aging management program. Industry operating experience that forms the basis for the program is described in the operating experience element of the NUREG-1 801 program description. VYNPS plant-specific operating experience has been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1 801, the VYNPS program will manage all of the aging effects identified in the Operating Experience section of NUREG-1 801.

The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience. As such, this program will provide reasonable assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed."

BVY 06-079 Page 12 of 12

BVY 06-079 Docket No. 50-271 Vermont Yankee Nuclear Power Station License Renewal Application - Amendment 11 Time Limited Aging Analysis Table List, Revision 1

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Audit item 309, 321 and 354 - Tables and text of LRA Sections 3.1, 3.2, 3.3 and 3.4 are modified as follows:

I Table 3.1.2-1 Reactor Vessel Closure flange Pressure Low alloy Air-indoor (ext) GaGking T'._AA.

1 3.4-.2 G,404 Aging effect entry for studs, nuts, boundary steel fatigue fatkiue (R-"

component line deleted -

washers and Cracking managed by bushings Reactor Head Closure Studs Program in following entry of line.

Incore housing Pressure Stainless Air-indoor (ext) GraGkig -

Aging effect entry for bolting boundary steel fatigue fatigue component line deleted -

Flange bolts Cracking managed by

Flange Inservice Inspection

Nut and washer Program in following entry of line.

Other pressure Pressure Low alloy Air-indoor (ext) G*aekiig TAA F--etal I-7 3.4.

G, -404 Aging effect entry for boundary bolting boundary steel fatigue fatigue (R4))

component line deleted -

" Flange bolts and Cracking managed by nuts (N6A, N6B, Inservice Inspection N7)

Program in following entry

" CRD flange of line.

caps-crews and washers CAP Pressure Stainless Treated water Gfaekinig-TL.AA, IAtl 7 3.4.4 A

Aging effect entry for

CR0 return line boundary steel

>270QF (int) fatigue fatigue (R-"

component line deleted -

(N9)

Cracking managed by BWR CRD Return Line Nozzle Program in following entry of line.

BVY 06-079 Page 1 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Intended Aging Effect Aging NUREG-Table Component Type Function Material Environment Requiring Management 1801 Vol.

Notes Change Description Management Programs 2 Item I Item Thermal sleeves Pressure Stainless Treated water G=aGkinag--

n P-A--

A Aging effect entry for

" Recirc inlet (N2) boundary steel

>270QF (int) fatigue ftue (R4)4) component line deleted -

Core spray (N5)

Cracking managed by BWR Vessel Internals Program in following entry of line.

Therrmal sleevoes Peeure SlainieMss T*eated-wate.

Gaekig-FT=AA,*-etal lX44-

.1.-2 A

Deleted entire line -

.....d t......oteunda. y steel and

>2702F nt) fatigue fatigue (R-04)

Feedwater inlet thermal Niekel-sleeves are not welded to based nozzles and are not subject aUGy to aging management review (See audit items 209 and 291).

Weld Pressure Nickel-Treated water Craking-TL, me

-nmetal 4

-,3.1.1-2 A

Aging effect entry for

SLC nozzle to boundary based

>2702F (int) fatigue fatigue (R

component line deleted -

safe end weld alloy Cracking managed by BWR (N10)

Penetrations Program in following entry of line.

Table 3.1.2-2 Reactor Vessel Internals Control rod guide Support for Stainless Treated water Gr-aeki-g-T-LAA, etal WI-14 3.4.1-A Aging effect entry for tubes Criterion steel

>2709F (int) fatigue fatigue

(

component line deleted-

Tubes

.(a)(1)

Cracking managed by BWR equipment Vessel Internals Program in following entry of line.

Control rod guide Support for CASS Treated water Gaekin9-TIAA-metal l-VB4--44 2-.44--

A Aging effect entry for tubes Criterion

>4829F (int) fatue fatigue (R-.6) component line deleted -

Bases (a)(1)

Cracking managed by BWR equipment Vessel Internals Program in following entry of line.

Core plate Support for Stainless Treated water GraGking-1 T-AA-metal

!.4-44 4-.4 -E A

Aging effect entry for

" Plate, beams Criterion steel

>270QF (int) fatigue fatigue (R-83) component line deleted -

" Blocks, plugs, (a)(1)

Cracking managed by BWR

" Alignment equipment Vessel Internals Program in assemblies following entry of line.

BVY 06-079 Page 2 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Intended Aging Effect Aging NUREG-Table ComponentType Material Environment Requiring Management 1801 Vol.

1 Item Notes Change Description Management Programs 2 Item Core spray lines Flow Stainless Treated water G;aekiP--

T'bAA.-metai IIIB1-14 3.1-5 A

Aging effect entry for distribution steel

>2 7 0F (int) fatigue fatigue (R-53) component line deleted -

Cracking managed by BWR Vessel Internals Program in following entry of line.

Fuel support Support for CASS Treated water

-GFaGkig

^- ^LAA4-el

,*, 144 3.4.5 A

Aging effect entry for pieces Criterion

>4829F (int) fatigue fatigue (R-63) component line deleted -

" Orificed supports (a)(1)

Cracking managed by BWR

" Peripheral equipment Vessel Internals Program in supports following entry of line.

Incore dry tubes Pressure Stainless Treated water Gaekfr-TLA4A-e M131-14 3.-1-6 A

Aging effect entry for boundary steel

>270QF (ext) fatigue fatigue (R-43) component line deleted -

Cracking managed by BWR Vessel Internals Program in I

_following entry of line.

Incore guide tubes Pressure Stainless Treated water GraGkiR -

T.AA-metal,.B-"4 3-.4-5 A

Aging effect entry for boundary steel

>2702F (ext) fat§ue faatigue (R-63) component line deleted -

Cracking managed by BWR Vessel Internals Program in following entry of line.

BVY 06-079 Page 3 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Intended Aging Effect Aging NUREG-Table No Component Type Function Materal Environment Requiring Management 1801 Vol.

1Te tes Change Description Management Programs 2 item Jet pump Floodable Stainless Treated water Gr-aTki TA-meta 4--4 m34.

A Aging effect entry for assemblies volume steel

>2702F (Int) fatigue fatigue

(

component line deleted -

Risers, riser Cracking managed by BWR braces Vessel Internals Program in

Riser hold down following entry of line.

bolts

" Mixer barrels and adapters

" Restraint

brackets, wedges, bolts

" Diffusers and tailpipes

" Adapter upper rings Jet pump Floodable Nickel-Treated water G

-aG4kn-TLAA-metal W.134-!4 3..-5 A

Aging effect entry for assemblies volume based

>2709F (int) fatigue fatigue (R43 component line deleted -

" Hold-down alloy Cracking managed by BWR beams Vessel Internals Program in

" Adapter lower following entry of line.

ring Jet pump castings Floodable CASS Treated water Giaeking--

TIM.A-meItVa 1-14 3.4!-*-4 A

Aging effect entry for

Transition pi.ece volume

>482QF (int) fatigue fatigue (R-63) component line deleted -

Inlet elbow/

Cracking managed by BWR nozzle Vessel Internals Program in

Mixer flange following entry of line.

and flare

Diffuser collar Shroud Floodable Stainless Treated water

,,king,-

TAA*Fnetal W.13144 344 6 A

Aging effect entry for volume steel

>270QF (int) fatigue fatigue (R-63) component line deleted -

Cracking managed by BWR Vessel Internals Program in following entry of line.

BVY 06-079 Page 4 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Intended Aging Effect Aging NUREG-Table Component Type Fntin Material Environment Requiring Management 1801 Vol.

1 Item Notes Change Description Management Programs 2 Item Shroud support Support for Nickel-Treated water Gakin-1LAA metal W.1B4-!4 3.4.4 A

Aging effect entry for

" Ring, cylinder, Criterion based

>2709F (int) fatigue4 Wge (R-63) component line deleted -

and legs (a)(1) alloy Cracking managed by BWR

" Access hole equipment Vessel Internals Program in cover following entry of line.

Top guide Support for Stainless Treated water Gra.ki, --

TLAA-metal V.6,1-I44 341.-6 A

Aging effect entry for assembly Criterion steel

>2702F (int) fatigue faiue (R-component line deleted -

(a)(1)

Cracking managed by BWR equipment Vessel Internals Program in L _following entry of line.

Table 3.1.2-3: Reactor Coolant System Pressure Boundary Detector (CRD)

Pressure Stainless Treated water CGrckig -

1TAA - me IV.GI !45 3.4.4-3 A

Aging effect entry for boundary steel

>270°F (int)

Wfaiiue a

(R-220) component line deleted -

Cracking managed by One-Time Inspection Program in

_previous entry of line.

Drive (CRD)

Pressure Stainless Treated water Ga"ki*g* -

-ea

34.

_*3 A

Environment for this boundary steel

>2700r-(i.)

fatigue fatigue (R-22-)

component line changed.

CRD drive temperatures maintained below threshold for fatigue. Aging effect entry for component line deleted.

BVY 06-079 Page 5 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Intended Aging Effect Aging NUREG-Table Component Type Function Material Environment Requiring Management 1801 Vol.

1 Item Notes Change Description Management Programs 2 Item Pump casing and Pressure CASS Treated water Gacking--

e VG.C1-5 3.-4.-3 A

Aging effect entry for cover (RR) boundary

>482°F (int) fatigue fatw (R 220) component line deleted -

Cracking managed by BWR Stress Corrosion Cracking and Inservice Inspection Programs in preceding entry of line.

Restrictors (MS)

Flow CASS Treated water arking T=AA-meta4 e

4V.CI4-4 3.-1.

3 A

Aging effect entry for control

>4820F (int) fatue fatigue (R 220) component line deleted -

Cracking managed by One-Time Inspection Program in preceding entry of line.

Intended Aging Effect Aging NUREG-Table Component Type Function Material Environment Requiring Management 1801 Vol.

1 Item Notes Change Description Management Programs 2 Item Table 3.2.2-1: Residual Heat Removal System Heat e

,,v*,ue G

,,.ated wate GFari_

MeafatgueV.D2-3a3 G

Line deleted. See next line.

(Shel J

b.u.doa Steel

o-,o=,4I fatigue T A(940)

Heat exchanger Pressure Carbon Treatedwater Cracking One-Time V.D2-32 3.2.1-1 E

New line item.

(shell) boundary steel

>270°F (int)

Inspection (E-1O)

(tubers)

P~eSGUre bouinda~y Stanese r T~eated vteF Graeki.~

> 27 PF-(eGt fatigue Metal atigueV 1 1.0~-14 Line deleted - Cracking managed by Water Chemistry Control - BWR augmented by One-Time Inspection in preceding line of table BVY 06-079 Page6 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision I intended Aging Effect Aging NUREG-Table Component Type Function Material Environment Requiring Management 1801 Vol.

1 Item Notes Change Description Management Programs 2 Item eaeh;;n P--essure Stgntcaie

,eaed wate aGkin, -

Meta f.atigue V

3*-34 3.3.12 G

Line deleted - Cracking (tuber.)

beGumary steelO~

,7,0F() fatigue T-IAA (A-62) managed by Water Chemistry Control - BWR augmented by One-Time Inspection in preceding fine of table Pump-casing ess.e Gar~be J.eated wae Gva.kiRg-

.. eal Wi*,,.

.. 02-3 3.24 -4 A Line deleted. See next line.

b.U..

ay steel

->2O"° 'gue (E)

(_---I_)_

Pump casing Pressure Carbon Treated water Cracking One-Time V.D2-32 3.2.1-1 E

New line item.

boundary steel

>2707F (int)

Inspection (E-10)

Table 3.2.2-4: High Pressure Coolant Injection System TPrcines-asiN PeSS4e Ca-ben Steam> 27- 02 CFang-Metal-fatigue VI12-5 3.4-4 G

Line deleted. See next line.

bcu~dar-y at"e (ipq) faiu T4=M*(*8 Turbine casing

! Pressure Carbon Steam >270°F Cracking One-Time VIII.B2-5 3.4.1-1 E

New line item.

i boundary steel (Int)

Inspection (S-08)

Table 3.2.2-5: Reactor Core Isolation Cooling

-U biRe Gaeing

.P.e.U.e Gar-be.

S.ea. >,220oF Gki-*g Metal fatigue V.132-5 3.4.

G Line deleted. See next line.

stee 0FI fatgu T_08 Turbine casing Pressure Carbon Steam > 22001 Cracking One-Time ViII.B2-5 3.4.1-1 E

New line item.

boundary steel (int)

Inspection (S-08) 3.3.2-13-36: Reactor Water Clean-Up System Heat exshanWe (she4l I

P~erssure beunda~y Staness Steel T-reated wateF I

GraGki~g-fatigue Metal atige V11.3 14 (A-624 Line deleted - Cracking managed by Water Chemistry Control - BWR augmented by One-Time Inspection in preceding line of table BVY 06-079 Page 7 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Intended Aging Effect Aging NUREG-Table Component Type Funten Material Environment Requiring Management 1801 Vol.

1 Item Notes Change Description Management Programs 2 Item PUMPpasaig P~e 9

Stainless eated wateF GaGki-Metal fati-.

V-.E.-44 3.34-a A

Line deleted - Cracking bounda Steel

>,27-00F (it) fatigue TI=AA (A-62) managed by Water Chemistry Control - BWR augmented by One-Time Inspection in preceding line of table Teue-e Sa4e lele-wati.

.,+

MetaI-fatiMue VIt.E3-14 3.3.4-2 A

Line deleted - Cracking beu.da:,

steel

>270F(iRt) fatigue T-AA (A-62) managed by Water Chemistry Control - BWR augmented by One-Time Inspection in preceding line of table 3.4.2-1: Main Condenser and MSIV Leakage Pathway Nea-exGha f

PFeSSUF9e St.ainIe.se Stea*..

2*0f=

,,aki-Metal-fatigue H

Line deleted - Cracking (tuer,,buGdS*eel,,,

(-it) fatigue T-managed by Water Chemistry Control - BWR augmented by One-Time inspection in preceding line of table BVY 06-079 Page 8 of 10

ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Table 3.2.1: Engineered Safety Features, NUREG-1801 Vol. 1 Further item Aging Etfect/

Aging Management Fute Item Component M

echi Pg rams Evaluation Discussion Change Description Number Mechanism Programs Recommended 3.2.1-1 Steel and stainless Cumulative fatigue TLAA, evaluated in Yes, TLAA Fatigue is a TLAA for Discussion modified as steel piping, piping damage accordance with 10 most components.

shown components, and CFR 54.21(c)

The One-Time piping elements in Inspection Program emergency core manages cracking for cooling system components susceptible to fatigue with no TLAA.

See Section 3.2.2.2.1.

Section 3.2.2.2.1 is revised as follows:

3.2.2.2.1 Cumulative Fatique Damage Where identified as an aging effect requiring management for components designed to ASME Code requirements, the analysis of fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are evaluated in accordance with 10 CFR 54.21(c). Evaluation of this TLAA is addressed in Section 4.3.

Where fatigue damage is identified as an aging effect requiring management for components with no fatigue design requirements, the aging effect is managed by inspection. The One-Time Inspection program will manage cracking due to fatigue for these components.

BVY 06-079 Page 9 of 10

D ATTACHMENT 3 LICENSE RENEWAL APPLICATION SUPPLEMENT TLAA TABLE CHANGES, Revision 1 Table 3.4.1: Steam and Power Conversion Systems, NUREG-1801 Vol. 1 g

EFurther Item Component Aging Effect/

Aging Management Evaluation Discussion Change Description Number Mechanism Programs Recommended 3.4.1-1 Steel piping, piping Cumulative fatigue TLAA, evaluated in Yes, TLAA Fatigue is a TLAA for Discussion modified as components, and damage accordance with 10 most components.

shown piping elements CFR 54.21(c)

The One-Time exposed to steam Inspection Program or treated water manages cracking for components susceptible to fatigue with no TLAA.

See Section 3.4.2.2.1.

Section 3.4.2.2.1 is revised as follows:

3.4.2.2.1 Cumulative Fatigue Damage Where identified as an aging effect requiring management for components designed to ASME Code requirements, the analysis of fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are evaluated in accordance with 10 CFR 54.21(c). Evaluation of this TLAA is addressed in Section 4.3.

Where fatigue damage is identified as an aging effect requiring management for components with no fatigue design requirements, the aging effect is managed by inspection. The One-Time Inspection program will manage cracking due to fatigue for these components.

BVY 06-079 Page 10 of 10

ML071150066

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ML071150066

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