ML070680348

4.19: Reactor Vessel Surveillance Program, Evaluation of Aging Management Programs, 01/25/2006

ML070680348
Person / Time
Site:	Vermont Yankee
Issue date:	01/25/2006
From:	Balduzzi M Entergy Nuclear Operations, Entergy Nuclear Vermont Yankee
To:	Office of Nuclear Reactor Regulation
References
BWRVIP-116-01 LRPD-02, Rev 1
Download: ML070680348 (291)

Text

r LRPD-02 VYNPS License Renewal Project Revision 1 Aging Management Program Evaluation Results Page 185 of 275 4.1 9 Reactor Vessel Surveillance ProQram A. Proqram Description The Reactor Vessel Surveillance Program complies with the guidelines for an acceptable Integrated Surveillance Program described in NUREG-1801,Section XI.M31, Reactor Vessel Surveillance. This program manages reduction in fracture toughness of reactor vessel beltline materials to assure that the pressure boundary function of the reactor pressure vessel is maintained for the period of extended 3 operation.

VYNPS is a participant in the Boiling Water Reactor Vessel and lnternals Project (BWRVIP) Integrated Surveillance Program (ISP) as approved by License Amendment 218. This program monitors changes in the fracture toughness properties of ferritic materials in the reactor pressure vessel (RPV) beltline region.

As BWRVIP-ISP capsule test reports become available for RPV materials representative of VYNPS, the actual shift in the reference temperature for nil-ductility transition of the vessel material may be updated. In accordance with 10CFR50 Appendix H, WNPS reviews relevant test reports to assure compliance with fracture toughness requirements and P-T limits.

(Ref. Bases Section 3/4.6.A, VYNPS Technical Specifications) 1 1

BWRVIP-116, "BWR Vessel and lnternals Project Integrated Surveillance Program (ISP) Implementation for License Renewal," describes the design and implementation of the ISP during the period of extended operation. BWRVIP-116 identifies additional capsules, their withdrawal schedule, and contingencies to ensure that the requirements of 10CFR50 Appendix H are met for the period of extended operation.

(Ref. Commitment Report BWRVIP-116-07)

This program is credited in the following.

AMRM-31, Reactor Pressure Vessel I $

B. Evaluation

1. Scope of Program The Reactor Vessel Surveillance Program includes all reactor vessel beltline materials as defined by 10 CFR 50 Appendix G, Section 1I.F.

I I 2. Preventive Actions I

I No actions are taken as part of this program to prevent aging effects or mitigate aging degradation.

LRPD-02 VYNPS License Renewal Project Revision 1 Aging Management Program Evaluation Results Page 186 of 275 Reactor Vessel Surveillance Program 3, Parameters Monitored/lnspected The Reactor Vessel Surveillance Program monitors reduction of fracture toughness of reactor vessel beltline materials due to neutron irradiation embrittlement. The BWRVIP ISP uses existing BWRVIP-ISP surveillance capsules in BWR plants, as well as supplemental capsules irradiated in host I plants, to provide data which bounds all operating plants. The capsules in the VYNPS vessel are spares, not currently scheduled for withdrawal. VYNPS plate and weld metal is represented by the surveillance capsule in Susquehanna Unit 1.

(Ref. Section 3.1, BVY 03-29)

4. Detection of Aging Effects The Reactor Vessel Surveillance Program detects the effects of reduction of fracture toughness prior to loss of the reactor vessel intended function in accordance with the information provided in Monitoring and Trending.

5. Monitoring and Trending The Reactor Vessel Surveillance Program uses existing BWRVIP-ISP surveillance capsules in BWR plants, as well as supplemental capsules irradiated in host plants, to provide data which bounds all operating plants. The capsules in the W N P S vessel are spares, not currently scheduled for withdrawal. VYNPS plate and weld metal is represented by the surveillance capsule in Susquehanna Unit 1.

(Ref. Section 3.1, BVY 03-29)

Representative capsule data will be evaluated using the methods in Regulatory Guide 1.99 in accordance with Appendix G to 10CFR50 for the determination of the actual shift in the reference temperature for nil-ductility transition (RTNDT)of the vessel material. Charpy shift results will be used to reevaluate embrittlement projections for vessel beltline materials represented by materials in the capsule.

If changes to pressure-temperature limits are required due to a reassessment of limiting RTNoTvalues, changes to the licensing basis will be requested. 1 (Ref. Section 3. 1, BVY 03-29)

Enhancement: The Reactor Vessel Surveillance Program will be enhanced proceduralize (in PP 7027 or a new procedure) the data analysis, criteria, and corrective actions described in this program description.

Although there are no plans to remove additional material surveillance specimens from VYNPS, the remaining two surveillance capsules will continue to reside in the RPV as a contingency.

(Ref. Section 3.1, BVY 03-29)

LRPD-02 VYNPS License Renewal Project Revision 1 Aging Management Program Evaluation Results Page 187 of 275 Reactor Vessel Surveillance Program

6. Acceptance Criteria VYNPS embrittlement projections will comply with 10CFR50 Appendix G limits for the period of extended operation.

RTNDT for material in the beltline will remain below screening criterion using end of life fluence.

Enhancement: The Reactor Vessel Surveillance Program will be enhanced to proceduralize (in PP 7027 or a new procedure) the data analysis, acceptance criteria, and corrective actions described in this program description.

Acceptable pressure-temperature curves for heatup and cooldown of the unit will be maintained in Technical Specifications. The operational EFPY shall not exceed the Technical Specification limits for the pressure-temperaturecurves.

(Ref. Section 3l4.6, VYNPS Technical Specifications)

,I 7. Corrective Actions Specific corrective action and confirmation will be implemented as follows.

If embrittlement projections drop below 50 ft-lbs, the margins of safety against fracture will be demonstrated to be equivalent to those of Appendix G of ASME Section XI. This could be accomplished by demonstrating that the equivalent Margin Analysis documented in BW RVIP-74 represents a bounding evaluation for the VYNPS reactor vessel.

If RTNDTfor material in the beltline is projected to exceed the screening criterion using end of life fluence, VYNPS may implement flux reduction programs that are II h .I reasonably practicable to avoid exceeding this criterion. If no reasonably practicable flux reduction program will avoid exceeding the screening criteria, VYNPS will submit a safety analysis to determine actions to prevent potential failure of the reactor vessel as a result of postulated events if continued operation beyond the screening criterion is allowed.

Enhancement: The Reactor Vessel Surveillance Program will be enhanced to proceduralize (in PP 7027 or a new procedure) the data analysis, acceptance criteria, and corrective actions described in this program description.

If a capsule is not withdrawn as scheduled by BWRVIP-ISP, the NRC will be notified and the withdrawal schedule will be updated and submitted to the NRC.

i (Ref. Section 5.7, B WRVIP-86-A)

8. Confirmation Process This attribute is discussed in Section 2.0, Background.

I 1

LRPD-02 VYNPS License Renewal Project Revision 1 Aging Management Program Evaluation Results Page 188 of 275

9. Administrative Controls This attribute is discussed in Section 2.0, Background.

10. Operating Experience i

Operating experience provides assurance that the program will be effective managing effects of aging so that components crediting this program can their intended function consistent with the current licensing basis period of extended operation. The fact that WNPS now BWRVIP ISP ensures that future operating experience BWRs will be factored into this program. For more information operating experience, see VYNPS Report LRPD-05, Review Results.

.QI .. C. References 10CFR50, Appendix G, Fracture Toughness Requirements, U.S. NRC 10CFR50, Appendix H, Reactor Vessel Material Surveillance Program Requirements, U.S. NRC B W 03-29, Technical Specifications Proposed Change No. 258, RPV Fracture Toughness and Material Surveillance Requirements, March 26, 2003 BWRVIP-86-A, BWR Vessel and lnternals Project Updated BWR Integrated Surveillance Program (ISP) Implementation Plan, EPRl Report 1003346, October 2002 Commitment Report BWRVIP-116-01, BWRVIP IS1 Implementation for License Renewal, 9/17/2003 PP 7027, Rev. 03, LPC 00, Reactor Vessel lnternals Management Program VYNPS Technical Specification, Amendment 228 D. Summary The Reactor Vessel Surveillance Program ensures that reactor vessel embrittlement is monitored and corrective actions are taken prior to exceeding allowable limits.

The Reactor Vessel Surveillance Program provides reasonable assurance that aging effects 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.

LRPD-02 VYNPS License Renewal Project Revision 1 Aging Management Program Evaluation Results Page 189 of 275 The following enhancement will be initiated prior to the period of extended operation.

Attributes Affected Enhancement

5. Monitoring and Trending The Reactor Vessel Surveillance Program

6. Acceptance Criteria will be enhanced to proceduralize (in

7. Corrective Actions PP7027 or a new procedure) the data analysis, acceptance criteria, and corrective actions described in this program description.

.. . I

XI.M31 REACTOR VESSEL SURVEILLANCE Program Description The Code of Federal Regulations, 10 CFR Part 50, Appendix H, requires that peak neutron fluence at the end of the design life of the vessel will not exceed I O " nkm2(E >IMeV), or that i reactor vessel beltline materials be monitored by a surveillance program to meet the American Society for Testing and Materials (ASTM) E 185 Standard. However, the surveillance program in ASTM E 185 is based on plant operation during the current license term, and additional surveillance capsules may be needed for the period of extended operation. Alternatively, an integrated surveillance program for the period of extended operation may be considered for a set of reactors that have similar design and operating features in accordance with 10 CFR Part 50, Appendix HI Paragraph 1I.C. Additional surveillance capsules may also be needed for the period of extended operation for this alternative.

The existing reactor vessel material surveillance program provides sufficient material data and dosimetry to monitor irradiation embrittlement at the end of the period of extended operation, and to determine the need for operating restrictionson the inlet temperature, neutron spectrum, and neutron flux. If surveillance capsules are not withdrawn during the period of extended operation, operating restrictions are to be established to ensure that the plant is operated under the conditions to which the surveillance capsules were exposed.

All capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements of ASTM E 185-82, to the extent practicable, for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the Nuclear Regulatory Commission (NRC) prior to implementation. Untested capsules placed in storage must be maintained for future insertion.

An acceptable reactor vessel surveillance program consists of the following:

1. The extent of reactor vessel embrittlement for upper-shelf energy and pressure-

&* . I temperature limits for 60 years is projected in accordance with the NRC Regulatory Guide (RG) I.99, Rev. 2, "Radiation Embrittlement of Reactor Vessel Materials." When using NRC RG 1.99, Rev. 2, an applicant has a choice of the following:

a. Neutron Embrittlement Using Chemistry Tables An applicant may use the tables in NRC RG 1.99, Rev. 2, to project the extent of reactor vessel neutron embrittlement for the period of extended operation based on material chemistry and neutron ff uence. This is described as Regulatory Position 1 in the RG.

b. Neutron Embrittlement Using Surveillance Data When credible surveillance data is available, the extent of reactor vessel neutron '

embrittlement for the period of extended operation may be projected according to Regulatory Position 2 in NRC RG I .99,Rev. 2, based on best fit of the surveillance data.

The credible data could be collected during the current operating term. The applicant may have a plant-specific program or an integrated surveillance program during the period of extended operation to collect additional data.

NUREG-1801. Rev. 1 XI M-102 September 2005

2. An applicant that determines embrittlement by using the NRC RG 1.99, Rev. 2, tables (see item 1[a], above) uses the applicable limitations in Regulatory Position 1.3 of the RG.

The limits are based on material properties, temperature, material chemistry, and fluence.

3. An applicant that determines embrittlement by using surveillance data (see item l[b],

above) defines the applicable bounds of the data, such as cold leg operating temperature and neutron fluence. These bounds are specific for the referenced surveillance data. For example, the plant-specificdata could be collected within a smaller temperature range than that in the RG.

4. All pulled and tested capsules, unless discarded before August 31, 2000, are placed in storage. (Note: These specimens are saved for future reconstitution use, in case the surveillance program is reestablished.)

5. If an applicant has a surveillance program that consists of capsules with a projected fluence of less than the 60-year fluence at the end of 40 years, at least one capsule is to remain in the reactor vessel and is tested during the period of extended operation. The applicant may either delay withdrawal of the last capsule or withdraw a standby capsule during the period of extended operation to monitor the effects of long-term exposure to neutron irradiation.

6. If an applicant has a surveillance program that consists of capsules with a projected fluence exceeding the 60-year fluence at the end of 40 years, the applicant withdraws one capsule at an outage in which the capsule receives a neutron fluence equivalent to the 60-year fluence and tests the capsule in accordance with the requirements of ASTM E 185.

Any capsules that are left in the reactor vessel provide meaningful metallurgicaldata (Le.,

the capsule fluence does not significantly exceed the vessel fluence at an equivalent of 60 years). For example, in a reactor with a lead factor of three, after 20 years the capsule test specimens would have received a neutron exposure equivalent to what the reactor vessel would see in 60 years; thus, the capsule is to be removed because further exposure would not provide meaningful metallurgical data. Other standby capsules are removed and placed in storage. These standby capsules (and archived test specimens available for reconstitution) would be available for reinsertion into the reactor if additional license renewals are sought (e.g., 80 years of operation). If all surveillance capsules have been removed, operating restrictions are to be established to ensure that the plant is operated under conditions to which the surveillance capsules were exposed. The exposure conditions of the reactor vessel are monitored to ensure that they continue to be consistent with those used to project the effects of embrittlement to the end of license. If the reactor vessel exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are altered, then the basis for the projection to 60 years is reviewed; and, if deemed appropriate, an active surveillance program is re-instituted. Any changes to the reactor vessel exposure conditions and the potential need to re-institute a vessel surveillance

! program is discussed with the NRC staff prior to changing the plant's licensing basis.

7. Applicants without in-vessel capsules use alternative dosimetry to monitor neutron fluence

! during the period of extended operation, as part of the aging management program (AMP) for reactor vessel neutron embrittlement.

8. The applicant may choose to demonstrate that the materials in the inlet, outlet, and safety injection nozzles are not controlling, so that such materials need not be added to the material surveillance program for the license renewal term.

September 2005 XI M-103 NUREG-1801, Rev. 1

The reactor vessel monitoring program provides that, if future plant operations exceed the limitations or bounds specified in item 2 or 3, above (as applicable}, such as operating at a lower cold leg temperature or higher fluence, the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. An applicant without capsules in its reactor vessel is to propose reestablishing the reactor vessel surveillance program to assess the extent of embrittlement. This program will consist of (1) capsules from item 6, above; (2) reconstitutionof specimens from item 4, above; I

and/or (3) capsules made from any available archival materials; or (4) some combination of the three previous options. This program could be a plant-specific program or an integrated surveillance program.

Evaluation and Technical Basis Reactor vessel surveillance program is plant-specific, depending on matters such as the composition of limiting materials, availability of surveillance capsules, and projected fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant submits its proposed withdrawal schedule for approval prior to implementation. Thus, further staff evaluation is required for license renewal.

References 10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements, Office of the Federal Register, National Archives and Records Administration, 2005.

ASTM E-185, Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels,American Society for Testing Materials, Philadelphia, PA. (Versions of ASTM E-185 to be used for the various aspects of the reactor vessel surveillance program are as specified in 10 CFR Part 50, Appendix.)

NRC Regulatory Guide 1.99, Rev. 2, Radiation Embritflement of Reactor Vessel Materials, U.S. Nuclear Regulatory Commission, May 1988.

NUREG-1801, Rev. 1 XI M-104 September 2005

Vermont Yankee Nuclear Power Station License Renewal Application Technical Information A.2.1.26 Reactor Vessel Surveillance Program WNPS is a participant in the Boiling Water Reactor Vessel and tnternals Project (BWRVIP) Integrated Surveillance Program (ISP) as incorporated into the plant Technical Specifications by Amendment 218. The Reactor Vessel Surveillance Program monitors changes in the fracture toughness properties of ferritic materials in the reactor pressure vessel (RPV) beltline region. As BWRVIP-ISP capsule test reports become available for RPV materials representative of VYNPS, the actual shift in the reference temperature for nil-ductility transition of the vessel material may be updated.

In accordance with Appendix H to IOCFRSO, VYNPS reviews relevant test reports to assure compliance with fracture toughness requirements and P-T limits.

BWRVIP-116, "BWR Vessel and lntemals Project Integrated Surveillance Program (ISP) Implementation for License Renewal," describes the design and implementation of the ISP during the period of extended operation. BWRVIP-116 identifies additional capsules, their withdrawal schedule, and contingencies to ensure that the requirements of 10CFR50 Appendix H are met for the period of extended operation.

A.2.1.27 Selective Leaching Program The Selective Leaching Program ensures the integrity of components made of cast iron, bronze, brass, and other alloys exposed to a raw water, treated water, or groundwater environment that may lead to selective leaching of one of the metal components. The program includes a one-time visual inspection and hardness measurement of selected components that may be susceptible to selective leaching to determine whether loss of material due to selective leaching is occurring, and whether the process will affect the ability of the components to perform their intended function for the period of extended operation.

A.2.1.28 Service Water Integrity Program The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water systems (SWS) will be managed for the period of extended operation. The SWS include the service water, residual heat removal service water, and alternate cooling systems. The program includes component inspections for erosion, corrosion, and blockage and performance monitoring to verify the heat transfer capability of the safety-related heat exchangers cooled by SWS. Chemical treatment using biocides and chlorine and periodic cleaning and flushing of redundant or infrequently used loops are the methods used to control or prevent fouling within the heat exchangers and loss of material in SWS components.

Appendix A Updated Final Safety Analysis Report Supplement Page A-20

Vermont Yankee Nuclear Power Station License Renewal Application Technical Information B.1.24 REACTOR VESSEL SURVEILLANCE Proaram Descriotion The Reactor Vessel Surveillance Program complies with the guidelines for an acceptable i Integrated Surveillance Program described in NUREG-1801,Section XI.M31, Reactor Vessel Surveillance. This program manages reduction in fracture toughness of reactor vessel beltline materials to assure that the pressure boundary function of the reactor pressure vessel is I

maintained for the period of extended operation.

VYNPS is a participant in the Boiling Water Reactor Vessel and lnternals Project (BWRVIP)

Integrated Surveillance Program (ISP) as approved by License Amendment 218. This program monitors changes in the fracture toughness properties of ferritic materials in the reactor pressure vessel (RPV) beltline region. As BWRVIP-ISP capsule test reports become available for RPV materials representative of WNPS, the actual shift in the reference temperature for nil-ductility transition of the vessel material may be updated. In accordance with 10CFR50 Appendix H, i VYNPS reviews relevant test reports to assure compliance with fracture toughness requirements and P-T limits.

a BWRVIP-116, BWR Vessel and lnternals Project Integrated Surveillance Program (ISP)

Implementation for License Renewal, describes the design and implementation of the ISP during the period of extended operation. BWRVIP-116 identifies additional capsules, their

! withdrawal schedule, and contingencies to ensure that the requirements of 10CFRSO Appendix H are met for the period of extended operation.

i NUREG-1801 Consistency The Reactor Vessel Surveillance Program at WNPS will be consistent with the program described in NUREG-1801,Section XI.M31, Reactor Vessel Surveillance, with one enhancement.

ExceDtions to NUREG-1801 None Enhancements I

The following enhancement will be initiated prior to the period of extended operation.

I i

I I

I i

Appendix B Aging Management Programs and Activities Page B-78 J

I i

Vermont Yankee Power Station License Renewal Application Technical Information I I Attributes Affected I Enhancement I

5. Monitoring and Trending Actions The Reactor Vessel Surveillance Program will

6. Acceptance Criteria be enhanced to proceduralize the data analysis,

7. Corrective Actions acceptance criteria, and corrective actions described in this program description.

Oeeratina ExDerience W N P S is a participant in the Boiling Water Reactor Vessel and lnternals Project (BWRVIP)

I

• -. . I Integrated Surveillance Program (ISP) as incorporated into the plant Technical Specifications by Amendment 218. The fact that WNPS participates in the 6WRVIP ISP ensures that future operating experience from all participating BWRs will be factored into this program.

Conclusion The Reactor Vessel Surveillance Program ensures that reactor vessel degradation is identified and corrective actions are taken prior to exceeding allowable limits. The Reactor Vessel Surveillance Program provides reasonable assurance that aging effects 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.

Appendix B Aging Management Programs and Activities Page B-79

LRPO-05 VYNPS License Renewal Project Revision 0 Operating Experience Review Results Paae 54 of I 2 2 Section 4.4.20 presents conclusions regarding the effectiveness of this program for managing aging effects.

3.4.21. Reactor Vessel Surveillance Program The VYNPS Reactor Vessel Surveillance Program is a condition monitoring program, which monitors reduction of fracture toughness of reactor vessel beltline materials due to irradiation embrittlement. The attributes of this program are described in LRPD-02 (Ref. 5.17).

The results of OE reviews described in Section 2.0 are as follows.

Item Issue OE Evaluation Action Item I BWRVIP-116 identifies additional VYNPS has committed to Regulatory capsules, their withdrawal schedule, and participate in the BWRVIP Commitment contingencies to ensure that the Integrated Surveillance Program NO.BWRVIP- requirements of 10CFR50 Appendix H (ISP)thereby ensuring that I16-01 are met for the period of extended operating experience from all operation. participating BWRs is factored into this program.

VYNPS to Plant specific surveillance requirements Technical specification criteria NRC Letter in technical specifications were replaced assure continuing compliance with BVY-03-029 with NRC-endorsed BWRVIP integrated 10 CFR 50 Appendix H and surveillance program (ISP) criteria. requirements for managing NRC to fracture toughness.

VYNPS Letter NVY-04-027 Section 4.4.21 presents conclusions regarding the effectiveness of this program for managing aging effects.

3.4.22. Service Water Integrity Program The VYNPS Service Water (SW) Integrity Program is an inspection, monitoring, and testing program, which manages loss of material, cracking and fouling on service water, residual heat removal service water, and alternate cooling system components and structures and components serviced by the service water systems. The attributes of this program, which relies on implementation of recommendations of NRC Generic Letter (GL)89-13, are described in LRPD-02 (Ref. 5.17).

The results of OE reviews described in Section 2.0 are as follows.

LRPD-05 VYNPS License Renewal Project Revision 0 Operating Experience Review Results Page 75 of 122 VYNPS program is consistent with the NUREG-I801 program with one exception; when reactor head closure studs are removed for examination, either a surface or volumetric examination is allowed. Since cracking initiates on the outside surfaces of bolts and studs, a qualified surface examination meeting the acceptance standards of IWB-3515 provides at least the sensitivity for flaw detection that an end shot ultrasonic examination provides on bolts or studs. Therefore, the VYNPS program is effective at managing loss of material and cracking for applicable components (Ref. 5.17)

The Reactor Head Closure Studs Program has been effective at managing aging effects. The Reactor Head Closure Studs Program provides reasonable assurance that the effects of aging will be managed such that the applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

4.4.21. Reactor Vessel Surveillance Program The Reactor Vessel Surveillance Program complies with the guidelines for an acceptable program described in NUREG-1801,Section XI.M31, Reactor Vessel Surveillance. This program manages reduction in fracture toughness of reactor vessel beltline materials to assure that the pressure boundary function of the reactor pressure vessel is maintained for the period of extended operation. (Ref. 5.17)

VYNPS is a participant in the Boiling Water Reactor Vessel and lnternals Project (BWRVIP)

Integrated Surveillance Program (ISP) as incorporated into the plant Technical Specifications by Amendment 218. This program monitors changes in the fracture toughness properties of ferritic materials in the reactor pressure vessel (RPV) beltline region. As BWRVIP-ISP capsule test reports become available for RPV materials representative of VYNPS, the actual shift in the reference temperature for nil-ductility transition of the vessel material may be re-established. In accordance with Appendix H to 10CFR50, VYNPS reviews relevant test reports and makes a determination or whether or not a change in Technical specifications is required as a result of the data. (Ref. 5.17)

BWRVIP-116, BWR Vessel and lnternals Project Integrated Surveillance Program (ISP)

Implementation for License Renewal, describes the design and implementation of the ISP during the period of extended operation. BWRVIP-116 identifies additional capsules, their withdrawal schedule, and contingencies to ensure that the requirements of 10CFR50 Appendix H are met for the period of extended operation. (Ref. 5.17)

The Reactor Vessel Surveillance Program has been effective at managing aging effects. The Reactor Vessel Surveillance Program provides reasonable assurance that the effects of aging will be managed such that the applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

4.4.22. Service Water integrity Program Recent performance test and inspection results (2004) provide evidence that the program is effective for managing aging effects for applicable components. For example, diesel generator service water cooled heat exchanger performance testing revealed no significant performance degradation, RHR heat exchanger inspection revealed no loss of material, cracking or fouling, a

Entergy Nudear Vermont Yankee, uc Entergy Nuclear Operations, Inc 185 Old Ferry Road Brattleboro, VT 05302-0500 March 26,2003 BVY 03-29 US.Nuclear Regulatory Commission ATTN: I)ocmnent#ntmlbsk Washingto& DC 20555 bf Snbjeet: Vermont Yankee Nuclear Power Station Li~eneeNO.DPR-28 (Docket NO.50-271)

Technical Specificaiions Proposed Change No. 258 RPVFractareTouphness and Material Sm&nce Radrements hvsuant to 10CFR50.90,Vermont Yankee' (W) hereby proposes amend its Facility Operating '

License, DPR-28, by mcorpOrating the attached proposed change into the VY Techaid SpecEdom. This proposed change adopts the Boiling Water Reactor Vessel and Jntemah Project Integrated Surveillance Program and updates presfllre and t e m p e m limitations for the mtctor coolant system.

Attachments 1 and 2 to W letter contain supporting i t & o d m and the safety assessment for the proposed change. Attachment 3 contains the determination of no significant baplrds considemtion.

Attachment 4 provides a proposed change to the Updated Final Safety Analysis Report regding the Integrated SurveilIance Program. Attachment 5 provides the marked-up version of the current i Technicat Specification and Bases pages, and Attachment 6 is the retyped Technical Specification and Basespages.

VY has reviewed the proposed change in accordaflce with 10CFR50.92 and concludes that the proposed change does not involve a significanthazards consideration.

VY has also determined that the proposed change satisfies the criteria for a categorical exclusion m accordace wifh IOcFR51.22(~)(9) and does nor require an environmental review. Therefore, pursuant to 10CFR51.22@), no environmental impact statement or environmental assessment needs to be prepared for this change.

Upon accepfance of &is proposed c h g e by the NRC, VY requests that a Iicense amendment be issued prior to the next scheduled refbeling outage (Spring 2004) for implementationwithin 60 days of its effixtive date. A license amendment is required prior to the end of the next refbeling outage because current Technical Specifications or pressure-tempemtmlimitations are only valid through the end of the current operating cycle, and current requirements for the removal of reactor vessel surveillance specimens would necessitate the removal of a surveillance capsule during the next refueling outage. Accordingly, VY respectfully requests timely approval of this license amendment EipeSt.

' Entergy Nuclear Vermont Yankee, LLC and Eutergy Nuclear Operations, Inc. are the Iicensees of the Vermont Yankee Nuclear Power Station

BVY 03-29 /Page 2 If you have any questions on this transmittal,please contact Mr.Len Gucwa at (802) 258-4225.

Michael A. B d d d Vice President, Operations STATEOF VERMONT 1

)ss WINDHAMCOUNTY 1 Then personally appeared before me, Michael A. Balduzzi, who, W in g duly sworn, did state fhat he is Vice President, operations of the Vermont Yankee Nuclear Power Station, that he is ddy authorized to execute and file the foregoing document, and that the statementstberem are true to the best of his knowledge and belief.

Thomas B. Silko, Notary Public My CornmiSSion Expires February 10,2007 Attachments cc: USNRC Region 1 Administrator USNRC Resident inspector VYNPS-USNRC Project Manager - VYNPS Vermont Department of Public Service

Vermont Yankee

> License Amendment and Technical Specification I

Proposed Change List

e. H

License Amendments and Changes The purpose of this note is to assist in clarifying use of the terms Amendment (to either the Facility License or the PDAWSAR) and Change to tech specs; both were issued and/or used by the AEC/NRC and VY in the VY Operating License revision process.

Amendments Once the Operating License was granted, the AEC, and later the NRC, authorized revisions or modifications to the Facility License by issuing Amendments. Initially, the AEC-issued Amendments were used only to transmit approved revisions or modifications to the specific conditions andor requirements incorporated in the License; e.g., financial qualifications, owners, Comrnission-approved environmental requirements requested by the states, increases in reactor power level, U-235 possession limits). At the outset, the AEC did not use Amendments for approval of tech spec changes (see footnote 2, below).

The amendment numbers issued by the AEC started with No. 1 (dated April 21,1972), which authorized possession and use of additional Special Nuclear and Byproduct Materials. Subsequent AEC/NRC-issued Amendment Nos. have been sequential with no break in number continuity. The last Amendment, as ofthe date of preparation of this note (November 17, 1998), was No. 162, issued on September 1, 1998.

VY also used amendment numbers to amend its License Application, but only for the specific purpose of identifying sequentially issued versions of the PDAR/FSAR, which form a part of the License .

Application. These Amendment Nos. also started with No. 1, thus replicating the first 35 AEC/NRC-issued Amendment Nos., but are unrelated thereto.

Changes The AEC initially issued their approval of VY-proposed tech spec changes using Change Nos., but this procedure changed with time*.

VY assigned Proposed Change (PC) Nos. to its requests for tech spec revisions; this started with PC No.

I, dated June 16, 1972. However, there were a limited number of earlier requests that were not assigned a PC No.

i i (I)

The PDAR,and subsequently the FSAR, were revised by issuing Amendments 1 through 35 thereof. Amendment IO of the PDAR became the FSAR on December 31, 1969, and subsequent changes were submitted continuing the Amendment No. sequence. Amendment 35 of the FSAR became Rev. 0 of the UFSAR on July 20,1982, in response to revisions to Part 50.7 1 dealing with updating of the FSAR. Subsequent issues of the UFSAR have been identified using Revision Nos.

(2)

The first 17 Change Nos. used by the AEC in approving tech spec changes proposed by VY were associated or correlated with Amendment Nos. This practice changed with the issuance of Change No. 18 on June 19,1974, when the AECs notification letter specifically stated that Amendment No. 7 to the License was issued incorporating Change No. 18.

(As an additional example, Amendment No. 12, issued on December 3, 1974, include[d] Change No. 23 to the Technical Specifications.) The practice of using both an amendment number and a change number when approving proposed tech spec changes ceased following the issuance of Change No. 29 on November 12, 1975. Thereafter, the NRC (the name of the agency was changed in January 1975) dropped the use of Change Nos., and all subsequent tech spec changes were approved using Amendment Nos. Page 2 of 38 T.Silko review as pan. of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change Submitted Letter No. (C: TS Change) 6/16/72 1 AOG Modification Description and Operation (Attachment A of PC No.1) 7/25/72 1 SupplementNo. 1 9118/72 I I I Accepts 1 I Modifi&tion 7/26/73 Supplement No.2 8/29/73 Page 3 of 38 T.Silkoreview as part o f W 2003-101-04

~

~

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change Submitted Letter No. (C: TS Change)

NO. Letter No.

3 2/26/73 W Interim Of-GasModification 511 1/73 3/15/73 Supplement No. 1 Approves 4/4p73 Supplement No. 2 Modification AEC Comments (5/14/73) --

9 3/19/73 Increase in Noble Gas Activity Release Rate 4/5/73 Denied 10 4/9/73 Senior Control Room Operator License Requirements 5/3/73 c-a (Modifies and Approves) 11 Revised Definition for Abnormal Occunences and Reporting Requirements 611 1/73 c-9 12 Corrective Update 1/17/74 C-13 1/28/74 C-15 21~n4 Correction 4tion4 C-17 13 Fuel Densification 8/24/73 c-10 I4 First Reload License Submittal 11/16/73 No TS Change required.

Supplement #1; Response to request for additional information 15 16 17 18 t- 10119/73 11/12/73 12/18/73 9/25/73 i 1/6/13 Effects of Inverted Control Blade Absorber Tubes; response to 9/5/73 request Supplement 2; End of Cycle Reactivity Analysis Additional confirmatory calculations Reduction in MAPLHGR for fuel assemblies with deviant enrichments Fuel Channel Wear, Investigation and Corrective Actions Taken Increase in MAPLHGR (based on fuel densification model in GEGAP mA)

Relief Valves settings c-11 c-12 C-14 C-16 3/19/74 Supplement No. 1 Supplement No. 2 Clarifies condition requiring closed cycle operation 4/4/14 A-6 Order to Inert Containment Atmosphere 6119/74 A-I, C-18 19 Technical Specification Subsection 3.3 Control Rod System - Rod Drop Accident 20 512 1/74 Second Core Reload 12/3/74 A-12, C-23 WVY 74-17 Supplement No. 1 1/26/74 WVY 74-25 Supplement No. 2 8/23/74 20 W Y 74-33 Request to load fuel pending approval of PC A-10, C-21 9/25/74 Page 4 of 38 T Silko review as part of UND 2003-101-04 c- >---

u 3 -

Proposed Change I

Initiatedby I I

Date Submitted I

I Title I

II Date Letter No.

Approved NRC Approval (A: Lie. Amend)

(C: TS Change)

No. I I LetterNo. I I I Proposed ECCS Modification

~

21 WVY 74-5 iu3n4 A- 1 1, C-22 6/25/74 WVY 74-31 Supplement No. 1 9/9/74 -.

WVY 74-35 Response to 9111/74 RAI 1011~74 WVY 74-38 Drawings to accompany response to 9111/74RAI 10nfl4 WVY 74-40 Testing and Analysis of Rwirc System Discharge Valves io~n4 WVY 74-45 Second set of Independently Interlocked Contactors 10/29/74 WVY 74-51 Supplement No. 2 i 1/13/74 WVY 74-61 Correction to Supplement 2 12/9/74 22 WVY 74-16 Removal of Neutron Flux DosimeterDuring First Refueling Outage 8/23/74 A-8, C-19 7125ff4 23 WVY 744'7 Revised ECCS Evaluation, GETAB and Revised Technical Specification 12/27/74 1013 1/74 Commission WVY 75-70 Supporting Information for Operation with Bypass Row Holes Plugged Order mot15 24 WVY 74-25 Off-GasSystem Isolation InstrumentationlCondenser Low Vacuum Trip Function 10/23/74 A-9, C-20 8/23/74 25 WVY 74-22 Preliminary Evaluation of Core Configuration 8120114 26 W V Y 75-17 Full Power with Relief Valve Inoperable 5/21/75 A- 13, C-24 3/3/75 27 W Y 74-64 Incorporate Provisions of Reg. Guide 1.16 1i15m A-17, C-28 12116/74 NRC letter (1 l/l0/75) with enclosures missing fiom 11/5/75 letter NRC letter (1/28/74) correction to 11/5/73 letter 28 WVY 75-24 Corrections Necessitated by Previous License Amendments/Organizational Changes 5/21/75 A-14, C-25 3/20/15 2/14/75 (Notice) 29 WVY 75-3 1 Limit Torus Suppression Pool Temperature (Response to NRC 2/14/75 letter) 10/8/75 A-16, C-27 313 1/75 NRC Notice of Proposed Issuance of Amendment (7115175)

Page 5 of 38 T.Silk0 review as pari of UND 2003-101-04

Proposed Change Initiatedby I Date Submitted I Title Date Approved Letter No.

NRC Approval

A: Lie. Amend)

C: TS Change)

No. I Letter~o. I I Single Valve Failurel14.4 kW/ft Technical Specification Increase in LHGR

~ ~~

30 1 WVY 75-38 11/12/75 A-18, C-29 W 14/75 I WVY 75-53 I Supplement 1 5128/75 I -_

WVY 75-61 1 Supplement 2 7/8/75 WVY 75-98 Supplement 3 9/15/75 WVY 75-100 Supplement 4 9/22175 WVY 75-104 Withdraws the 14.4kwlft portion of PC No. 30 9/23/75 31 WVY 75-47 I Standby Gas Treatment System 8/28/75 A-15, C-26 311 1/76 A-20 32 2/ 14/77 A-3 1 7116/75 WVY 76-87 SuppIement 1 7/15/76 33 WVY 75-102 Orderly Shutdown through Use of Open Cycle Upon Loss of Cooling Tower 11/21/77 All0 9/22/75 W V Y 76-56 Response to RAJ of 4/7/76 51ionti WVY 77-26 Supplemental Information 3/8/77 WVY 77-90 State Authorization Letters (VT& NH) 912am 34 WVY 75-71 APRM Setdown into the Reactor Protection System 3/12/76 A-2 1 7131175 WVY 75-83 Supplement 1 8/28/75 35 WVY 75-82 Snubber Surveillance to Protect Primary Coolant System 7/19/76 A-24 8/27/75 WVY 76-7 supplement 1 Page 6 of 38 T. Silko review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Tiffe Date Approved (A: Lic. Amend)

Change Submitted Letter No. ( C TS Change)

No. Letter No.

36 WVY 75-103 Surveillance Interval Change from 15 to 18Months 2/25/76 A-19 9/23/75 37 WVY 75-117 Change Table 3.1.1:Operator Response to a Failed Instrument Channel 4/29/76 A-22 12/8/75 -i 38 WVY 76-39 Changes Instrument 62 Electrical Surveillance Test Interval fiom a maximum of 18 to 22 4/29/76 A-23 1 4f7fl6 montths I 39 W V Y 76-43 Refueling of Reactor CodCycle 4 8/2/76 A-25 4/23/76 I I 5/25/76 WVY 76-77 6/23/76 I

I Response to RAI of 6/4/76 Correction I

WVY 76-80 Supplement 2 7/6/76 WVY 76-90 Response to RAT of 7/12/76 7119/76 1 40 WVY 76-82 Delete High Drywell Pressure Signal from Automatic Isolation for RHR Shutdown Withdrawn 7/8l76 Cooling Isolation Valves WVY 77-1 1 Response to RAI of 1/3/77 242177 WVY 78-39 4/20/78 1 -

1 Withdrawal Letter I 41 WVY 76-88 Operation and Surveillance Requirements for CAD System (see W V Y 76-67,dated Withdrawn 7/15/76 61/1/76)

FVY 83-62 Withdrawal Letter 6117/83 1 I 42 WVY 76-70 Deletion of Testing of Standby Gas Treatment System Gaskets and Doors 1I 19/79 A-49 I

6/8/76 WVY 7845 511lI78 1 Supplement 1; Testing Requirements for SBGT System I 43 WVY 76-85 Installation of 480 Volt Uninterruptible Power SupplyBmergency Core Cooling Valves 8/2n6 A-26 7/15/76 44 WVY 76-83 Modifies ConditionsJRequirements for Discharge of Condenser Cooling from 9/6/75to 91m6 A-28 76/76 SI3 1/76 WVY 77-29 Status of Appendix B Environmental Monitoring Requirements after Completion of Phase 3/15/77 IV Open Cycle Testing Page 7 of 38 T.Siko review as pari of UND 2003-101-04

Proposed Change Initiated by Date Submitted 1 Title Date Approved Letter No.

NRC Approval

A: Lic. Amend)

C: TS Change)

No. Letter No.

.5 WVY 76-89 Replacement of Valve Position Limiters with Inline Orifices 8/2/76 A-27 7/15/76 8/23/76 Correction WVY 76- 154 DrywelYSuppression Chamber Differential Pressure 1131/79 A-50 imon6 2128179 Correction WVY 77-42 Supplement 1 4/14/77 WVY 78-46 Additional Information 5/16/78 WVY 76-103 Use of Dose Integrating Devices in High Radiation Areas 6116/77 A-36 8/26/76 WVY 76-140 Supplement 1 11110176 WVY 77-34 Modification to prior submittals 38 I WVY 76-102 I Change MAF'LHGR Curves to Current Design Limlts (LHGW13.4 kw/ft) 2110177 A-30 m6n6 19 WVY 76-101 Spent and New Fuel StorageMovingRacks in Spent Fuel Pool 9/15/77 A-37 I 1/5/76 (SE sent 6110177)

WVY 77-10 Response to RAI of 1111/77 6/20/71

?I1 177 (Suppl 1 To SE)

I 3/30/77 NRC Summary of 3/27/77 Meeting WVY 77-36 I Response to RAl of 3/14/77 414177 WVY 77-44 Response to RAI of 4/15/77 4/27/77 WVY 77-52 Supplemental Dynamic Analysis in response to 3/14/77 Letter 5111/77 WVY 77-59 Modification of Description of supplemental Dynamic Analysis 6/3/77 50 9/2/76 Page 8 of 38 T.Silko review as part of UND 2003-101-04

I Proposed Change No.

Initiated by Date Submitted Letter No.

Title I Date Approved Letter No.

(A: Lie. Amend)

(C: TS Change) il WVY 76- 109 Single Recirculation Loop Settings and Lirnih Withdrawn I1/10/76 FWY 83-62 -..

Request to place PC on hold GI 17/83 FVY 86/22 3/12/86 Withdrawn - See PC 132 1 A-33 52 WVY 76-136 Pressure-Temperatme LirnitationdlOCFR Part 50, Appendix G 3l23R7 11/9/76 Expand Radiological Surveillance Program I

4/19/77 53 %VY76-121 10/15fl6 I A-35 54 WVY 76-133 MAPLHGR Curve Correction to 1/3 Drilled Core Withdrawn (see NRC letter 11/5/76 of 3125177)

No VY Letter Cycle 4 MAPLHGR Limits No.

iii9n7 WVY 77-15 Response to 2115fl7 telephone request 21113/77 WVY 77-16 Agreement to reanalyze LOCA response 2123117 NRC letter (3125177) concludes no MMLHCR restrictions required WVY 77-80 1 Withdrawal of Proposed Change 9114/77 WVY 76-134 Reactor Building Crane Surveillance Prior to Fuel Cask Handling 1/28/77 A-29 11/8/76 4/8/77 A-34 12/3/76 I WVY 77-30 I Response to UlSi71 RAI 3/11/77 I I WVY 77-27 1 R W M Operability Power Level Increase 9/30/11 A-39 3/9/77 I I I

Page 9 of 38 T.Silk0 review as part of UND 2003-101-04

I I NRC Approval Proposed Initiated by Date Title (A: Lic. Amend)

Change Siihdtted (C: TS Change)

No. Letter No.

59 WVY 77-31 Fire Protection Systems (see W V Y 77-8, dated 1/31/77, and NRC letter dated 12/2/76) 1/13/78 A43

?I1 .

", R / 'l ,l Y.

6/16/77 NRC Revised sample fire protection Tech Specs WVY 77-64 Supplement 1: Modification of Proposed Change pages - -

7/14/77 WVY 77-73 Restates VY position on Fire Protection Issues 8118/77 WVY 77-105 Supplement 2: Incorporates revisions agreed upon since 6/16/77 NRC letter revising 11/30/77 sample fire protection Tech Specs WVY 80-57 Self-Contained Breathing Apparatus for Control Room Personnel 4/7/80 WVY 77-60 Administrative Radiation Protection Controls (Compliance to R.G. 1.8) 9130177 A-39 6/8/77 WVY 77-69 High Drywell Trip Setpoint Revision from 2.0 to 2.5 psig 2/7/18 A44 8/5/77 W V Y 77-62 Cycle 5 Reload 9/30/77 A-39 7/ 1177 WVY 77-71 Supplement

.. 1 8/12/77 WVY 77-86 Supplement 2: Response to RAI of 9/ 1/77 9116/77 WVY 77-70 Phase 5 Open Cycle Testing 9/30/77 A-38 8/8/77 WVY 77-77 Supplemental Information 9/1/77 64 WVY 77-67 Increase Circ Water ph Limit to 8.5 8/4/77 W V Y 78-7 Supplemental Information: Basis page for change 7/3 1/78 A46 1/30/78 WVY 78-283 Calculations in support of PC (response to verbal request) 3/10/78 55 WVY 77-84 Inservice Inspection Requirements 9/30/77 A-39 911 -. . .

- . - 6/17 I WVY 77-94 MAPLHGR Limit Uprate 11/30/77 A-4 1 IO/ 12/77 67 I W V Y 77-103 11/23/77 I Increase CR Scram Tmes Withdrawn Page 10 of 38 T. Silk0 review as part of UNU 2003-101W

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lie. Amend)

Change Submitted Letter No. (C: TS Change)

No. Letter No.

6/17/83 Withdrawal letter FVY 83-62 58 WVY 77-100 Administration Organization, Corporate Organization - Westboro Changes Denied 11/7/77 -. 8/14/79 WVY 77-116 Supplement1 :Removal of Corporate and Plant Organization Charts Withdrawn 12/29/77 WVY 80-18 Supplement 2 Revised Current OrganizationalStructure in~ao W Y 80-61 Withdrawal of Proposed Change 4/15/80 69 WVY 77-108 Administrative - Monthly Reporting Requirement 12/29/77 A-42 11/22/77 70 WVY 77-1 15 Coolant Leakage LitnWAugmented IS1 Requirement (Outstandingportion cancelled by 6/20/78 A-45 12/29/77 WVY 82-39, PC No.77, S,upplement 1) (only includes FVY 86-2 Withdrawal of PC No. 77, Supplement 1, and unapproved portions of PC NO.70 Item Ill) 1/6/86 71 WVY 78-25 SRV Setpoint Requirements and Corrective Update Withdrawn 3/17/78 FVY 87-45 Withdrawal of FC 4/27/87 72 WVY 78-14 Safety-Relief Valve SurveillanceRequirements 7/16/79 2/2/78 Canceled by NRC WVY 79-107 Deletes PC from NRC Action Item List 9f 19n9 73 WVY 78-59 Reload 5 Licensing Submittal 10/10/78 A-47 tinin8 WVY 78-64 Response to RAI of 5/23/78 7/12/78 W V Y 78-82 Correction to 7/12/78 Letter 8MOfl8 WVY 78-89 Response to RAI of 8/31/78 9120178 Telecopy Responses to RAI of 9/29/79 10/5f78 Page 11 of 38 T.Silkoreview aspartofUND2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No. Submitted Letter No. (C: TS Change)

Letter No.

73 WVY 79-30 Supplement 1: MCPR Limits to end of Cycle 6 3130179 A-52 3/5/79 WVY 79-58 APRM Gain adjustment -_

5/9/79 Incorporates Physical Security Plan based on WVY 77-57 (5/25/77),WVY 78-100 2/23/79 A-5 1

[12/lt78) and letter dated 2/12/79 74 Complete Appendix B Rewrite - Nonradiological Environmental Technical Specifications 10113/78 A-48 8/16/78 2/22/80 A-56 WVY 78-83 Additional lnformation 8/31/78 W V Y 79- 18 Supplement I: Resubmittal of Water Quality Limits 2/23/79 7/3/79 NRC Rewrite of Appendix B in new format for review WVY 80-03 Documents EPA Acceptance 3 16 Demonstration Document 1/2/80 WVY 80-38 Submittal schedule for rewritten Technical Specification pages (see PC No. 87) 3/13/80 75 This number never used NA NA 76 WVY 79-5 Containment Purging During Normal Plant Operation Withdrawn 1/9/79 WVY 79-6 Additional Support for Purging Justification: Response to NRC letter (1 1/29/78) to cease 1/9/79 purging during operation WVY 79-148 Response to NRC letter 11/9/79 imn9 WVY 80-15 Supplemental Information to WVY 79- 148 1/21/80 WVY 80-8 1 Response to NRC letter 3/12/80 5/28/80 WVY 80-139 Supplemental Inforination to WVY 78-148 and WVY 80-15 responding to NRC letter 10/3/80 11/9/79 NRC 10/19/81 Request for additional information WVY 8 1-74 Additional responsc to NRC 3112/80 letter 43018 1.

FVY 81-83 Response to NRC questionaire of 31318 1 5/21/81 Page 12 of 38 T.Silko review as part of UND 2003-101-04

Proposed Change No.

Initiated by I Date Submitted I Title I Date Approved Letter No.

NRC Approval

A Lic. Amend)

C: TS Change)

I LetterNo. I 1 r6 I I NRC Request (12/8/81) for full annunciation of overridden status of safety systems I (including Purge and Vent Valves)

FVY 82-32 I Modification of manner of operation of Purge and Vent Valves due to requirement to inert 3/26/82 containment NRC acceptance (5/3/82) of FVY 82-32 response question to on valve orientation FWY 82-74 Response to NRC 5/3/82 questions 612282 FVY 83-62 Withdrawal Notification 6/17/83 17 WVY 79-09 Inservice Inspection and Testing Requirements inon9 WN 79-46 Re-request for delay in portion of IS1 Program 1/9/79 A-53 4/25/79 WVY 79-48 Licensing Fee for IS1 4125119 WVY 77-47 Delay in implementation of 10CFR50.55 411 l n 9 4/29/77 (Denied)

WVY 79-5 1 IS1 Program Description (Rev. 0) mom WVY 79-70 IS1 Program - Request for Relief msn9 W Y 79-72 Correction for 6/25/79 Letter 6/28/79 WVY 79-122 IS1 Program Description (Rev. 2)

WVY 80-75 IS1 Program Description (Rev. 3) 5/14/80 WVY 80-92 IS1 Program Description (Rev. 4) 7/1/80 WVY 80-142 IS1 Progam Description (Rev. 5 )

10/10/80 Page 13 of 38 T.Silk0 review as part of UND 2003-101-04

1 NRC Approval Proposed Date Title Date Approved [A: Lic. Amend)

Change No. Submitted Letter No. [C: TS Change)

Letter No. I 17 NRC request (2/26/81) to meet guidelines of NUREG 0313, Rev. 1 regarding IGSCC I (Generic Task A-41) (Generic Letter 81-04)

FVY 81-102 Commits to provide augmented IS1 Program as required by NUREG-0313 Rev. 1 71118 1 FVY 81-153 Implementation schedule for NURF7,G-0313,Rev. 1 1114181 W Y 1-177 IS1 Program Description (Rev. 6) 12/28/81 W Y 82-39 Supplement 1: Augmented IS1 and Leakage Detection Requirements (withdraws PC 4/8/82 No. 70)

FVY 82-41 IS1 Relief Request 4/14/82 FVY 82-48 IS1 Relief Request 5/3/82 FVY 82-121 Response to NRC request (NVY82-155, dated 9/28/82) for a Listing of IST Program 11/24/82 Submittals W Y 83-5 IS1 Program (Rev. 7) 1/18/83 NRC Approval (NVY 83-125, dated 5/19/83) of Ccrlain lS1,ReliefRequesrs FVY 84-37 IS1 Plans for 1984 RFO and Coinmitnient to Subnut Revised Progam 4/19/84 FVY 84-139 IS1 Program (Rev. 8) SER 2110187 11/27/84 NVY 87-25 313 1/87 NVY 87-54 A-99 12/9/87 (partial)

NVY 87- I89 (Errata)

NRC RAI (NVY 85-220. dated 10/25/85)

NRC Acceptance (NVY 85-271, dated lU19/85) of Request for Relief from requirements of 1st 10-Year IS1 Program Plan, Rev. 7 FVY 85-124 Review of Section XI Requirements in IS1 Program 1U30/85 SER 2f10187 FVY 86-2 1/6/8 6 Withdrawal of PC No. 77, Supplement. 1, and unapproved portions of PC No. 70 I NVY 87-25 Page 14 of 38 T. Silk0 review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lie. Amend)

Change No. Submitted Letter No. (C: TS Change)

Letter No.

FVY 86-68 Response to NRC RAI (NVY86-104dated 5/27/86) 8/1/86 FVY 86-77 Transmittal of GE documentation in support of FVY 86-68Response to RAI (NVY 86-8/22/86 104)Question No. 8 -*

NRC RAI (NVY87-01, dated 1/5/87)on IST Program (Rev. 8) SER 2/10/87 NRC transmittal (NVY87-25, dated U10187) of SER for 2nd Interval IS1 Program NVY 87-25 (Rev. 8)

FWY 87-72 IS1 Program Revision 9 1/1/87 NRC (NVY87-146,dated 9111/87)schedule for meeting to discuss open items in NVY 87-01 (115187)

FVY 88-09 Response to Request (NVY87-189,dated 12/9/87)for IS1 Information 2/12/88

~ ~~ ~~

I NRC (NVY 88-074,dated 5/9/88)Summary of 10/14/87IST Meetings FVY 88-44 IS1 Revision 9.Amendment 1 6/1/88 I FVY 88-63 ] IST Revision 9 7/28/88 78 WVY 79-15 Radiological Effluent Technical Specification (Appendix I Requirements) (Amendment A-2/13/79 83 effective 4/1/85)

WVY 79-40 Off-Site Dose Calculation Manual (ODCM) 411 1/79 NRC Request (7/31/79)for Remittance ofClass III Fee ($4,OO0.00)

FVY 83-6 Revised lzETS 1/24/83 FVY 83-27 Submittal of Revised Draft RETS to Franklin Research 4/12/83 FVY 83-62 Requests PC be placed on hold 6/17/83 FVY 83-75 Submittal of Revised Draft of ODCM to Franklin Research 7/14/83 FVY 83-18 Schedule for submittals (RETS and ODCM) 11/15/83 FVY 83-127 Revises submittal dates 12/27/83 NVY 84-224 83 1019184 Page 15 of 38 T.Silko review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No. Submitted Letter No. (C: TS Change)

Letter No.

78 FWY 84-6 Revised RETS Program - Supersedes PC No. 78 1/23/84 FVY 84- 17 Revised Off-Site Dose Calculation Manual (ODCM) - Supersedes 4/11/79 ODCM 3/5/84 ~~ ~

FVY 84- 122 Process Control Program Submittal for Review 10/12/84 79 WVY 80-49 RPT/Analog Trip System I I /Y80 A-58 3/17/80 ~~

WVY 80-72 Additional information 5/9/80 WVY 80-115 SupplementalInformation Supporting RpT/Analog Trip System; response to NRC letter 8/13/80 WVY 80-134 Supplement 1 Information Supporting RPTIAnalog Trip System 9/23/80 80 5/18/79 Trip System Logic Surveillance Frequency Changes Withdrawn WVY 79-63 1013n9 Defers submittal of response to 8/22/79 RAI WVY79-116 7/16/83 Requests PC be placed on hold W Y 83-62 FVY 87-107 Withdrawal (see PC No. 142) 11/30/87

-:1 Requires Safeguards Contingency Plan 11/21/80 A-60 81 Reactor Vessel PressureKemperature Limitations (Appendix G) 1/14/81 A-62 WVY 79-94 9/5/80 Supplement 1: Revised Bases Pages 117 and 118 W V Y 80-128 111918 1 Supplemental Information FVY 81-12 82 8110179 Fire Protection Technical Specification (Fire Brigade) 9112/79 A-54 WVY 79-88 Page 16 of 38 T. Silk0 review as pari of UND 2003-101-04

NRC Approval Proposed Initiated by Date Date Approved (A: Lic. Amend)

Change No. Submitted Letter No. (C:TS Change)

Letter No.

33 8/21/79 Revised MCPR Limits for Cycle 7 10/26/79 A-55 WVY 79-92 9/18/79 Submittal of Reload 6 NEDO 24208 Report WW 79-106 10/5/79 Submittal of supplemental Reload 6 NEDO 24208 Report in response to request (9/27/79)

WVY 79-114 34 10/5/79 Control Rod Hydraulic Return Line Isolation Valves 10/26/79 A-55 WVY 79-113 35 11/12/80 Alternative Testing Requirements (for Core Spray and LPCI systems)

WVY 80-158 6/17/83 Requests PC be placed on hold I V Y 83-62 12/7/87 Supplement 1; surveillance testing of ECCS and SLC equipment 7/21/89 FVY 87-112 NVY 89-153 A-114 7/15/88 Response to RAI (NVY88-077,dated 5/9/88)

FVY 88-58 6/8/89 Supplement 2,superceding Supplement 1 BVY 89-49 86 4/23/80 Current Organizational Structure for VY and YAEC 41618 1 A-65 WVY 80-65 10/7/80 Supplement 1: Current Organizational Structure W Y 80-141 87 4/29/80 Appendix B Technical Specification Withdrawn WVY 80-66 6/17/83 Withdrawal Letter FVY 83-62 88 8/1/80 I Extension of MAPLHGR Limits 8/22/80 A-57 WVY 80-110 89 8/19/80 Reload 7 Licensing Submittal (change to MCPR and updates) 12J18/80 A-61 Page 17 of 38 T.Silk0 review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No. Submitied Letter No. (C:TS Change)

Letter No.

10/7/80 Supplement 1:Additional Information Reload 7 WVY 80- 140 11/21/80 Additional Information Reload 7: Response to NRC letter 10130/80 W V Y 80-162 -.

NRC request (311118 1) for change fee 90 8/28/80 Hydrogen Monitoring System 11/3/80 A-58 W V Y 80- 123 10/14/80 Additional Information WVY 80-I43 91 9112/80 SRVlSV Monitoring & STA Tech Specs (TMX-2Lessons Learned Category "A" items) 31218 I A43 WVY 80-131 1/5/8 1 Supplement 1: LCOs for SRV/SV Monito%-ng. and Program Requirements for Integrity of FVY 81-5 Systems Outsider Containment and Iodine Monitoring; Response to NRC requests (1U1/80 and 12/10/80\

92 2/12/81 Stability Testing 311 118 1 A-64 FVY 81-28 93 12/01/80 Common Reference Level for Reactor Water Level Instrumentation 1M6/81 A-68 WVY 80- 166 4117181 Extension of implementation date for Item LK.3.27 WVY 8 1-69 NRC response (6/30/81) to W V Y 81-69 94 1 1/6/80 Allow Spiral Unloading and Reloading of the Reactor Core (Lowering of SRM Channel 11/10/80 A-59 WVY 80-156 Count Rate) 95 10/5/8 1 Modifications to HPCURCIC Break Detection Logic and SDV Vent and Drain Valve 1 1/27/111 A-69 FWY 81-144 Surveillance 11/29/82 A-73 NVY 82-204 11/18/81 Response to Request (1 0/7/81) for Information regarding MJREG-0737, Item TI.K.3.15 W Y 81-162 96 613018 1 Fire Protection Systems 11/10/81 A-67 FVY 81-96 ~~

812618 1 Supplement 1 FVY 81-123 Page 18 of 38 T. Silko review as part of UND 2003-101-04 I

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No. Submitted Letter No. (C:TS Change)

Letter Nu.

37 8/4/81 organizationalchanges 9110/81 A-66 FVY 81-109 8/25/81 Supplement 1 FVY 81-121 -*

98 9/2/81 I Reload 8Licensing- Submittal 1 1127181 a-10 FVY81-128 I 10128/81 IAdditional Information FVY 81-151 lOnolSl Additionai Information: Response to NRC RAI of 10/23/81 FVY 81-152 1 1/6/81 Supplemental Information (Errata sheets for EWY 81- 152)

FVY 81-155 11/13/81 Additional Information FVY 81-160 1 1/23/8 1 Validation of SIMULATEi Code to support Tech Spec Change FVY 81-167 11/23/81 Juacation for MCPR Operating Limits BOC to EOC-u)o Mwd/t Cycle Exposure FVY 81-168 3/31/82 Supplemental Information (YAEC-1299P)

PW 82-36 6/24/82 Information in support of Cycle 9 Reload Analysis FVY 82-90 9116/82 8/19/82 Supplement (2) NVY 82-146 FVY 82-93 I 9/10/82 I Additional Information to Supplement 2 1 FVY 82-64 6/17/83 Withdrawal letter.

FVY 83-62 VY tech spes for Inerting and containment atmosphere are consistent with or less restiictive than industry norms. No further action is warranted.

Page 19 of 38 T.Silk0 review ns part of UND 2003-101-04

I NRC Approval Proposed Title Date Approved (A: Lic. Amend)

Change No. Letter No. (C: TS Change) 101 I 7/22/82 Suppressic., l'alllpl nit incrLhc: to 100% 6/6/85 A-88 FVY 82-86 NVY 85-1 I6 7/20/83 Additional Ini )n subm ' 'T' quencher elevation (from 7/15/83 telecon)

My 83-76 I02 7/22/82 Limiting C , , o r Open: dby Liquid Control System 2/17/83 A-75 FVY 82-85 NVY 83-31 103 1/10/83 Andog Trip ', .III and Scram DIhlr.. Volume Instrumentation 3/28/83 A-76 FVY 83-1 NVY 83-66 9/27/82 -

OrganizationalChanges YNSD and Corporate Staff 2/17/83 A-75 FVY 82-107 NVY 83-3 1 105 8/5/83 RPS Power Protection Panel FVY 83-88 12/14/83 Response to telecon RAI on Voltage and Frequency Setpoints ErvY 83-124 3/4/85 Supplemental Submittal (supercedes 8/5/83 submittal)

FVY 85-26 6/2/89 A-1 12 NVY 89-122 5/ 18/89 RPS Power Protection Panel Specifications- Supporting Information and Clarifying B V Y 89-45 Submittal responding to NRC letter (NVY 89-52, dated 3/24/89)

I06 1UY82 Organizitional Changes - Maintenance Superintendent UI 7/83 A-I5 1 pvY82-129 NVY 83-31 107 I 5/26/83 Reactor Pressure Vessel Temperature Curves 31 13/84 A-8 1 FVY 83-45 NVY 84-46A 108 5120183 Safety-Related Shock Suppressors (Snubbers) (see also PC 117) 7/9/85 A49 FVY 8341 NVY 85- 136 8/4/83 Supplement 1: Deletion of Certain Snubbers and Clarification FVY 83-89 109 2/7/84 HFCI Auto Suction Transfer 1/23/85 A-85 W Y 84-7 NVY 85-8 5118/84 Response to NRC RAI (NVY 84-71, dated 4/12/84)

FWY 8447 1 LO 5/26/83 E-Plan Annual Drill Requirement 1!/IO183 A-80 FVY 83-43 NVY 83-263 Page 20 of 38 T. Silko review as part of UND 2003-101-04

Proposed Change No.

Initiated by 1 Date Submitted 1 Title II Date Approved Letter No.

NRC Approval (A: Lie. Amend)

(C: TS Change)

1. . I Letter~o.

111 I 2/22/83 RPS Instrumentation (LPRM Disconnect) 4/11/83 FVY 83-11 NVY 83-83 2/28/83 Shift Technical Advisors 5/2/83 FVY 83-14 .-. NVY 83-91 113 2/22/83 Spiral UnloadlReload 3/28/83 FVY 83-10 NVY 83-67

=l I14 2/8/83 Primary Containment Isolation Valves 2/14/83 FVY 83-08 NVY 83-21 111s 5/26/83 Reactor Coolant System Leakage Monitoring Withdrawn FVY 83-44 Confirmatory Order (NVY83- 150, dated 6/27/83) Requiring Implementation of Leakage Monitoring Limits Consistent with PC No. 115 3/29/84 Withdrawal letter.

W Y 84-29 I

VY LCOs associated with Reactor Coolant System leakage are consistent with, our less I restrictive than industry norms. No further action is requi&d.

I16 1/23/84 I Main Steam Line Low Pressure Isolation Setpoint Decrease (850 to 800 psia) 12/4/84 A-84 NVY 84-252 1117 2/7/84 Revised Snubber Surveillance Criteria 7/9/85 A-89 FWY

~ ~-84-8 I .--- ---- PC (See also - - 1081

---, NVY 85-136

] I8rE Inspection Report 84-03 (NVY 84-63, dated 3/29/84)- Review of PC No. 117 7/9/84 I Response to RAI (NVY 84-97, dated 5/3/84)

FVY 84-87 10/22/84 Request for Amendment - Safety-Related Shock Suppressors; supercedes FVY 84-8 FVY 84-124 11/6/84 Additional page FVY 84133 2/7/84 Appendix G, Reactor Vessel Pressurenemperature Curves Superceded FVY 84-9 Supercedes PC No. I18 (see PC 129)

FVY 85-46 5110185 .

Page 21 of 38 T.Silk0 review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A:Lic. Amend)

Change No. Submitted Letter No. (C: TS Change)

Letter No.

3/26/84 Main Steam Line High Flow Setpoint Increase (120%to 140%) 2/21/85 A-86 FVY 84-28 NVY 85-29 3/19/85

• & NVY 85-49 9/7/84 Response to RAI (NVY 84-137, dated 6/21/84)

FVY 84- 108 1 NRC Approval Proposed Initiated by Date Title Date Approved (A:Lic. Amend)

Change No. Submitted Letter No. (C: TS Change)

LetterNo. I I I 6/5/84 I Technicat Specification Clarification - Standby Gas Treatment (SBGT) System Operability I Withdrawn I FVY 84-58 6/15/84 FVY 84-62 I and Secondary Containment Integrity I Suppleiiient 1 - Revision 1 7/9/84 Clarification allowing refueling operations with only one ERG available N Y 84-84 10/21/86 Withdrawal letter FVY 86-99 This PC was replaced by PC 236 and approved via LA # 197. The remainder of VYs LCO durations for SBGT are consistent with industry nornis.

6/26/84 Appendix J - Primary Containment Leak Rate Testing Progam The PCLRT FVY 84-76 program and 5130186 Response to RAI (NVY 86-29, dated 2/14/86) LCOs for inop FVY 86-51 CIVs is 10110186 Supplemental Response to RAI (NVY 86-29) consistent with FVY 86-97 industry noms.

No further 12/15/86 Requests expedited review decoupling RWCU V 12-68 . .

I I

FVY 86-116 action IS 4/11/89 I Withdrawal of request for separate review of RWCU V 12-68 required.

Page 22 of 36 T. Silk0 review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No. Submitted Letter No. (C: TS Change)

Letter No. I NRC Closeout (NVY86-65,dated 3/31/86)of Multi-PlantAction Item B-23,Degraded Grid Voltage Protection 313 1/86 NRC Approval (NVY 86-66,dated 3/31/86)of Degraded Grid Procedures NVY 86-66 --

123 11/2/84 Mark 1Containment - Technical Specification Change NVY 85-137 Accepts PC wlo Fvy 84-130 7/1/85 Amendrnent NVY 85-164 I 8/7/85 1 (correction) 1 1 NRC Approval Proposed Initiated by Date TiiIe Date Approved (A: Lie.

Change No. Submitted Letter No. Amend)

Letter No. (C: TS 1

124 12/14/84 NuRec-0737 Technical Specifications (Generic Letter 83-36) NVY 86-167 FVY 84-146 8111/86 11/26/85 Supplement 1 NVY 86-255 Revised SE FVY 85-117 12/19/86 I25 1/15/85 Administrative Update (Ops. Super.) 4/1/85 FVY 85-3 NVY 85-55 126 1/15/85 Operation of Purge and Vent Valves, and Iodine Spike Limit for Reactor Coolant (response 1OD8185 FVY 85-05 8/2/85 to NRC letter NVY 84-108,dated 5/22/84)

Response to RAI

- NVY 85-221 3/17/86 Evy 85-70 NVY 8648 Correction 127 3/27/85 Administrative Update and changes to certain trip level settings. 10/9/85 A-90 FVY 85-31 NVY 85-222 3/17/86 M Y 86-48 Correction 128 3/4/85 Administrative Changes relating to RETS 8111/86 A-95 W Y 85-25 NVY 86-166 -

129 5/10/85 Reactor Vessel PressureITemperature Curves (supercedes PC No. 118) 6/24/86 A-93 FVY 85-46 NVY 86-121 I 11/21/85 I Response to RAI (from 11/7/85telecon) 1 I FVY85-107 I I I I Page 23 of 38 T.SilkonviewaspartofUND2003-101-04

L NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic.

Change No. Submitted Letter No. Amend)

Letter No. (C: TS Change) 130 10/9/85 Deletion of RL n Syste: 1 izer Piping Valves 3/27/86 A-92 I V Y 85-95 NVY 86-60 11/15/85 Resubmittal FVY 85-104 131 1/24/86 Change to REI'S (Tables 3.9.2,3.9.3 Idinitions and Oil Incineration) 1/20/88 A- 103 FVY 86-9 NVY 88-008 5/13/86 Clarification 2/16/88 FVY 86-42 I NVY 88-023 NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No. Submitted Letter No. (C: TS Change)

Letter No.

6/9/86 Withdrawal of'Reques1for Contaminated Oil Burn Portion of PC FVY 86-53 RETS is not currently a part of TS and therefore no further action is required.

1/16/87 Supplement 1 FVY 87-11 2/2/87 Errata to Supplement 1 87-15 3/12/86 Single Loop Operation and Thermal-Hydraulic Stability (withdraws P.C. No. 5 1) 8/8/86 A-94 FVY 86/22 I NVY 86-165 3/27/86 1 Submittal of GE Report NEDO-30060 A- 107 10/9/87), FVY 087-76 (10/16/87), FVY 88-02 (1115188). and FVY 88-14 (3/16/88)

Page 24 of 38 T.Silk0 review as part of UND 2003-101-04 I

..... I .

._. _. . 1 --

-.-- I -

Proposed Initiated by Date Title Date Approved Change No. Submitted Letter No.

Letter No.

133 4/25/86 Spentand New Puel Storage 5/20/88 FVY 86-34 Note: A-104;-allows rack installation and storage of up to 2000 assemblies (the current NVY 88-093 tech spec limit)A-130 grants final approval for increasing the number of stored fuel 7/10/91 assemblies from 2000 to 2870. See also MC SE (NVY88-223,dated 10/14/88.) NVY 91-144 8/15/86 Response to NRC RAI (NVY 86-147,dated 7/24/86)

I V Y 86-73 9/26/86 Response to NRC telecon RAI of 9/12(86 (Criticality)

FVY 86-88 10/21/86 Response to NRC RAI of 9/25/86(k-infinity)

FVY 86-98 11/24/86 Response to NRC RAI (NVY86-217,dated 10/'22/86)

FVY 86-107 12/5/86 Transmittal of Supplemental Informarion (Proprietary Drawings)

FVY 86-115 NRC Transmittal (NVY 86-258,dated 12/23/86)of Hybrid Hearing Notice NRC Transmittal (NVY 87-02, dated 1/5/87)regarding 12/23/86 Meeting on Heavy Loads NRC Notice (NW 87-03,dated 1/6/87)of 1/15/87Meeting on Thermal Hydraulics 133 NRC Summary (NVY 87-17,dated 2/8/87)of 1/15/87meeting in Richland, WA to discuss Thermal Hydraulics NRC Letter (NVY 87-32,dated 2/24/87)to Harmon and Weiss on: Rerack Meeting 2/25/87 Clarification of Information on Heavy Loads FVY 87-23 3/19/87 Thermal-Hydraulics Information (Heat Load Calculations)

FVY 81-32 3 0 1187 Materials Information FVY 87-39 4/9/87 Justificationfor 150 F Temperature Limit FVY 87-40 4/13/87 NES Rack Lifting f i g Design Information FVY 87-42 5/22/87 PaR Rack Lifting Rig Design Information PVY 87-57 6/11/87 Additional Information (Commitments)

FVY 87-65 NRC Notice (NVY87-102,dated 6/30/87)of 7/14/87Rerack Meeting NRC Notification (NVY 87-1I I, dated 7/15/87)of continuing staff review Page 25 of 38 T.Siko review as pBR of UND 2003-101-04

NRC Approval Proposed Initiated by Date Title Date Approved (A: Lic. Amend)

Change No.

submitted LetterNo. Letter No. (C: TS Change)

- NRC summary of(NVY 87-1 15, dated 7130187) of 7/14/87 meeting on amendment status 9/1/87 Response to NRC RAI (NVY87-120, dated 8/7/87) (TAC 61351): withdraws commitment I EVY 87-87 to implement license certain conditions in F?T 87-65 12111/87 Clarification of information in FWY 87-87, on seismic qualification of pool makeup FVY 87- 114 12/16/87 Request for meeting FVY 87-118 NRC Approval Proposed Initiated by Date Submitted Title Date Approved (A: Lic. Amend)

Change No.

133 Letter No. NRC Summary (NVY88-027, dated 2/16/88) of 2/9/88 Meeting, with transcript Letter No. (C: TSChlmge) 3/2/88 Documentation of Information presented at 2/9/88 Meeting FVY -.

-- 17 NRC Errata (NVY 88-042, dated 3/22/88) to transcript in 2/16/88 letter NRC Environmental Assessment and Finding of No Significant Impact (NVY88-145, dated 7/25/88) 6/7/88 Description of Enhanced Spent Fuel Pool Cooling System 10/14/88 FVY 88-47 NVY 88-223 (Safety I NRC Replacement page (NVY 881238, dated 11/04/88) for Safety Evaluation I

1 I34 3/29/89 A-1 10 NVY 89-62 1/19/90 Change to Tech Spec 3.7.5.b Approved in Amendment No. 110 245190 A-I 19 1 3 5 1 BVY 90-005 NVY 90-0I 9

. FVY 8/28/86 86-78 86/87 Operating Cycle InspectiodRepairs of RHR Pump Impeller Wear Rings (one time basis) NVY 12/4/86 86-237 A-97 1 1/3/86 Response to Request for Information (telecons of 10pL0/86 and 10/22/86)

FVY 86-102 I36 1/16/87 SLC System (Testing) 12130187 A- 102 FVY 87- 10 NVY 87-199 A-1 13 I37 Ill2487 Post-Accident Instrumentation 6/22/89 FVY 87-08 , NVY 89-135 1 ~

rage LO or ;)I( T.Silk0 review as part of UND 2oO3-10I -04

- _I__ -_

NRC Approval Proposed Initiated by Date Submitted Title Date Approved (A: Lic. Amend)

Letter No. Letter No, (C: TS Change) 1/29/88 Supplement 1 FVY 88-08 4/28/87 Administtative Changes (Chedi3.P. and Procedures Approval Process) 12/29/87 A-101 FVY 87-48 NVY 87-196

' -1 1llu87 Clarification FVY 87-102

--I--

No PC No.used 5/29/87 FVY 81-59 6/24/87 Clarification of Reactivity Shutdown Margin Demonstration (doesn't require License Amendment)

Change for Cycle 13 Operating Limits 812 1/87 NVY 87- 133 9/18/87 No Amendment Number A-100 FVY 87-67 NVY 87-148 8111/87 Clarification of VY Cycle 13 Core Performance Analysis Report FVY 87-78 Not Subinittcd I V Y 87-87, dated 9/1/87, withdraws coinrnitment re: Spent Fuel Pool Cooling System License Conditions.

This PC was not submitted to the NRC. This is appropriate as no specs are required for the subject system. Since no specs exist, they are not restrictive and no further action is warranted. -

4/27/89 Construction Period Recapture BVY 89-42 6123/89 Revision of requested end of license date 12/17/90 A-127 BVY 89-55 NVY 90-217 11/30/87 Logic System Functional Test Intervals; withdraws PC No. 80 8/9/88 A- 106 FVY 87-107 N V Y 88-170 1/20188 Clarification 9/1/88 A-IO6 FWY 88-04 NVY 88-189 Wata 3/1W88 NRC Notice (NVY 88-036, dated 3/10/88) of 3/15/88 Meeting to discuss Logic System Reliability NRC Summary of (NVY88-044, dated 3/17/99) 3/15/88 meeting Additional Information regarding Relay Reliability FVY 88-028 4/27/88 NRC letter ( N W 88-069, dated 4/27/88) to State of Vermont, "Logic System Functional W Y 88-069 Test at Vermont Yankee" Page 27 of 38 T.Silk0 review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date Approved (A: Lic. Amend)

Letter No. Letter No. (C: TS Change) 12/9/87 Automatic Depressurization System (Logic Modification) 8/48 8 A- 105 FVY 87-1 17 NVY 88- 155 5/23/88 New Fuel Type (16 gram Umit) GE 8X8EB Puel 9/9/88 A-108 W Y 88-40 NVY 88- 198 8115/88 Response to Request for Supporting Document (NEDE-21697 supplement 1)

FVY 88-66 11/18/88 Generic Letter 83-02:NUREG-0737Technical Specifications, Items TI.K.3.13and 4/24/89 A-1 11 FVY 88-98 II.K.3.22 I NVY 89-84 I 11/30/88 Incorporates 1.04 Fuel Cladding Inkgrity Safety Limit I u27/89 I A- 109 FVY 88-99 NVY 89-37 12/21/88 Clarification FVY 88-103 1/6/89 Further Clarification BVY a 8 9 NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic. Amend Change No. Letter No. Approved (C: TS Change Letter No.

I47 SI 1 2/89 Change regarding ATWS Rule (10CFR50.62) in response to NRC request (NVY87-04, 811 2/97 WlTHDIWWN BVY 89-44 dated 1/8/87) NVY 97- 129 (Notice of Withdrawal)

NKC summary ( N W 92-208, dated 11/12/92) of 8/15/92 Meeting and clai-ification of NRC letter (NVY 92-96, dated 6/fi/92)concerningopen issue on sig~ialcoiiditioning I 47 4/14/93 Commitment to implement plant mods to meet ATWS rule BVY 93-40 10122193 Updated Technical Specification pages responding to NRC requesl (NVY 92-96, dated A V Y 93- 119 6/5/92) 112s191 Withdrawal IeLler dcferring changes to ITS BVY 97-95 A review of this WITHDRAWN PC reveals that most of the TS changes contained within this submitlal have worked their way into the specs. WRT to the issue of outlier restrictive TS changes. the LCO periods contained with in VYs specs are less restrictive than that of STS.

Accordingly, no further action IS required.

I48 1/27/89 Administrative Changes 8/24/90 A-126 B W 89-10 M Y 90- 167

~~~~

Page 28 of 38 T.Silko review as part of UND 2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lie. Amend)

Change No. Letter No. Approved (C:TS Change)

Letter No.

11/28/89 Clarification BVY 89- 109 149 2ma9 Primary Containment Isolation Valve Testing in Head Spray Subsystem of RHR 9/7/89 A-115 BVY 89- 14 v i NVY 89- 187 10110189 NCIY 89-2 13 SE Correction 150 5/12/89 Elimination of Cycle-Specific Parameter Limits Generic Letter 88-16 9/15/89 A-I 16 BVY 89-43 NVY 89-204 7/14/89 Cldkation removes FCSE parameter fiom PC 10110/89 BVY 89-67 NVY 89-212 Correction 151 10/16/89 Compensatory Fire Watch fiequency reduction 1ua/m A-1 17 BVY89-97 NVY 89-250 152 11/1#89 Revise Reactor Vessel Pressure-TemperatureCurves (Generic ktter 88-11) 4/17/90 A-120 B W 89-113 NVY 90-077 153 11/9/89 Emergency Change Request for 198911990 Operating Cycle RefurbishrnentlRepair of 1/26/90 A-118 BVY 89-106 Uninterruptible Power Supply System NVY 90-008 NRC Temporary Waiver of Compliance (NVY 89-224, dated 11/9/89} fromTechnical SpecificationSection 3.5.A.4 154 3/9/90 Type C Leakage Testing of New Inboard FW Check Valves 6/4/90 A-122 BVY 90-029 NVY 90-121 155 2/28/90 Utilization of Alternative Longer Life Control Blades 6/5/90 A-123 BVY 90-021 NVY 90-I27 156 3/5/90 Removal of 3.25 Limit on Extending Surveillance Intervals 7/2/90 A- 124 B V Y 90-022 Nvy 90-138 6/7/90 Replacement of Unintermptible Power Supply (incorporated into A- 124)

BVY 90-066 157 3/2(90 Administrative Update 4/25/90 A- 12 1 BVY 90-023 NVY 90-91 158 611 1/90 Update Section 6.0, "AdministrativeControls" 8/24/90 A- 126 BW90-069 NVY 90-167 159 7/20/90 SurveillanceTesting of Engineered Safeguards EQuipment 314t9 1 A- 128 B W 90-081 NW 91-38 Page 29 of 38 T.Silk0 review as pan of UND 2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic. Amend)

Change No. Letter No. Approved (C: ISChange]

Letter No.

4/8/90 Auxiliary Electrical Power System Technical Specification 8/23/90 A-125 BVY 90-044 NVY 90-161 8/3/94 Correction of SER accompanying A-I25 8/22/95 BVY 94-077 -_ NVY 95-1 13 Correction to 161 6/1/90 Corrects Typographical and Format Inconsistencies 1Om9 1 A-131 I BVY 90-068 NVY 91-183 1 7/17/90 List of References (omitted from BVY 90-068)

BVY90-078 1 162 It 15191 Toxic Gas Monitoring System 10/24/91 A- 132 BVY 91-02 NRC RAI (NVY 91-56, dated 4/16/91) _...... VY Response to RAI (BVY91-53, dated NVY 9 1-205 511W9 I) I In19 1 VY response to 2* RAI (BVY91-65, dated 7/12/91) - 2M1RAI via 7/3/91 telecon NVY 9 1-206 Corrections to A-132 and SE 163 1115191 Surveillance of Indication of LPCI Crosstie Monitor (Valve RHR-20) 3/25/9 I A- 129 BVY 91-03 NVY 91-69 r

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS 1 Change) 164 12127191 Administrative Changes regarding Plant Operations Review Committee and testing of 7/21/92 A- 134 BVY 91-125 Primary Containment Isolation Valves NVY 92-136 (partial)

Denial of that part of PC No. 164 dealing with Plant Operations Review Committee and approval of reinstatement of portion dealing with testing primary containment isolation valves I65 12/23/91 Analog System Replacement 5/8/92 A- 133 BVY 91-120 NRC KAI (NVY 92-35, dated 3/3/92) ....... VY Response to RAI (BVY 92-41, dated NVY 92-097

- 3l3 1/92)

I66 121 1 5/92 One-Time Extended Emergency Diescl Generator (EDG) LCO Period to Support 3/25/93 BVY 82-139 Maintenance Activities. NVY 93-59 Notice o I c

II Page 30 of 38 T. Siko review as pari of UND 2003-101-04 r

I

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. ( C TS J Change) 3/9/96 Withdrawal letter. wilhdrawd

\

B W 93-025 The issue of extending the EDG LCO from 7 days to 14 dajrs has been identified on tho PC list as a wish list items for over 5 years. Periodically during the Monthly Licensing Meeting, the desire for this PC is discussed. Thus far, the consensus has been that that this change is not warranted.

167 12/15/92 Calibration Requirements for Control Rod Block Instrumentation 8/25/93 A- 136 B W 92- 140 NVY 93132 168 8/4/93 Auxiliary Power System Tech Specs and Associated Revision to IST Program 3/22/94 A- 138 BVY 93-30 NVY 94-45 169 3/26/93 UDdates Section 6.0. "Administrative Controls" 5/26/93 A-1 35 I BVY93-29 I NRC Reissue (NVY.93-088,dated 5/28/93)of A-135 due to failure to put Amendment No.on TS pages NRC transmittal(NW 93-089, dated 6111/93) of TS pages omitted from NVY 93-088 I Nvy93-87 I 170 8/27/93 Revisions relating to 10CFR20 4/3/95 A-I44 BVY 93-81 Provides FSAR Figure 2.2-5 to assist NRC in review (BVY93-124, dated 11/9/93) NVY 95-48 (Non-Part 20 Response to comments in telecon of 8/10/95 (BVY96-53, dated 4/26/96) portion only)

Response to comments in telecon of 9/25/96 (BVY 96-111, dated 9/25/96) 6119197 A-151 NVY 97-92 (Part 20 portion) ,

171 7/14/93 Additions in Response to Generic Letter 88-01 on Intergranular Stress Corrosion Cracking 6/1/94 A-139

~- -~ -

BVY 93-068 ~-

NVY 94-86 172 6/25/93 CoreAlteration Defition 9/3/93 A-137 B W 93-063 NVY 93-144 173 3/31/94 BWR Thermal-Hydraulic Stability and Plant Information Requirements for BWROG Option 8/9/95 A- 146 BVY 94-36 1-D Long Term Stability Solution NVY 95-106 NRC RAT (NVY94-84 dated 6/9/94).. ,.... VY Response (BVY 94-90, dated 9/9/94]

NRC Acceptance (NVY 95-43, dated 3/30/95) of Report submitted with BVY 93-72 (dated 7/7/93) Application of BWROG Thermal Hydraulic Stability Long-Term Solution Optioin I-D Submittal of Updated TS Pages (BVY 95-70, dated 6/22/95)

I74 I0/28/94 Removal of Neutron Flux Instnunentation fromPost-Accident Monitoring Technical 6/20/95 A- 145 BVY 94-103 Specifications Mry 95-84 175 12/6/93 Revisions relating to Jet Pump Surveillance Requirement lot26194 A-141 BVY 93-134 NVY 94-190 176 5/20/94 Removal of Core Spray High Sparger Pressure Instrumentationfrom Emergency Core 8/22/94 A-140 BVY 9451 Cooling System Actuation Instrumentation NVY 94-134 -

Page 31 of 38 T.SilkDreviewasparfofUND2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS I

177 128194 Standby Gas Treatment Power Supply Requirements During Refueling Operations 3/23/95 A- 143 B W 94-105 Clarification (BVY 95-20, dated 2/16/95) NVY 95-41

~~~

I78 1 1/7/94 Diesel Fuel Oil Procurement and Testing using ASTM D975( 1993) WITHDRAWN WITHDRAWN Withdrawal letter BVY 95-15 This issue was subsequently submitted as part of PC 256 and approved as part of LA # 2 14.

No further action required.

179 Instrument IdentificationChange for ECCS Actuation Instrumentation (ATWS Diversity) 3/3/95 A- 142 I BVY94-123 NVY - - - - -5

. . 95-1 180 J. Meyer I 2/5/96 Administrative Change to Correct Typographical Error and Text Inconsistcncies Withdrawn N/A BVY 96-06 112319a 7/14/98 Withdrawal letter NVY 98-I02 BVY 98-105 Notice of Withdrawal 181 182 J. Meyer 8/22/96 BVY 96-99 Not Submitted High Range Stack Noble Gas Monitor Action Statement Minimum Cog Cooling System Availability During Cold Shutdown and Refueling I1 4/8/98 NVY 98-50 Not Submitted A-I58 I I Conditions - Incorporated into ITS effort 183 3. Mever I 4/4/96 I Control Rod Over-Travel Indication Surveillance I 9130196 A-149 BVY 96-37 NVY 96-155 loll 7/96 Updates approved Technical Specificationpages to reflect effect of Amendments 148 and I BVY96-126B 149 I

I 184 J. Meyer 4/4/96 Secondary Containment Integrity Requirements 711OJ96 A- 147 I BVY96-39 NVY 96-123 I85 J. Meyer I 9111/96 Safety and Relief Valve Setpoint Tolerance Increase and Power Operation with an inoperable 4/15/98 A-I60 BVY 96-104 SRV .... Proposed schedule extension (BVY97-14, dated 11/6/97)for responses to RAI NVY 98-55 (NVY 97-151, dated 10J7J97) .... RAI Response submitted on 12/8/97, BVY 97-164 I86 J. Meyer 8/9/96 Safety Limit Minimum Critical Power Ratio 1014196 A- I50 BVY 96-98 NVY 96-154 9117/96 Revision

~

BVY 96-109 187 J. Meyer 6/28/96 Core Shutdown Margin 9/25/96 A-I48 BVY 96-84 NVY 96- I50 Page 32 of 38 T. Silko review as pari of UND 2003-101-04

-a

- _ I m i .

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS J 10/17/96 I

Updates approved Technical Specificationpage to reflect effect of Amendments 148 and 149 Change)

BVY 96-126B I 188 J. Meyer 10111/96 Revised Recirculation Motor Generator Set Fire ProtectioirFoam System Capacity 3/31/98 I A-156 BVY 96-120 NVY98-46 I 189 J. Meyer 12/10196 Relocation of Fire Protection Requirements fiom Technical Specifications to Fire Protection 2/24/99 I A-168 BVY 96-155 Plan and UFSAR NVY 99-21 1/22/99 Revised pages BVY 99-04 190 J. Meyer 7/11/97 10 CFR 50, Appendix I, Option B 2/26/98 1 A-152 BVY 97-90 NVY 98-24 I 11/21/97 Modification (Revised Pages) 3110199 I BVY 97-154 NVY 99-28 12/22/97 Additional corrected pages BVY 97-170 316/98 Option B Modification BVY 98-18 3~19a Find results of Core Monitoring relating to MCPR calculations BVY98-32 I 191 J. Meyer 6/9/97 Revises Section 6 to reference NRC Approved Methodology for Thermal-HydraulicStability 4/7/98 1 A- 157 BVY 97-77 I (LAPURS) NVY 98-51 1 192 J. Meyer aoom I Adds reference to m W R 2 Method 2/23/99 I A-167 BVY 97-107 NVY 99-20 9/ 18/97 Marked-upTech Spec pages for PC Nos. I92 and 193 B W 97-118 I Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS r---l-- I Chanpe J. Meyer 8/22/97 Revision of COZSystem Technical Specifications 3/6/98 A-I54 BVY 97-106 NVY 98-26 9118/97 Marked-upTech Specs pages for PC Nos.. 192 and 193 Page 33 of 38 T.Silk0 review as pzyt of UND 2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS I I Change) 194 J. Meyer 10/10/97 Offsite Power System Technical Specifications 312419a A- 155 BVY 97-130 NVY 98-39

-i I 95 J. Meyer 11/20/97 Revision of Main Station (Spare) 125v Battery Charger mga A-153 B W 97-155 NVY 98-25 196 J. Meyer 12/11/91 Safety Limit MCPR for Cycle 20 411 0198 A- 159 BVY 97-165 NVY 98-56 3/3/98 Final results of Core Monitoring relating to MCPR calculations BVY98-32 197 H. Heilman ii1219a CSLPCI Pump Start Time Delay (Table 3.2.1) 4/26/99 A-170 BVY 98-16 W Y 99-44 198 J. Meyer 912 1I99 EDG Fuel Oil Storage Tank Minimum Volume 11/22/99 A- 180 BVY 99- 119 NVY 99-1 14 199 H. Heilman 6130198 CSLPCI Aux Power Monitor (Table 4.2.1) 9/1/98 A- 162 BVY98-15 NVY 98- 127 200 J. Stanton 4/23/98 ServiceWater/Altermate Cooling - Tower System 311 1/99 A- I69 BVY98-52 NVY 99-30 1/25/99 Duplication of applicable Tech Spec pages into Technical Requirements Manual BVY 99- 1 1 20 I T. Silko 3/20/98 Containment Purge and Vent 5/14/98 A-I41

~ ~ 9 8 - 4 3 NVY 98-7 1 202 J. Meyer 511/98 Administrative Change to Section 6.0 Superceded WITHDRAWN BVY 98-63 By PC-208 51819a Revision to Tech Spec page BVY 98-70 PC 208 2/1/99 Supercedes PC No. 202 approved via BVY 99-20 I LA#171. No further action required.

203 J. Meyer 5/26/99 -

Proposed Change No.203 Suppression Pool Water Temperature Surveillance a130199 A- 174 BVY 99-75 NVY 99-82 Page 34 of 38 T.Silk0 review as parr of UND 2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS Change) 204 T. Silko 5/8/98 Maximum Torus Water Temperature 12/28/98 A-163 BVY98-69 NVY 98-170

-- 1/21/99 NVY 99-06

- SE Correction 7/10/98 Calculation to support change BVY 98-102 205 L.Gucwa 11/3/98 AdministrativeChange to TS 1/5/99 A-164 BVY 98-118 (ThisPCreplaces PC 180) NVY 99-02 1 2115/98 Correction BVY 98-167 206 L.Gucwa 12/10/98 Calibration of Hydrogen Monitors (Offgas) 2/12/99 A-I66 B W 98-119 NVY 99-14 207 T.Silku 9/4/9% Proposed Change No. 207 - Increased Spent Fuel Assembly Storage Capacity 1Z 21/99 A- I82 B W 98-130 NVY 99-124 2/8/99 Supplement B W 99-19 208 L. Gucwa 31/99 Proposed Change 208 - TS Section 6.0Rewrite 7/19/99 A-171 BVY 99-20 (Replaces PC 202.) NVY 99-69 205, W.Limberger 32/4/98 Proposed Change 209 Intermittent Opening of Primary WITHDRAWN WITHDRAWN BVY 98-162 (Replaced by PC-210)

PC 210 approved viaLA #I65 No further action required.

210 W. Limberger 12111/98 Proposed Change No.210 - Intermittent Opening of Manual Primary Containment Isolation 1/I 9/99 A-165 BVY 98-165 Valves (Withdrawal of PC-209) NVY 99-04 21 I D. Pendry 4120199 Proposed Change No.2 I 1 - Spiral Reload WITHDRAWN W ITHDMWVN 3VY 99-58 (Replaced by PC-223)

- PC 223 approved via LAJfl81. No further action required.

212 L.Gucwa 5/5/99 -

Proposed Change No.212 ATWS Rule (lOCPR50.62) / Standby Liquid Control System 9/17/99 A- I75 BVY 99-69 NVY 99-85 213 W. Limberger 4/16/99 Proposed Change No.213 - Generic Letter 88-01 and Use of Code Case N560 8/13/99 A- 172 BVY 99-13 NVY 99-76 214 L. Gucwa 4/24/99 Proposed Change No.214- TCV and TSV Closure Scram Bypass 8113/99 A- 173 BVY99-85 NVY 99-75 Page 35 of 38 T. S i 0 review as part of UND 2003-101-04

1 I I I

NKC Approval Proposed Change No.

Initiated by D. Pendry Date Submitted Letter No.

5/6/99 Title Proposed Change No. 215 - Removal of Main Steam Isolation Valve b & g e Date Approved Letter No.

WITHDRAWN I 1

(A: Lie.

Amend)

(C: TS Change)

WITHDRAWN I

I BVY99-68 (Replaced by PC-220)

PC 220 approved via LA# 178. No further action required.

NOT USED

' 217 B. Drews 6/15/99 Proposed Change. No. 217 - Surveillance Test Interval / Allowable Out-Of-Service Time 4/3/00 A-186 I 218 I

D. Pendry 1

BVY 99-76 7/20/99 (BVY99-161 Supplement)

Proposed Change No. 218 - Increased Core Flow NVY 00-35 4/25/00 NVY 00-42 A- 187 I BVY 99-82 -

219 I L.Gucwa I 7120199 Proposed Change No. 219 - High Pressure Cooling (HPCIIRCIC) and ADS Operability 10/1199 A-177 BVY 99-86 NVY 99-90 220 I).Pendry 6/29/99 Proposed Change No. 220 - Main Steam Line Isolation Valve Leakage 10/1/99 A-118 B W 99-83 (Replacement for 2 15) NVY99-91 1 22 I J. Meyer 7/12/99 Proposed Change No. 221 - SLMCPR Revision 9/21/99 I A-176 BVY99-91 NVY 99-87 222 W. Limberger 5/22/00 Proposed Change No. 222 - Inservice Inspection of Class MC Components 7/ 19/00 A- 192 I I BVY00-25 NVYOO-66 I 223 [ D.Pendry I warn kopvsed Change No. 223 - Spiral Core Loading Around a Source Range Monitor 12/14/99 1 A-181 I I BVY99-104 fRedacement for 21I f 224 I L.Gucwa I 11/5/99 Proposed Change No. 224 - Reactor Power Distribution Limits Applicability N W 00-60 Proposed Change No. 225 - Missed Technical SpecificationsSurveillance 10/13/99 A-179 NVY 99-98 226 L. Gucwa 12/21/99 Proposed Change No. 226 - Control Rod Block lnstrurncntation WITHDRAWN WITHDRAWN I *vy99-160

[Withdrawnper BVY 00-1 IS)

Resubmitted as part of PC 247 - approved via LA# 21 I . No hurther action warrantcd.

227 J. Meyer 10/18/99 -

Proposed Change No. 227 Revised SBGT Charcoal Testing Standard 7111/00 A- 189 BVY 99- 132 228 L. Gucwa 10121/99 Proposed Change No. 228 -Administrative Change BVY 99-134 NVY 00-14 1 229 L. Gucwa 12114/99 Proposed Change No. 229 - Relocation of Radiological Effluent Tech Specs (RETS) 8/24/00 I A- 193 BVY 99- 159 NVY 00-87 1 230 W. Lmberger 1/20/00 Proposed Change No. 230 - Testing of Augmented Off-Gas (AOG) Instrumentation 3/6/00 A- 184 BVY 00-11 NVY 00-24 Page 36 of 38 T.Silkoreview aspart of UND 2003-101-04

NRC Approval Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: Ts Change) 23 1 L. Gucwa a11/00 Proposed Change No, 231 - Main Steam Isolation Valve Surveillance Requirements 3/9/00 A-I 85 BVY 00-20 NVY 00-25 232 NOT USED --

233 L. Gucwa 5/23/00 -

Proposed Change No. 233 LPRh4 Calibration Frequency 7118/00 A-191 BVY 00-47 NVY 00-65 234 L.Gucwa 5/23/00 Proposed Change No. 234 - Reactor Coolant Chemistry - Conductivity and Chlorides 7/18/00 A-190 BVY 00-48 NVY 00-64 235 L. Gucwa 8/10/00 Proposed Change No. 235 - ECCS Requirements During RefueIing 11/17/00 A- 195 BVY 00-70 NVY 00-101 236 L. Gucwa 9/26/00 Proposed Change No. 236 - Standby Gas Treatment System Operability During Refueling 3/23/01 A197 BVY 00-88 NVY 01-18 237 B. Hobbs 9/14/00 Proposed Change No. 237 -Table 4.7.2 Notes 10131/00 A- 1 94 B W 00-84 NVY 00-108 238 J. Meyer 1012S/OO Proposed Change No. 238 -Administrative Changes I /23/01 A-196 BVY 00-97 NVY 01-10 239 T. Silko 11/30/00 Proposed Change No. 239 - Refueling Interlocks 4/20/0 I A-200

- BVY 00-90 NVY 01-40 240 B. Hobbs 11/3/00 Proposed Change No. 240 - High Pressure Core Cooling Systems Isolation Function 4/20/0 1 A-202 BVY 00-101 NVY 01-42 24 1 J. Meyer 10/25/00 -

Proposed Change No. 241 125 Vdc Battery Chargers 3i2ZO 1 A-198 BVY 00-98 NVY 01-25 242 J. Meyer 11/27/00 Proposed Change No. 242 - 24 Vdc ECCS Battery Removal 4J2W01 A-20 1 BVY 00-107 NVY 01-41 243 L. Gucwa mmo Proposed Change No.243 - LPCI OperabiIity During Shutdown 3/30/01 A- 199 BVY 00-112 NVY 01-22 244 T. Silko 1U19/00 Propased Change No. 244 - Revised P/rLimit Curves 5/4/01 A-203 BVY 00-113 NVY 01-46 245 L. Gucwa 4117101 Proposed Change No. 245 - Post-Accident Monitoring Instrumentation IOnlOl A-204 BVY 01-31 NVY 01-106 247 L.Gucwa I 6/21/01 Proposed Change No. 247 - ControI Rod Block Instrumentation 8/27/02 A-21 1 BVY 01-51 NVY 02-77 Page 37 of 38 T.Siko review as part of UND 2003-101-04

NRC Approval -

Proposed Initiated by Date Submitted Title Date (A: Lic.

Change No. Letter No. Approved Amend)

Letter No. (C: TS Change) 248 L. Gucwa 8/20/01 Proposed Change No. 248 -Elimination of Alternate Train Testing 8114/02 A-209 B W 01-65 NVY 02-71 249 L. Gucwa 811410 1 Proposed Change No. 249 - HPCI and RCIC LCO Extension to 14 days 10118/01 A-205 BVY 01-64 NVY 01-100 250 L. Gucwa 3/19/02 Proposed Change No. 250 - Elimination of the Main Steam Isolation Valve Closure and I 9118/02 A-2 12 BVY 02-18 Scram Functions of the Main Steam Line Radiation Monitors NVY 02-89 251 J. Meyer 11/20/01 Proposed Change No. 251 -Table 4.7.2,SBGT Heater and Miscellaneous Admin Changes 8/21/02 A-210 BVY 01-85 NVY 02-74 252 L. Gucwa 11/20l01 Proposed Change No. 252 - Allowed Outage Times for P A M Instrumentation 5110102 A-207 BVY 01-86 NVY 02-39 E53 T. Silko 1 ll4/02 Proposed Change No, 253 - U T Interval Extension BVY 02-62 254 D. Green 2/26/02 Proposed Change No. 254 - Definition of Operable 2/4/03 A-2 I3 BVY 02-12 NVY 03-14 255 L. Gucwa 1/9/03 Proposed Change No. 255-Definition of LSFT BVY 03-04 256 R. Daflucas 1u10/02 Proposed Change No. 256 - Admin Change to update Titles in Section 6.0 and Table of u27/03 A-214 BVY 02-95 Contents and EDG Fuel Oil Specification 251 J. Devincentis Proposed Change No. 257 - ARTSIMELLLA 258 L. Gucwa Proposed Change No. 258 - Reactor Pressure Vessel Integrated Surveillance Program 259 L. Gucwa Proposed Change No. 259 - Instrumentation Tech Specs I I I I Page 38 of 38 T. Silk0 review as part of UND 2003-101-04 i

- -c c . . - .

-3

Entergy Nuclear Vermont Yankee, LLC Entergy Nuclear Operations, Inc 185 Old Ferry Road Brattleboro, VT 05302-0500 March 26,2003 BVY 03-29 U.S.Nuclear Regulatory Commission A m Document Control Desk Washington, DC 20555 Subject. Vermont Yankee Nuclear Power Station License No.DPR-28 (Docket No.50-271)

Technical SpecEcatioas Proposed Change No. 258 I'-11 , RPV Fracture Toudmess and Material SurveilIanceReauirementq 7

Pursuant to 10CFR50.90, Vermont Yankee' 0hereby proposes to amend its Facility Operating License, DPR-28, by incorporating the attached proposed change into the VY Technical Specifications. This proposed change adopts the Boiling Water Reactor Vessel and hkrnals Project Integrated Surveillance Program and updates pressure and temperature Iimihtions for the reactor coolant system.

Attachments 1 and 2 to this letter contain supporting information and the safety assessment for the proposed change. Attachment 3 confaixls the determination of no significant hazards consideration.

Attachment 4 provides a proposed change to the Updated Final Safety Analysis Report regarding the Integrated Surveillance Program. Attachment 5 provides the marked-up version of the current Technical Specification and Bases pages, and Attachment 6 is the retyped Technical Specification and Bases pages.

VY has reviewed the proposed change in accordance with 10CFR50.92 and concludes that the proposed change does not involve a significanthazards consideration.

r'--l V Y has alsu determined that the proposed change satisfies the criteria for a categorical exclusion in accordance with 10CFRs1.22(~)(9) and dues not require an environmental review. Therefore, pursuant to 1OCFW 1 .De), no environmental impact statement or environmental assessment needs to be prepared for this change.

Upon acceptance of this proposed change by the NRC, VY requests that a license amendment be issued prior to the next scheduled refueling outage (Spring 2004) for implementation within 60 days of its effective date. A license amendment is required prior to the end of the next refueling outage because current TechnicaI Specifications for pressure-temperature limitations are only valid through the end of the current operating cycle, and current requirements for the removal of reactor vessel surveillance specimens would necessitate the removal of a surveillance capsule during the next refueling outage. Accordingly, VY respectfully requests timely approval of this license amendment request.

• Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations,Inc. are the licensees of the Vermont Yankee Nuclear Power Station

A B W 03-29 / Page 2 If you have any questions on this transmittal, please contact Mr. Len Gucwa at (802) 258-4225.

Sincerely, NUJAG-Michael A. Balduzzi Vice President, Operations Then pemnatly appeared before me, Michael A. Balduzzi, who, being duly sworn,did state that he is Vice President, Operatioas of the Vermont Yankee Nuclear Power Station, that he is duly authorized to execute and fde the foregoing document, and that the statementstherein are true to the best of his knowledge'andbelief.

. . 1. _.

I .

Thomas B.Silko,Notary Public My Commission Expires February 10,2007 Attachments cc: USNRC Region 1 Administrator USNRC Resident Inspector - VYNPS USNRC Project Manager - VYNPS Vermont Department of Public Service

Docket No.50-271 BVY 03-29 i

1 '

i .

Attachment 1 i

i Vermont Yankee Nuclear Power Station Proposed Technical Specification Change No. 258 RPV Fracture Toughness and Material Surveillance Requirements Supporting Information and Safety Assessment of Proposed Change

- 1 I -

B W 03-29 / Attachment 1 / Page 1

1.0 INTRODUCTION

1.1 PURPOSE This Proposed Change to the licensing basis of the Vermont Yankee Nuclear Power Station (VYNPS) revises the Technical Specifications (TS) and Updated Final Safety Analysis Report

( U F S A R ) regarding reactor pressure vessel @PV) fiacture toughness and materia1 surveillance requirements. The specific changes are summarized as follows:

1.1.1 RPV Material SurveillanceProgram Vermont Yankee is proposing to revise current, plant-specific RPV material surveillance requirements (SRs) by adopting the Boiling Water Reactor Vessel and Internals Project (BWRVIP) RPV integrated surveillance program (ISP) as the basis for demonstrating compliance with the requirements of Appendix H to IOCFR Part 50, Reactor Vessel Material Surveillance Program Rdquirements. In a safety evaluation dated February 1, 2002 (Ref. I), the NRC staf determined that the B W R W ISP was an acceptable alternative to existing B W R plant-specific RPV Y -veillance programs for the purpose of maintaining compliance with the requirements of A p p ~LIXH.

I. Pressure-Temperature Limitations update current pressure and temperature (a-T) limit curves for the reactor uAC&AL J e required by TS 3.6.A, Pressure and Temperature Limitations. Currently, TS Figure:, .,A.l, 3.6.2 and 3.6.3 expire at the end of the current operating cycle. This proposed chan,:e updr_tx the pressure and temperature Iits for the reactor coolant system through the end of the current operating Iicense. The updated P-Tlimits are based on a recdculated RPV neutron flv i r e wing ap iC staff-accepted neutron fluence methodology for boiling water reactors. The

- T:?

yes are valid through the end of the current operating license or 32 effective PY) and generally satisfy the requirements of Appendix G to 10CFR Part 50, FraLihx . ,.Iness Requirements.

1.2 DESCRIlTION OF THE PROPOSED CHANGE I .2.1 RPV Material SurveillanceProgram Current TS SR 4.6.A.5 (and associated Bases) regarding irradiated reactor vessel surveillance specimens are being revised. Specifically, the plant-specific SR 4.6.A.5 is being removed from TS,and details regarding the BWRVIP ISP (which is being adopted in place of the current plant-specific requirements) are being added to the UFSAR. In addition, conforming changes are being made to the TS Bases for Sections 3.6 and 4.6.

Current TS SR 4.6.A.5 requires:

The reactor vessel irradiation surveillance specimens shdi be removed and examined to determine changes m material properties in accordance with the following schedde:

B W 03-29I Attachment 1 I Page 2 C4PSULE REMOVAL nZ4.R I 10

,. .' 2 30 i 3 Stundby n e r e d & shall be wed to reassess materidproperties and $ate Figures 3.6.1, 3.6.2 and 3.6.3, as appropriate. The removal times shali be rejc?renced to the refireling outagefollowing the year specified, referenced to the ciate of commercial operm'oia.

I .

Attachment 4 of this Proposed Change provides a proposed revision to the UFSAR to adopt the provisions of'the-BWRVIP ISP in place of the existing plant-specific surveillance program.

Because the RPV material surveillance program requirements are being reIocated h r n the TS and incorporated into the UFSAR,the proposed change to the WSAR regarding the ISP is included in Attachment 4 for NRC review.

I- 3 As noted in proposed UFSAR Table 4.2.4, instead of withdrawing the second surveillance capsule after 30 year's of operation, the capsule will be maintained in a "standby" status. Other, changes to I ' the UFSAR which result from the updated P-Tcalculations are not included in this sub-, but

! will be made fol issuance of a license amendment.

I 1.2.2 I .

Current TS Figures 3.6.1,3.6.2 and 3.6.3 (and associated Bases), which establish P-Tlimitations for the reactor coolant system are being updated. The subject figures currently contain a restriction on their use, such that the figures are no longer valid affer the end of the current operating cycle (Cycle 23). The updated set of P-Tc w e s is valid through the end of the 40-year operating license and was redefined based on a recalculation of neutron fluence using in NRC staff-accepted neutron fluence methodology for BWRs. The updated curves are also clarified as described below. otherwise, the set of P-T limits remains as shown in current TS Figures 3.6.1, 3.6.2 and 3.6.3. In addition, conforming changes are being made to the TS Bases for Sections 3.6 and 4.6.

Current TS Fibres 3.6.1, 3.6.2 and 3.6.3 are being replaced by the figures in Attachment 6.

Specific changes entail:

0 Figures 3.6.1,3.6.2 and 3.6.3 currently mntain'a statement that each is valid through the end of Cycle 23. That validity duration is being changed to 4.46 x 10' megawatt-hours thermal (MWHtt)).

To improve legibility of the curves, the grid line divisions have been changed, the ordinate axis has been identified by 100 psi increments, and more data were used to plot the c w e s to improve resoIution.

A Note is being added to TS Figure 3.6.2 to specie requirements for minimum temperature when using local test instrumentation during flange tensioning and detensioning operations. The new Note will specify:

W i n g tensioning and detensioning operations with the vessel vented mrd the vesselfluid level below the flange region, the Jange temperature may be monitored with test

B W 29 i Attachment 1 i Page 3 rstrumentation in lieu of process instrumentation for the downcomer region fluid mperatzue and permment flange region outside s d a c e tempetawe. ?%e test sirurnentation uncertainty must be less than +f- JQF. l%e$ange region temperatwa wt be maintuheci greuter than or equal fo 72°F when monitored with test itrumentationdzwing tensioning, detensioning, and when imioned 0 e tabulation of pressure and temperature data on Figure 3.6.3 is being revised to more

urateIy reflect the plot of the curyes (the curves are unchanged). At I16OF the bottom d pressure is changed to 4'3 pig, instead of the current 416 psig. At 120°F, there uld be only two data points on Figure 3.6.3, and these are at 253 psig for the upper

.on and at 439 pig for the bottom head region. Therefore, the tabulation asponding to a ternperatur. of 12PF will only specify pressures of 439 psig and 253 for the bottom head regioi md upper region, respectively.

VY plar implement the proposed change to support the next refueling outage (i-e., Spring 2004) ar hequent restart. The proposed change involves the eIimhation of refueling outage work-scc 2nd its approval is needed for post-outage plant restart. Because current TS SR 4.6.A.5 r es that VY remove a RPV material capsule during the next refueling outage, and the c u m t SE P-Tcurves expires at the end of the current operating cycle (defined as the end of the next refur ioutage), a license amendment is required before the end of the refkeling outage.

The next I ling outage is currently scheduled to commence on April 3,2004.

2.0 B KGROUND B To ensure 2 structural integrity of RPVs, 10CFR50.60, "Acceptance criteria for fracture prevention fsures for light water nuclear power reactors for noma1 operation," imposes the specific fr *e toughness and material surveillance program requirements set forth in Appendices nd H to 10CFR Part 50.  !

2.1 FU a/IATERfAz.SURVEILLANCEPROGRAM Licensees of dear power plants are required by Appendix H to IOCFR Part 50 to implement RPV mater; urveilhrice programs (including the withdrawal and analysis of surveillance capsules) fos nitoring changes in the fracture toughness properties of ferritic materials in the reactor vesse -1tIine region which result from neutron irradiation. These programs consist of surveillance d e s installed inside the RPV that include specimens from RPV plate, weld and heat-affixted e materials. These specimens are removed at periodic intervals, tested and analyzed to rn +or the radiation embrittlement of the RPV. Appe~dixH provides two alternative methods for c iliance:

The first alterr 'e is the design and implementation of a plant-specific surveillance program that is consistent o ,I->%ASTM E-185 (Ref. 2). In accordance with this alternative, Iicensees must comply with e?' .T the edition of ASTM E-185that was current on the issue date of the American Society of Mec' .nical Engineers (ASME) Code to which the reactor vessei was purchased, or later editions thr gh the 1982 edition as the basis for estabIishing surveillance capsule withdrawal schedules.

B W 03-291 Attachment 1 t Page 4 i-The second alternative is addressed in paragraph III.C of Appendix H to 1OCIkSO, Xequirements 1  :

or an Integrated Surveillance Program, and involves the implementation of an integrated surveillance program in lieu of individual plant-specific RPV surveillance programs, Certain i technical and regulatory criteria are set forth in paragraph m.C.

Until recently, each 3WR has had its own RPV materid surveil1 en selection, testing, analysis and monitoring were conducted on a plant-specific basis. Over the past several years, the BWRW developed an ISP that meets the criteria defined in Appendix H for an ISP. The NRC M a p p r o v e d the BWRMP ISP in a safety evaluation (Sa, which was provided to the BWRVIP by M e r dated February 1,2002 (Ref. 1).

The NRC SE concIuded that the proposed ISP, if implemented in accordance with the conditions of the SE, is am acceptable alternative to all existing BWR plant-specific RPV surveillance programs for the purpose of maintaining compliance with the requirements of Appendix H to IOCFR 50 through the end of current facility 40-year operating licenses. In NRC Regulatory Issue Summary @IS) 2002-05 (Ref. 3), NRC endorsed the BWRW ISP and provided guidance for BWR IicenSeeS in implementing the ISP program.

ides certain benefits.

were selected for plant-specific swveillatice programs, the f knowledge concerning RPV material response to irradiation and post-irradiation fracture toughness was not as robust as it is today, As a result, many facilities did not include what would be identified today as the plants limiting RPV materials in their surveillance programs. Hence, the integrated effort to identify and evaluate materia other BWRs, which may better represent a facilitys limiting materials, should improve erall evaluation of BWR AIso, the inclusion of additional data from the-testing of BWR Owne tal Surveillance Program capsules will improve overall quality of the data being used to evaluate BWR RPV embrittlement.

Implementation of the ISP is also expected to reduce the costs associated with removing capsules fiom RPVs and surveillance testing and analysis, since surveillance materials that are of M e or no value (either because they lack adequate unirradiated baseline Charpy V-notch data or because they are not the best representative materials) will no longer be tested. In addition, the exposure of personnel to radiation due to the removal and handling of irradiated specimens should be reduced.

By letter dated November 12, 2002 (Ref. 4), the BWRW submitted Proprietary Report BWRVIP-86-A (Ref. 5 ) to the NRC staEfor information and review. BWRW-86-A represents a compilation of information from several sources upon which the NRC staff based its SE (Ref. 1).

The NRC staff reviewed the information in BWN@-86-A and, by letter dated December 16, 2002 (Ref. 6), found that it accurately incorporates all of the relevant information submitted by the BWRVIP to support NRC staffapproval of the B W R . .ISP.

A major consideration in the NRC staffs SE (Ref. 1) deals with BWR RPV fluence calculations.

Specifically, the NRC staffrequired as a condition to its SE that RPV neutron fluence caIculations use a fluence methodology that is acceptable to the NRC staff and is consistent with the guidance found in NRC Regulatory Guide 1.190 (Ref. 7). In addition, if differing fluence methodologies are used (Le., the methodology used to determine the neutron fluence values for a licensees RPV differs fiom the methodology used to establish the neutron fluence values of the ISP surveillance capsuIes which represent the RPV h the ISP), the results of these differing methodologies are compatible (i.e., within acceptable levels of uncertainty).

I BVY 03-29 / Attachment 1 I Page 5 2.2 P-T LIMITATIONS 2.2.1 Technical and Redatorv Basis 10CFR50.60, Acceptance criteria for fracture prevention measures for light water nuclear power reactors for normal operation, imposes the fracture toughness requirements for the reactor coolant pressure boundary set forth in Appendix G to Part 50. Licensees of nuclear power pIants.are required by Appendix G to lOCF Part 50, Fracture Toughness Requirements, to develop and use P-Tlimits in order to provide adequate margins of safety during any condition of operation, including anticipated operational occurrences and system hydrostatic tests, to which the reactor cooIant pressure boundary may be subjected over its service lifetime.

Appendix G to IOCFRSO d e s c n i the conditions that require P-Tlimits and provides the general bases for these limits. Operating h i t s based on the criteria of Appendix G, as defmed by applicab1e reguIations, codes, and standards, provide reasonable assurance that nonductile. or rapidly propggating failure will not occur.

1 Appendix G of Section XI of the ASME Boiler and Pressure Vessel Code (the Code), (Ref. 8) forms the basis for the requirements of Appendix G to 10CFRsO. The operating limits for i pressure and temperature are required for three categories of operation: (1) hydrostatic pressure tests and leak tests; (2) non-nucIear heatup/cooldown and low-level physics tests; and (3) core critical operation.

Pressure-retaining components of the reactor coolant pressure boundary that are made of ferritic materials (including the pressure vessel) must meet the requirements of Appendix G of the Code, as supplemented by the additional requirements in Table 1 of Appendix G to 10CFRSO for fracture toughness during system hydrostatic tests and any condition of normal operation, including anticipated operational occutrences. In addition to beltline considerations, non-beltline discontinuities such as nozzles, penetrations, and flanges may influence the construction of P-T curves.

The P-T limits are not derived from design basis accident analyses, but are prescribed for all plant I modes to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause non-ductile failure of the reactor coolant pressure boundary. The P-Tlimits are acceptance limits because they preclude.operation in an unanalyLed condition.

P-Tlimits are revised when necessary in accordance with Appendix H to 10CFR50 for changes in adjusted reference temperature for nil ductility transition (ARTn-r) due to neutron fluence values determined fiom the analysis of irradiated RPV beltline materials. Upon acceptance of this Proposed Change, the ISP discussed above will provide the dosimetry data and resuIts of fracture toughness tests as the bases for changes in A R T ~ for T the VYNPS RPV.

2.2.2 N 10CFR50, Appendix G requires the prediction of the effects of neutron irradiation on vessel embrittlement by calculating the ARTm and the Charpy Upper Shelf Energy (USE). For reactor vessel beltline materials, includingwelds, plates, and forgings, the values of ARTw must account for the effects of neutron irradiation, as part of the surveillance program of Appendix H to

I B W 03-29 I Attachment 1 I Page 6 10CFR.50. To predict these effects, NRC Generic Letter 88-11 (Ref. 9) imposes the use of methods described in Regulatory Guide 1.99, Revision 2 (Ref. IO). The fluence values calculated using the methodology described ia Regulatory Guide I .190 satisfy the requirements of Appendix G to 10CFRSO and ReguIatory Guide 1.99.

2.2.3 Flaw AnaIvsis The basic parameter in Appendix G to Sedion XI of the ASME Code (Ref. 8) for calculating P-T limit curves is the stress intensity factor &), which is a function of the stress and a postulated

! flaw. The Code methodology specifies that licensees determine the reference & fmrs. Code Case N-640(Ref. 14) permits use of the lower bound static initiation fiactwe toughnessvdue (Kio) in lieu of I&.

The methodoIogy of Appendix G to the Code requires that P-T curves satisfy a safety fgctor of 2.0 on stress intensities arising fiorn primary membrane and bending stresses during normal: p h t operations (including heatups, cooldowns, h d transient operating conditions) and a safety factor of I .5 on stri=sS intensi&s arising h m primary membrane and bending stresses when leak rate or hydrostatic pressure tests are performed on the reactor coolant system. Table I in Appendix G to 10CFRSO provides criteria or meeting P-T limitations of Appendix 0 to the Code and the minimum temperature requirements for ons.

3.0 3.1 RPV MATERIAL SURYEELANCEPROGRAM VY is a participant in tkBWRVIP, which d rRW materials and will formally implement the ISP upon NRC Iicense amendment.

BWRW-86-A (Ref 5 ) provides the technical and regulatory basis for the BWRVIP ISP and will be incorporated by reference in the VYNPS UFSAR As noted in s reply to fie BWRVIP dated December 16,2002 (Ref. 6), reference to B CeptabIe in lieu of referencing the separate source documents. Attachment 4 of this proposed change is a proposed revision to the UFSAR,which will become effective upon hplementation of the requested license amendment.

The BWRVIP ISP is intended to replace the ex pIant-specEc RPV material survei~~mce programs withrepresentative weld and base materials data from host reactors. It is not intended that VYNPS be an ISP host reactor, As indicated ~JI the Test Matrix in BWRVIP-86-A, RPV weld and plate surveillance materials from Susquehanna-1 have been selected fiom among all the existing plant surveillance programs (including the Supplemental Surveillance Program) to represent the corresponding limiting plate and material in the VYNPS RPV, Thus, in accordance with the ISP,no further capsules wiII be removed and tested fiom the VYNPS RPV. It is anticipated that the next Susquehanna-1 surveillance capsule should be removed from the vessel in year 20 12.

Based on the test results of the removed capsules, fluence calculations will be reevaIuated using a methodoIogy approved by the NRC and demonstrated to be consistent with the methods descriied

BVY 03-29 / Attachment 1 / Page 7 in Regulatory Guide 1.190 (Ref. 7). W used an updated fluence methodology provided by GE Nuclear Energy (GENE)(Ref. 11) and approved by NRC to develop the revised P-T curves, As shown in Table 4-5 of BWRVIP-864, Detailed Test Plan By Plant, the VYNPS RPV wall is expected to experience the lowest, end-of-life neutron fluence of all domestic B W .

Under the ISP, representative capsule data dl1 be provided to each BWR vessel owner for limiting vessel weld and base materials. These data will be evaIuated, as appropriate, using the methods in RepIatory Guide 1.99 (Ref. 10) in accordance with Appendix G to 10CFRSO for the determination of A R T ~ values.

T The relevant data (Le., Charpy shift results) will be used to re-evaluate ernbrittlement projections for the corresponding vessel beltline materials represent& by the materials in the capsule. This re-evaluation will be conducted by V Y based on the results determined fiom testing of representative materials. If changes in P-T limits are required due to a reassessment of the limiting ARTWTvalues, changes to the licensing basis will be requested, as appropriate, The reporting of test results to NRC, includingthe data required by ASTM E-185(Ref. 2), and the results of all hcture toughness (Le., Charpy) tests conducted on the surveillance materials will be made by the BWRVXP program administrator.

Although there are no plans to remove additional material surveillance specimens fiom VYNPS, the remaining two surveillance capsules will continue to reside in the RPV in accordance with the B W R W ISP,in case they are needed in the future as a contingency.

Consistent with the guidance provided in RIS 2002-05 (Ref. 3), and because current TS require withdrawal of RPV specimens, V Y is submitting this proposed change as a license amendment request. Current TS SR 4.6.A.5 requires that the second VYNPS surveillance capsule be removed during the refueling outage following the year in which 30 years of commercial operation is reached (Le., the Spring 2004 refueling).

NRC has veviously determined, as documented in Generic Letter 91-01 (Ref. 12) &at details of v -

,id surveilIanceprograms do not need to be included in the TS, because there would be n of controls that have been established by regulations (i.e., Appendix H to 10CFR50). I

.eI  :,instead of replacing the piant-specific surveillance program requirements in TS 4.6A.5 I with details regarding the ISP,VY will incorporate the ISP into the UFSAR. Because duplication of -mtrols is unnecessary, and adequate controls already exist, it is acceptable to relocate details 0: PV surveillance program to the UFSAK VY I- questing a change to the WNPS RPV material surveilhce program required by 10CFR50,Appendix I, currently implemented through TS SR 4.6A.5,to incorporate the and 3 W R W ISP into the V Y N P S licensing basis. The proposed change to VYs RPV material

-urveiIlanceprogram meets the regulatory criteria in Paragraph E.C of Appendix H to 10CFRSO.

Based on the foregoing considerations, including the prior acceptance of the BWRVIP ISP by the NRC staff, this proposed change is acceptable because it provides an overall improvement in the quality of data that will be obtained, analyzed and reported to NRC for the purpose of monitoring changes in the fiacture toughness properties ofRPV beItline materials.

B W 03-29 I Attachment 1I Page 8 I

3.2 P-T LIMITATIONS 3.2.1 Current Licensing Basis for P-T Curves VYNPS License Amendment No. 203 (Ref. 13) revised the TS by changing the RPV P-Tlimit curves specified in TS Limiting Condition for Operation 3.6.A, Reactor Coolant System -

Pressure and Temperature Limitations, as graphically represented in Figure 3.6.1, Hydrostatic Pressure and Leak Tests,Core Not Critical, Figure 3.6.2, Normal Operation, Core Not Critical, and Figure 3.6.3, Normal Operation, Core Critical. However, because VYs neutron fluence estimate used at that time to support generation of the P-T curves was not based on a methodology acceptable to the NRC staff for current licensing applications, a restriction was pfaced on the application of the P-Tcurves. That restriction disallows use of the P-T curves beyond the end of 1.1 the current operating cycle (Le., Cycle 23).

3 2.2 Undated P-T Curves The updated P-T curves were established based on the requirements of Appendix G to 1OCPR50 to assure that brittle hcture of the RPV is prevented. Attachment 2 to this Proposed Change provides the me f calcdation used by VY in generating the revised P-Tcurves (Le., TS Figures 3.6.1, 3.6.2 and 3.6.3). The revised P-Tcurves retah the same basic P-Tlimits as the current curves.

Composite P-Tcurves were generated for each of the pressure test, core not critical and core critical conditions at 32 EFPY.Attachment 6 includes proposed TS Figures 3.6.1,3.6.2 and 3.6.3, which also incorporate a tabulation of P-Tlimits for both the bottom head and upper head regions.

The revised P-T curves (and current curves) differentiate between the bottom head region and upper vessel regions. The methodology used to generate the P-T c w e s in this submittal is similar to the methodologyused to generate the curves approved in license amendment no. 203 (Ref. 13).

In this update, however, the estimate of the RPV neutron fluence was based on a new fluence methodology that follows the guidance of Regulatory Guide 1.190 (Ref. 7). Part of the analysis conducted in developing the P-T curves was to account for radiation embriitlement effects in the core region, or beltline, and A R T ~ values T were determined using criteria of ReguIatory Guide 1.99 (Ref. 10). However, although VY Conducted an analysis in accordance with Regulatory Guide 1.99, the more conservativeA R T ~ values T used in the prior evaluation were retained.

For the hydrostatic pressure and leak test curve (TS Figure 3.6.1), a coolant heatup and cooldown temperature rate of 40F/hr or less must be maintained at all times. Similarly, for the normal operation, core not critical (TS Figure 3.62) and the normal operation, core critical c u m (TS Figure 3.6.3), the P-T curves specify a coolant heatup and cooldown temperature rate of lOOF/hr or less for which the curves are applicable.

The change to TS Figures 3.6.1,3.6.2 and 3.6.3 to extend their applicability to 4.46 x lo8 MWH(t) corresponds to an integrated plant operation of 32 EFPY. This limitation is acceptable because it is based on the recalculated, expected neutron fluence over 40 years of operation at the current licensed power level, accounting for periods of downtime.

The enhancements made to TS Figures 3.6.1, 3.6.2 and 3.6.3 by slightly revising grid divisions, adding additional 100 psi increments to the ordinate axis, and improving curve resolution are

I BVY 03-29 I Attachment 1 I Page 9 administrative changes of preference. They are acceptable because they'd0 not change any technical requirement and are made to enhance user acuity.

The addition of a Note to TS Figure 3.6.2 to permit use of test instunentation during tensioning, detensioning, and when tensioned is acceptable because test instnunentation can provide a better method of monitoring bolt-up temperatures during this phase of operations. The use of such instrumentation is limited to the condition when the vessel is vented and vessel fluid level is below the flange region. The establishment of this condition ensures that the vessel cannot be pressurized while relying on test instrumentation. Because test instrumentation is more accurate (conservatively within +/- 2 O F ) than permanent temperature instrumentation (+/- lO"F), a limit of 2 72°F may be established when using test instrumentation. A 72OF limit for test instrumentation corresponds to an 8OoF limit for permanent temperature instrumentation when the respective instrumentation uncertainties are included. These values are acceptable because the analytical Iirnit for head bolt-up is 70°F (without instrument uncertainty) as stated in current TS 3.6.A.

The changes to the tabuiation in Figure 3.6.3 represent a correction of actual values used to generate the' current curves. The current tabulation indicates that four different pressure limits were established corresponding to a temperature of 120'F. As can be seen from the curves, there are only two such points for 120OF. Similarly, the change in bottom head pressure at 116°F to 413 p i g reflects a past administrative error in transcribing the actual value fiom the current curve.

These changes to correct the tabulation are acceptable because they do not change actual limits (the curves are unchanged) and reflect the outputs from previous analyses.

3.2.3 Application of ASME Code Case N-640 The updated P-T limits were developed using Section XI, Appendix G of the 1995 Edition with the 1996 Addenda of the ASME Code (Ref. 8). This code edition and addenda incoprated revised stress intensity factors into the Appendix G methodology, which is used to develop the actual P-T Iimit curves. The revised stress intensity factors are based upon the re-orientation of the postulated defect normal to the direction of maximum stress. NRC has approved this code edition with addenda, as documented in IOCFR50.55a(b)(2).

In addition, the updated P-TIirnit curves are based, in part, on the application of ASME Code Case N-640(Ref. 14). Pursuant to 10CFRs0.12 and by letter dated April 16,2001 (Ref. 19, the NRC granted an exemption to allow VY to deviate from the requirements of Appendix G to 10CFR50 in the use of this alternative method.

Code Case N-640permits application of the lower bound static initiation fracture toughness value equation (Kk equation) as the basis for establishingthe P-T curves in lieu of using the lower bound crack arrest fracture toughness value equation (Le., the &, equation), which is based on conditions needed to arrest a dynamically propagating crack-the method invoked by Appendix G to Section XI ofthe ASME Code. Use of the &, equation in determining the lower bound hcture toughness in the development of the P-T operating limits curve is more technically correct than the use of the Ki. equation because the rate of loading during a heatup or cooldown is slow and is more representative of a static condition than a dynamic condition. The &, equation appropriately implements the use of the static initiation fracture toughness behavior to evaluate the controlled heatup and cooldown process of a reactor vessel.

BVY 03-29 1Attachment 1 / Page 10 3.2.4 Neutron Fiuence Calculations In developing the updated P-T limit cwes, the VYNPS neutron fluence calculations were also updated. These calculation updates were performed using the NRC-approved General Electric Nuclear Energy (GENE) methodoIogy as documented in GENE'S Licensing Topical Report NEDC-32983P-A (Ref. 11). The NRC-accepted (Ref. 16), proprietary methodology is hlly described in NEDC32983P-A and is not repeated herein. In general, GENE'S methodology adheres to the guidance in Regulatory Guide 1.190 (Ref. 7)for neutron flux CalcuIations and is based on a two-dimensional discrete ordinates code.

VY's estimate of n surveillance capsule removed from VYNPS on March 4,1983, after 7.54 EFPY of irradiation.

The updated RPV current P-T curve calculation remain conservative. The updated fluence analysis supports replacing the Cycle 23 expiration date with a 32 EFPY (4.46 x 108MW-hour) expiration limit.

1 The revised calculations consist of two parts: First, the GENE methodology was applied to recdcuIate the surv coupon fluence rates. This task served to benchmark the new methodology. The ask involved updating the mode1 to include a modern core design.

VYNPS operating Cycle 21 was selected as represehtive of recent, modem core designs.

Sensitivity studies of contemplated core loadings; including the current Cycle 23, indicated that peak vessel fluxes are bounded by Cycle 21. The updated fluence calculation is documented in a proprietaty report prepared by for VY. A~uxxuuqof the VY RPV fluence analysis is Table 1 Snmmary of F I u Results I Location 1 Flux (n/crnz-s) I RPV bideswfiice - max location 2.96 x 10' Surveillance Capsule (30") 1.89~10' Using the core design for Cycle 21, the revised, cdculated peak fast flux (E>I MeV) at end of life is summarized in Table 1.

The fast neutron fluences at the end of lant life (32 EWY) were conservativefy calculated to be 2.99 x P dcm2 and 1.91 x lo" dcm for the peak RPV location and the surveillance capsule, respectively. Through the end of calendar year 2002, VYNPS had accumulated approximately 23.8 EFPY of operation.

32.5  ;

The current and updated P-T curves are based on bounding ART= values of 89'F at 1/4T and 73'F at 3/4T. To ensure compliance with Regulatory Guide 1.99, the new fast neutron fluence at the end of plant life, 2.99 x n/cm2, was used to assess the adjusted RTmr of beltline

I BVY 03-29 /Attachment 1 / Page 1I components. The shift evaluation followed Position C. I (surveillance data not available) and the C.l(3) attenuation formula. This evaluation is documented in Attachment 2 and demonstrates that the limiting beltline component CrrpV plate 1-14) remained the same, and the A R T ~ T values calculated in accordance with Regulatory Guide 1.99 remain bounded by values used to develop the current P-T curves. As demonstrated in Attachment 2, the equivalent fluence,when compared to the updated fast auence of2.99 x 10" n/cm2, remains very conservative.

Becaw the capsule and end-of-life (EOL) fluence values have changed, the USE equivalent margin analysis plant appIicability assessment (Ref. 17) has been incorporated into Attachment 2 to demonstrate continued compliance with ASME Code Case N-512(Ref. 18). The prediction of change in Charpy USE was calculated in accordance with Regulatory Guide 1.99. As summarized in Attachment 2, there remains ample margin between the projected decrease in weld and plate USE and the allowable value specified in NEDO-32205(Ref. 19). Therefore, VYNPS remains in compliance with USE requirements of 10CFR50 Appendix G by demonstrating that the projected decrease in USE per the guidance of Regulatory Guide 1.99 meets bounding limits established in the topical report.

I, 3.2.6 Non-Beltline Regions Non-beftline regions are defined as the vessel locations that are remote from the active fuel and where the EOL neutron fluence is not sufficient (i.e., 10 n/cm2) to cause any significant embrittlement. Non-beltline components include nozzles, closure flanges, some shell plates, the top a d bottom head plates, and the control rod drive penetrations.

Detailed stress analyses of the applicable non-belthe components were performed for the purpose of hcture toughness analysis. The analyses took into account the mechanical loadiig and anticipated thermal transients. The thermal stresses in the vessel walI are caused by a radial thermal gradient that is created by changes in the adjacent reactor coolant during transient conditions. Transients considered include lOO'F/hr startup and shutdown, reactor irip, loss of a.

feedwater heaters or flow, loss of recircuIation pump flow, and transients involving emergency core cooling injections.

3.2.7 Head Closure Flange Stresses in the VYNPS RPV head closure flange (predominated by preIoad stress) establish limits incorporated into the updated P-T curves. For the flange evaluation, membrane and bending stresses were extracted from the original vessel stress report for pressure, preload and thermal expansion loadings. The critical location for head preload is the weld region between the upper head and the head flange. A minimum bolt-up temperature of 70°F was conservatively used and this requirement is maintained in TS 3.6.A.3. This conservatism is appropriate because bolt-up tensioning is one of the more limiting operating conditions (high stress and low temperature) for brittle fracture.

The conclusion of the revised neutron fluence analysis is that the revised TS P-T curves bound the recalculated coupon and RPV fast neutron fluences by a sigaihcant margin. The updated P-T curves are acceptable because they satisfy the requirements of 10CFR50.6O(a), Appendix G to 10CFR50,and Appendix G to the ASME Code, as exempted by the methods of analyses in ASME I Code Case N-640. In addition, the revised P-T curves provide an acceptable margin of safety against RPV brittle fracture.

BVY 03-29 /Attachment 1 / P e e 12 3.3 Conclusion/Summary h summary, participation in the ISP will improve the quality of compliance with the regulatory requirements in Appendices G and H to 10CFR50 while reducing cost, exposure, and outage time associated with capsule removal, shipping, and testing. The methodologies used to develop the proposed P-T limit curves satisfy the requirements of the regulations (as modified by application of ASME Code Case N-640). The raised P-T curves and outputs fiom the ISP (which will be used as appropriate for future adjustmentsto P-T limits), ensure that adequate RPV safety mar-against nonductile failure will continue to be maintained during normal operations, anticipated operational occurrences, and hydrostatic testing. Together, these measures ensure that the integrity of the reactor coolant system will be maintained for the life of the plant.

In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and saf of the public will not be endangered by operation in the proposed manner; (2) such activities wiIl be conducted in compliance with the Commissions regulations; and (3) the issuance of the requested license amendment will not be inimical to the common defense and security or to tlie health and safety of the public.

4.0 REFERENCES

I

1. NRC letter fiom W.H. Bateman to C. Terry (BWRW Chairman), Safety Evaluation Regarding EPRI Proprietary Reports BWRVessel and Internds Project, BWR Integrated SurveillanceProgram Plan (BWRW-78) and BWRMP-86: BWR Vessel and Xnternals Project,BWR Integrated SurveillanceProgram Implementation PIan, February 1,<2002

2. American Society for Testing and Materials (ASW E-185,Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels July 1982

3. NRC Regufatory Issue Summary No. 2002-05, %RC Approval of Boiling Water Reactor Pressure Vessel Integrated Surveillance Program, April 8,2002

4. BWRW letter fiom C. Terry to NRC Document Control Desk, Project No. 704 -

BWRVIP-86-A: BWR Vessel and Internals Project, Updated B W R Integrated SurveillanceProgram QSP) Implementation Plan, November 12,2002

5. Boiling Water Reactor Vessel and hternals Project report, BWRVIP-86-A: B W R Vessel and Internals Project, Updated BWR Integrated Surveillance Program (ISP)

Implementation Plan, October 2002

6. NRC letter from W.H.Bateman to C. Terry (BWRVIP Chairman), NRC StaffReview of BWRVIP-86-A, %WR Vessel and Intern& Project, Updated BWR Integrated SurveillanceProgram (ISP) Implementation Plan, December 16,2002

7. NRC Regulatory Guide 1.190, %alculational and Dosimetry Methods for Determining Pressure VesseI Neutron Fluence, March 2001

BVY 03-29 i Attachment 1 J Page 13

8. American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section X, Rules for Inservice Inspection of Nuclear Power Plant Components, Appendix G, 1995 Edition, including Summer 1996 Addenda

9. NRC Generic Letter 88-11, NRC Position on Radiation Embrittlement of Reactor PressureVessel:Materials and its Impact on Plant Operations, JuIy 12,1988

10. NRC Regulatory Guide 1.99, %diation Embrittlement of Reactor Vessel Materials, Revision 2, May 1988

11. NEDC-32983P-A, Licensing Topical Report, General Electric Methodology for Reactor Pressure VesseI Fast Neutron Flux Evaluations, Rev. 1, December 2001 iI

12. NRC Generic Letter 91-01, Removal of the Schedule for the Withdrawal of Reactor .

Vessel Material Specimens fiom Technical Specifications,January 4,1991

13. NRC,letter h m Robert M. Pulsifer to Michael A. Balduzzi (VYNPC),Vermont Yankee Nuclear Power Station - Issuance of Amendment Re: PIT Curves (TAC No. MB0764, May 4,2001

14. American Society of Mechanical Engineers Code Case N-640,Alternative Reference Fracture Toughness for Development of P-T Limit Curves,Section XI, Division 1, February 26,1999

15. NRC Ietter fiom R M. PuIsifer to M.A. Balduzzi OYNpC), Vermont Yankee Nuclear Power Station - Exemption from the Requirements of 10 CFR Part 50, Appendix G (TAC No.MB0763), April 16,2001

16. NRC letter from S. A. Richards to J. F. KIappmth (GENE),Safety Evaluation for NEDC-32983P3,General EIectric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation (TAC No. MA9891), MFN 01-050,September 14,2001

17. NRC Ietter from W. R ButIer to D. A. Reid (VYNPC), Vermont Yankee Nuclear Power Corporation,Review of Equivalent Margin Analysis (TACNo. M89225),July 20, 1994

18. American Society of Mechanical Engineers Code Case N-512, Assessment of Reactor Vessels With Low Upper Shelf Charpy Impact Energy Levels,Section XI, Division 1, February 12, 1993 19.NEDO-32205,10CFR.50Appendix G Equivalent Margin Analysis for Low Upper Shelf Energy in BWR/2 Through B W 6 Vessels, Revision I ,November 1993

, DocketNo. 50-271 BVY 03-29 i

If 1.9 I Attachment 2 f

Vermont Yankee Nuclear Power Station i Proposed Technical Specification Change No.258

! , RPV Fracture Toughness and M a t e d Surveillance Requirements 4

Calculation Summary Report for Revised P-T eurVes m

II .i

.-I

-1

VYC-829, Ro. 4, ATTACHMENT 1 3-18-2003 .. .

CAulULATION

SUMMARY

REPORT FOR REVISED P-T CURVES FOR VERMONT Y M B E NUCLEAR POWER STATION

- 1 I. .

Prepared by: *3)8b03 Senior MecrhmricnUStructurd Engineer Reviewed by:

Michael Selling L M e c w UStnichtral Engineer . J.

1 t

Reviewed by:

' I VStructura1Engineer i Approved by:

Scott Goodwin MechanicdStmtural Engineering Supervisor

CALCULATIONY S

- REPORT FOR REVISED P-T CURVES FOR VERMONT YANKEE NUCLEAR POWER STATION 1.0 Introduction This attachment documents the revised set of pressure-temperature (P-T) curves developed for the Vemont Yankee Nuclear Power Station (VY). This work includes a fufl set of updated P-T curves (Le., pressure and leak test, core not critical, and core critical conditions) applicabie for a gross power generation of 4 . 4 6 ~ 1 0MWHR(th)

~ (which will bound VY power generation beyond March 12,2012, the end of VY's current operating license (EOL)).

The curves were developed using the methodofogy specified in ASME Code Case N-640[2],

the 1995 ASME Code,Section XI, Appendix G (including the Summer 1996 Addenda) [3],

and IOCFRSU Abpendix G [4].

The previous revision of this report was submitted to the NRC on February 23,2001 in support of VY's TS proposed change 244 [Attachment 2 of Reference 191. The NRC accepted the P-T curves submitted under proposed change 244 with the condition that for operation beyond Cycle 23, VY submit an amendment request justifyingthe use of the curves which satisfies the guidance of RG 1.190. [21]

In response VY has revised the vessel ffuence evaluation [11. This revised assessment follows the methodology documented in the GE Licensing Topical Report (L'IR) NEDC-32983P-A approved by the U.S.NRC for licensing applications in the Safety Evaluation Report [18] and in general, GE's methodofogy adheres to the guidance in Regulatory Guide (RG)1.190 for neutron flux evaluation.

The new EOL fluence value remains enveloped by the conservative RTndt shift values used here and in proposed change 244. This report has been updated to incorporate the revised fluence data and demonstrates that there is no impact to the current P-T limits.

Because the capsule and EOL fluence values have changed, the upper shelf equivalent margin analysis plant applicability assessment [17) has been incorporated into this report to demonstrate continued compliance with ASME Code Case N-512. [161.

In addition to the new fluence value, the grid line divisions on the curves have been changed to make them easier to read. More data was used to plot the e w e s to improve resolution. In addition, specific requirements for minimumtemperature using Iocal test instrumentation have been incorporated for flange tensioning and detensioning operations.

Prior to approval of proposed change 244, the NRC xequested that VY provide basis information to support revised initid RTndt values for beltline materials, nozzle geometry data, and stress intensity values used in the development of the P-T curves. VY provided a responce to this RAI VYC-829 R4,Attachment 1, Page 2 of 35

in reference [191. In this revision there is no change to the initial RTndt and nozzle geometry data provided in Reference [I 91.The stress intensity information previously provided [191 has been again included here to facilitate NRC review.

In summary, the revision tu this report is being done to incorporate four changes:

1) Incorporate the revised fluence values provided by the GE Report [11.

2) Incorporate the revised upper shelfequivalent margin analysis @MA) plant applicability form to demonstrate continued compIiance with ASME Code Case N-5 12

[la.

3) Provide enhancements in curve grid division and curve resolution to facilitate operator interpretation.

4) Inco&rate detailed minimumtemperature requirements for flange tensioning and detensioning.

All changes, except those that are non-essentid or of an administrative nature, such as correction of typographical mors, editorid changes or format preferences, are marked with margin bars.

2.i) Material Properties An assessment of the hcture toughness properties of alI material used in the VY reactor vessel plate, weld and forgings is provided in Attachment 2 to VYC-829 R4. Estimation of the initial value of the nil-ductility reference temperature (RTWT) was based on the methods described in Branch Technical Position MTEB 5-2 [5]. Charpy impact and drop weight test data from original construction Certified Materials Test Reports (CMTRs) and =-fabricated material testing [6,7],supplemented by more recent data fiom Battelle for one beltline plate [8], were used. The resulting initial R T ~ values T are listed in Table 1.

For all material adjacent to the reactox vessel flange region, the GE vessel purchase contract required that a nilductility k i t i o n temperature0 of 10°F be met. Review of the CMTR data shows that the minimum Charpy energy (longitudinal specimens) was 69 fi-lb at 10°F,with 52 mils Iateral expansion reported. Two no-break drop weight tests at 20°F were also reported. Based on MTE3 5-2, this justifies an R T m = 10°F.

For the limiting material adjacent to the core region, the previous submittal by VY [lo] stated that the initial R T m of plate 1-14 was 40°F. Further evaluation justifies that the R T ~ canT be conservatively taken as 30°F.

VYC-829 R4,Attachment I, Page 3 of 35

- Evaluation of the CMTR data shows that the minimum Charpy energy (&om longitudinal specimens) was 42 A-lb at a test temperature of 10°F. Lateral expansion was not reported. Two no-break drop weight tests at 40°F were reported, justifying the NDTT of 5 30°F. Based on MTEB 5-2, this justifies an initial R T ~ =T3OOF.

- Evaluation of the as-fabricated test data showsthat the minimum Charpy energy @om longitudinal specimens) was 65 ft-lb at 40°F.The minimumlateral expansion was 54 mils. Two no-break drop weight tests at 20°F were reported, justifying an NDTT of 5 10°F. Based on MTFJ3 5-2, thisjustifies an initial R T ~ 5T10°F.

- Additional testing by Battelle exhibited relatively low Charpy energy (longitudinal specimens) [SI. At 4OoF, 80°F and 12OoF,the Charpy energy was 46.5 ft-lb, 57.5 ft-lb and 87.5 R-lb, respectively with lateral expansion greater than 35 mils in all cases. From this data, it is estimated that the 50 ft-lb Charpy energy could have been achieved at I .

70°F. Using the criteria from MTEB 5-2, this also justifies an R T ~ ofT 3OoF.

Similar evaluations conducted in supporting VY calculations (Attachment 2 of VYC-829R4) establish the initial R T m values for all other materials.

Table 2-1 and Table 2-2 show an evaluation of the expected irradiation shift for the beltline plat&. The peak end of license POL) fast f l m c e of 2.99 x IOI7 dcm2 (E.X.0 MeV) used in Table 2-1 is from the Reference 1 GE report. The methodology used by GE to develop this fluence value is documented in GEs Licensing Topical Report (LTR)NEDC-32983P-A [l],

which was approved by the U.S.NRC for licensing applications in the Safety Evaluation Report Safety Evaluation for NEDC-32983P, General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation P A C No. MA9891), MFN 01-050,September 14,2001.

For purposes of detemining the P-T curves for the vessel core region materials, VY has elected to maintain the more conservatively shifted A R T m values previously used by VY:89°F at the 1/4Tpoint and 73°F at the 3/4T point. Based on guidance of Reg Guide 1.99 Rev. 2 lower values of ARTmT could have been used. The NRC highlighted this in their Reference 11 safety evaluation.

The conservatism of employing these A R T ~ values T is expressed in terms of equivalent fluence in Table 3. Based on the initial RTmvalues and chemistry factors from Table 2-2, and Regulatory Guide 1.99, Rev.2 [12] criteria for calculating A R T ~ Tthe , use of the consenrative AJXT~T values equates to a minhum end-of-life d i i c e fluence of 1.24 x lo* dcm2for the four core region plates. This is we11 beyond the peak endsf-life surface fluence, 2.99 x 1017 n/cm2calculatedfor Vermont Yankee by GE [I]. This also confirms that plate 1-14, used for the VY surveillancespecimens [SI,is the critical plate from the standpoint of brittle failure up to fluence levels well beyond that expected at VY.

Reference 1 also provides the axial distribution of 32-EFPY fast neutron fluence at the peak azimuth of the RPV inside surf.The results of the analysis demonstrate the fast ffuence outside the active axial fuel zone at the RPV wall is less than lx1017 n/cm2. The N4 feedwater nozzles are well above the top of active fuel and the N2 recirculation nozzles are below the VYC-829 R4. Attachment 1. P u e 4 of 35

bottom of active fbel. Therefore the fluence in these locations is substantialIy below 1x10

n/cm2.

Based on the revised fluence projection [l], per Reg Guide 1.99 [12] requirements, we have revised the projected decrease in upper shelf energy (USE)data and reevaluated the decrease against criteria from NEDO-32205 1171, the equivalent mar& topical report applicabIe to VY.

This topical report follows the methods provided in Code Case N-512[18] and was accepted by theNRC [19].

As summarized in Table 15, there remains ample margin between the projected decrease in weld and plate upper shelf energy and the allowable decrease recommended in topical report NEDO-32205.Therefore V Y remains in compliance with USE requirements of IOCFRSO Appendix G by demonstrating that the projected decrease in USE per the guidance of Regulatory Guide I .99 meets bounding limits estabIished in the topical report.

3.0 P-T Curve Methodology The P-Tcurve methodology is based on the requirements of References [2] through [4]. There are five regions of the reactor pressure vessel (RPV) that were evaluated in this calculation: (1) the reactor vessel beltliie region, (2) the bottom head region,(3) the feedwater nozzle, (4) the recirculation inlet nozzle, and (5) the upper vessel flange region. These regions will bound all other regions in the vessel with respect to considerations or brittle fracture. For the feedwater n o d e , the limiting conditionsof sudden injection of 50°F cold water into the nozzle were considered. For the remainder of the locations, 100°F/br heatup and cooldown were considered for Service Level A/B curves and 40"Fh heatup and cooldown were ConservativeIy assumed for pressure and leak test conditions. The bottom head region was independently evaluated for 1

anticipated operational occurrences including rapid cooling foilowing a plant scram and hot sweep transients typically associated with re-initiation of recirculation flow into a relatively i colder lower head region following a reactor scram and recirculation pump trip.

3.1 General Approach for Analytical P-T Limit Curves The general approach for cieveIopment of the P-T curves was as follows:  !

a. A temperature at the crack tip, T114~(i.e., 1/4t into the inside or outside vessel wall surface) is either determined using ASME Section XI, Appendix G methods or is conservatively bounded. The method for each location addressed in discussed in subsequent sections.

b. Calculate the allowable stress intensity factor, I&, based on T1/4tusing the relationship specified by Code Case N-640[2], as follows:

VYC-829 R4,Attachment 1, Page 5 of 35

where: = metal temperature at assumed flaw tip (OF')

ARTNDT= adjusted reference temperature for location under consideration and desired EFPY ("I?)

KIC = allowable stress intensity factor (ksi 4 t inch)

c. Calculate the thermal stress intensity fator, Kn. This is calculated based on ASME Section XI,Appendix G [3] for the beltline and lower head regions, fiom alternate analysis for the feedwater nozzle or recirculation inlet nozzlehpper vessel regions, or using membrane and bending stresses from the reactor vessel stress report [13] or the upper flange region.

k 3 d. Calculate the allowable pressure stress intensity factor, Kp,using the following relationship:

I.;1  :

GP= CKrcKn>/Sr:

f - 1 1 . , where: KIP = allowablepress factor (ksid inch)

SF = (Code specified) safety factor

! = 1.5 for pressure test conditions I .

= 2.0 for normal operation heatup/cooldown conditions For the upper flange region, the expression also includes an additional term that subtracts the preload stress intensity factor (muftiplied by SI?) fioni the numerator of the equation.

e. Comp sure, p, lowable pressure stress intensity factor, IGp, using either ASME Appendix G [3] for the beltline or alternate analytical vdues for other locations.

. . : - ik

f. Make adjustments for temperature andor pressure uncertainties and hydrostatic head to T114~and P, respectively.

g. Repeat steps (a) through (0 for otha temperatures to generate a series of P-T points.

3.2 Adjustments to the C w e s The following additional requjrements were used to define the P-Tcurves. These limits are established in Reference [41:

For Pressure Test Conditions (Curve A):

VYC-829 R4,Attachment I, Page 6 of 35

Ifthe pressure is greater than 20% of the pre-senrice hydrotest pressure, the temperature must be greater than RTNDT of the limiting flange material + 90°F.

Ifthe pressure is less than or equal to 20% of the pre-service hydrotest pressure, the minimumtemperature is conservatively taken as greater than or equal to the RTNDT of the limiting flange material -t- 60°F. This limit has been a standard GE recommendation for the BWR industry for non-ductile failure protection.

For Core Not Critical Conditions (Curve B):

If the pressure is greater than 20% of the pre-service hydrotest pressure, the temperature must be greater than R T ~ ofTthe limiting flange material + 120°F.

a If the pressure is less than or equal to 20% of the pre-service hydrotest pressure, the minimurntemperature is conservativeIy taken as greater than or equal to the R T ~ ofT the limiting flange material + 60°F.This limit has been a standard GE recommendation for the BWR industry for non-ductile failure protection. This limit is applicable when the flange is tensioned or in the process of being iensioned or detensioned. t .:

I 0 10CFR 50 Appendix G requires that temperature be maintained at or above the RTndt of the closure flange.

For Core Critical Conditions (Curve C):

0 The core critical P-T limits must be 40°F above any Pressure Test or Core Not Critical curve limits. Core Not Critical conditions are more limiting than Pressure Test conditions, so Core Critical conditions are equal to Core Not Critical conditions pIus 40°F. In addition, when pressure is less thanor equal to 20% of the pre-service hydro test pressure and water level is in the normal range for power operation,the minimum temperature must be greater than or equal to the R T ~ ofT the limiting flange material 3. 60°F.  ! .

0 At pressures above 20% of the pre-service hydro test pressure, the minimum Core Critical curve temperature must be at least that required for the in-service pressure test (taken as 1, IO0 psig), or 160°F above the highest RTMTof the vessel flange region. As a result of these requirements, the Core Critical curve must have a step at a pressure equal to 20% of the pre-senrice hydro pressure to the temperature required by the Pressure Test curve at 1,I 00 psig, or Curve B -t 40°F,wbichever is greater.

The resulting pressure and temperature points constitute the P-T curves. These curves relate the minimum required monitored temperature to the allowable reactor pressure. Applicable temperature and pressure adjustments (described below) are also included in Curves A, B,and C.

VYC-829R4,Attachment 1, Page 7 of 35

The lower head area of a BWR, due to convection cooling, stratification, and cool CRD flow is subject to lower temperaturesthan the balance of the Pressure vessel. In addition, the RTNMof the bwer head is much lower than the assumed ARTNDTbeing used for the beltline. The lower head is also not subject to the same high level of stress as the flange and feedwater nozzle regions. Therefore, separate curves were provided for the Iower head. These curves are Iess restrictive than the enveloping curve used for the beltline and the balance of the vesse1. This will provide Operators with a more accurate data for assessment of PT limits for this cooler region.

3.3 Instrument U n a t y and Hydrostatic Head A conservative evaluation of instrument uncertainty by VY derived the following bounding error due to instruments:

Temperap: &l Pressure: f 30 psig Thus,the derived P-T curves were shifted to the right by 10°F. When djusted for the maximum effects of hydrostatic head ( h mthe top head), the resulting pressure margins are shown in Table 4, where the conservativefy adjusted margins are used in the P-T curves.

During vessel tensioning and detensioning the permanent flange temperatureinstnunentation is removed and special test inStnunentation is applied to monitor flange temperature. During this procedure, the vessel is vented to atmosphere and the vessel fluid level is below the flange region. During this operation the externax temperature is equal or lower than the internal temperature, thereforethe e x t e d test instrumentation can be used as a more accurate and conservative assessment of flange temperature conditions. The test instnunentation is selected to have less than +/- 2OF Uncertainty.

3.4 Beltline EvaIuation For the beltline evduation,-theequations in ASME Section XI, Appendix G r31 are used to predict the stress intensity facto; and temperature shifts for inside-and outsidel/4T flaws. For the cooldown, KICwas conservatively based on reactor temperature; for heatup, the ASM3E Section XI, Appendix G methods for estimation of temperature at the 3/4Tpoint in the wall were used. Tables 5-8 provide detailed results for the calculations.

3.5 Flange Region For the flangeevaluation, membrane and bending stresses were extracted from the original vessel stress report for pressure, preload and thermal expansion (heatup/cooldown) loadings.

The critical location was determined to be the weld region between the upper head and the head VYC-829R4,Attachment 1, Page 8 of 35

flange [13 1. Stress intensity factors were calculated based on the equations similar to ASME Section XI, Appendix G for membrane and bending stresses except that a&al stresses were substituted for the pressure stresses in AShE Section XI. For this region, notes have been added to the P-Tcurves requiring thatthe mbhum of the fluid or the measured vessel flange skin temperatures be used; thus this temperature may conservatively be used to compute &,-.

At temperatures in excess of the 10CFR50Appendix G limits,the P-T limits based on the flange are mixh higher than those resulting h r n the beltline. Tables 9 and 10 provide detailed results for the critical cases (without the margins discussed in Section 3.2).

The tabulated stress intensity stuntnary for the flange under hydrostatic pressure and leak tests has been updated in this summary report. Table 9 submitted with PC chhnge 244 conservatively applied a 2.0 safety factor to the preload stress intensity for the Pressure Test condition. Table 9 has been updated to inchde the 1.5 safety factor per ASME XI. This change was done to better highlight the margin between ASME XI Appendix G temperature limits and the GE recommended minimumtemperature requirement. The revised stress intensity information is included in the stress intensity summary included in Table 16-1. This change has no impact on the limiting P-T curve.

At low pressure all vessel components, except those components in the flange region, have little stress and are not at risk to brittle failure. The stress of flange region components is predominantly due to preload. With preload removed (unbolted condition) and the vessel depressurized the ASME 'XI Appendix G minimum temperature requirement for all vessel mponents are well below OOF. In Table 17 the ASME XI P-T limits for the flange region

k. ' nut preload are given using the highest t h d and pressure stress intensity from the conEolling flangelocations. At 0°F the allowable pressure is 637 psig.

3.5 N4 Feedwater Nozzle he feedwater nozzle, the assessment did not consider heatup and cooldown, but i coridered the effects of injection of 50°F feedwater into the nozzle at various reactor temperatures, this being the minimum realistic temperature for establishing flow into the feedwater nozzles. The stress intensities for pressure and for the feedwater injection were taken from the VY calculation (VYC-1005) that supported VY's NUREG-0619feedwater nozzle inspection interval evaluation. In VYC-1005 a 1/8Tflaw at the feedwater n o d e blend radius region (1 .O inches base metal,1.1875 inches including the cladding) was evaluated.

This is considerably larger than the 0.823 maximumallowable flaw size (including cladding) that determines the blend radius inspection interval at VY and has been accepted by the NIRC

[143. KIc for the thermal shock transient was conservatively based on the mean of the injected feedwater and the reactor temperature, whereas the initial temperature is steady state at reactor temperature. The deepest point of the postulated blend radius would actually be slightly more affected by reactor temperature due to the larger exposed area for heat transfer. The results are shown in Table 11.

3.6 N2 Recirculation Nozzle VYC-829R4,Attachment 1, Page 9 of 35

This nozzle was evaluated because of the relatively high R T m of one of the nozzles. ~n evaluation, based on the simiIar FW n o d e analysis discussed above, was conducted to determine a conservative stress intensity factor for a 1/4T nozzle corner crack. CooIdown wu the only condition evaluated since the postulated flaw is at the inside surface in the nozzle blend radius. No credit was taken for the difference between the fluid temperature and the crack-tip temperatiue in computing &c. The results are shown in Table 12 and show that significant margin exists.

i 3.7 BottomHead The bottom head evaluation was conducted with methods similar to that or the beItline region.

II Since the bottom head has the control rod drive penetrations, the stresses and stress intensity f'actorswere modified. An evaluation of the effects of the penetrations showed that the membrane stresses in the bottom head would be bounded by using a factor of 2.75 times the nominal stress computed sphericalbottom head. Then,the stress intensity factors were multiplied by a factor of ed on assuming a flaw aspect ratio (a) of zero instead of a 1/6 aspect ratio flaw fmditionallyutilized for ASME Appendix G evaluations. This approach consewatively accounte iptical cracks could potentially interact with the CRD penetrations in For the bottom head, the P-T curves were based on the minimum of the bottom head huid or the measured outside surfice temperatures, such that KICis based on a minimumtemperature.

Sensitivity evaluationswere conducted to show that anticipated operating occurrences would not control for the bottom head region. Ofsi&cance to a BWR is a reactor scram with recirculation trip. For this transient, the lower head region can cool relatively quickly fiom normal reactor temperature. Then, if recirculation pumps are restarted, the relatively colder water in the bottom head cau be swept out by hot water fiom the bottom head region.

- For the cooldown transients, a transient was synthesizedthat bounded data taken fiom a 11 reactor scram transient at VY and another B W R plant. It included cooldown fiom 527°F to 3'75°F in 10 minutes, then a 2OO0F/hr cooldown to 175OF,followed by a 100°F/hr cooldown. This transient showed that the limitinghigh pressure was 1050 psig (with margins) at the end of the initial rapid cooldown period, and that the low temperature portion of the cooldown was essentially the same & that based on the normal P-T cooldown evaluations. The resulting aIIowable pressure versus bottom head fluid temperature for an inside 1/4Tflaw is shown in Figure 1. This evaluation is conservative since 1) there is normally a slight depressurization following a reactor scram, and 2) the initial assumed cooldown was significantly more severe than experienced at VY.

- For the recirculation pump restart transient, the maximUm possible pressure and temperature conditions of the water sweeping the bottom head region are at saturated conditions, coming fiom the upper vessel region. Andy& was conducted to evaluate a VYC-829R4,Attachment I, Page 10 of 35

transient temperatme and stress intensity factor for an outside 1/4Tflaw due to a step-change transient in the bottom head. Then, using these results, a limiting step change from any initial bottom head temperature to saturated steam conditions could be iteratively determined such that the KICwould not be exceeded at the assumed flaw.

The results are shown in Figure 2. Additional pressure margin would be available above 350°F,since the maximum possible value of the step-change temperature difference starts to decrease as a result of BWR operating pressure and temperatures conditions. Also shown on the curve is the expected pressure based on a maxim=

recommended top-to-bottom temperature difference of 145°F between the top and bottom head region temperatures for recirculation pump start, as recommended in GI3 Service Information Letter (SIL)251 [15]. This shows that there is signifcant margin between the h c t u r e limiting pressure and the pressures expected when using the SIL as a guideline for when the recirculation pumps may be restarted.

4.0 P-TCUW~

1 The resulting P-Tcurves, including the Appendix G to 10CFR50margins discussed in Section 3.2 are shown in Figures 3 through 5. i During vessel tensioning and detensioning the permanent flange temperature instsumentation is removed and special test instrumentation is applied to monitor flange temperature. When monitoring external ffange temperature with local test instrumentation during tensioning and detensioning the temperature should be at least:

+ 10°F @Tm* ofthe of the limiting flange material)

+ 60°F (GE Margin)

+ 2°F (Maximm Test Instrument Uncertainty)

= 72°F Therefore when monitoring extemal flange temperature with local test instrumentation during tensioning and detensioning the flange region temperatures must be maintained greater than or equal to 72 OF. A note has been added to the P-T curve in Figure 4 to specify this requirement.

With the vessel depressurized and the flange detensioned the minimumvessel temperature per 10CFR50 Appendix G is 20°F ( R T m of the limiting flange material, +lO°F, plus instrument uncertainty of permanently installed process instrumentation, 10°F).

VYC-829R4,Attachment 1, Page f 1 of 35

5.0 References

1. GE-NE-0000-0007-2342-R0, DRF 0000-0007-2342, Revision 0, Class 3, January 2003" Fiial Report Entergy Northeast Vermont Yanhee Neutron Flux Evaluation".

2. ASME Boiler and Pressure Vessel Code, Code Case N-640, "AlternativeReference Fracture Toughness for Development of P-TLimit Curves,"Section XI,Division 1, Apprc t*edFebruary 26,1999.

3. *5 3oiler and hressure Vessel Code,Section XI,Rules for Inservice Inspection of

,ar Power Plant Components, Nonman&ory Appendix G, "FractureToughness

ria for PrOteCtion Against Failure," 1995 Edition, Summer 1996 Addenda.

4. U.8 3 d e of Federal Regulations, Title 10,Part 50, Appendix G, "FractureToughness

&nts," December 1995.

5. ranchTechnical Position - MTEB 5-2, "Fracture Toughness Requirements", July 1981, Rev. 1.

6. Pressure Vessel Record Exhibit E "AsFabricated Test Reports," CB&I Contract 9-6201.

7. Pressure Vessel Record Exhibit D "CertifiedTest Reports," CB&I Contract 9-6201.

8. Battelle Columbus Report BCL-585-84-1,"Testing of UnirradiatedPressure Vessel SurveillanceBaseline Specimens for the Vermont Yankee Nuclear Generating Plant,

3/2 1/84.

9. Battelle Columbus Report BCL-585-84-3,"Examination,Testing and EvaIuation of Irradiated Pressure Vessel Surveillance Specimens fiom the Vermont Yankee Nuclear Power Station," 8/15/84.

10. Letter h m Vermont Yankee Nuclear Power Corporation BVY 89-1 13, to U.S.NRC, "ProposedChange to Revise the Reactor Vessel Pressure-Temperature Curves,in the Vermont Yankee Technical Specifications (Generic Letter 88-1 l)," 1 1/10/89.

I I. Letter f'rom Nuclear Regulatory Cornmission, NVY 90-077 to Vermont Yankee Nuclear Power Corporation, "Issuanceof Amendment No. 120 To Facility Operating License No.

DPR-28 -Vermont Yankee Nuclear Power Station (Tac No.75499).

12. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.99, Revision 2, May 1988.

13. Chicago Bridge & lron Company Stress Report # 9-6201-1,Volume 3, Vermont Yankee Reactor Vessel, Revision 6,1/06/71.

VYC-829 R4,Attachment 1, Page 12 of 35

14. Letter from US.Nuclear Regulatory Commission NVY 95-02, Evaluationof the Request for Relief From NUISEG-0619for Vermont Yankee Nuclear Power Station PAC No. M88&03),2/6/95.

15. GE Service Information Letter (SIL)No. 251, Control of RPV Bottom Head Temperature, 10131/77.

16. ASME Boiler and Pressure Vessel Code, Code Case N-512, Assessment of Reactor Vessels With Low Upper Shelf Charpy Impact Energy Levels,Section XI,Division 1,02-12-93.

17. NEDO-32205Class I, November 1993, Revision 1, 10CFR50 Appendix G Equivalent Margin Analysis for Low Upper Shelf Energy in B W 2 Through B W 6 Vessels.

1% Letter fhm U.S.NRC to Chairman of BWR Owners Group, Acceptance for Referencing Topical report NEDO-32205,revision 1, 1 OCFR50 Appendix G Equivalent Margin Analysis for Low Upper Shelf Energy inB W 2 Through B W 6 Vessels.

19. Letter from Vermont Yankee Nuclear Power Corporation BVY 01-14, to U.S.NRC, TechnicalSpecification proposed Change No. 244, Response to Request for Additional MormatioT 2001.

I 21). 4L. dar Regulatory Commission, NVY 01-046 to Vermont Yankee Nuclear 1 I

?owex Corporation, Issuanceof Amendment RE: P/TLimit Curves (TAC No. MF30764)

(Tac No. m0764).

21. Reg !90, Calculationaland Dosimetry Methods for Determining Pres- VCL itron Fluence, U.S.NRC,March 2001.

22. iY Document TE-2002-050,Updated RPV Fluence Calculations Evaluation in Support of P/TCurves,yy VYC-829 R4,Attachment I, Page 13 of 35

PT Umit fur Wrculation Pump Trip Cooldown with Margins i

I I

i .

I.. .)

Figure 1: Bottom Head Recirculation Pump Trip Pressdemperature Limit Curve PT Limit for Restart of Recirculation Pump with Margins i

1200.0 1000.0 800.0 I ..,.1 z

3 600.0 2 +Psat for T + 145F a

8 400.0 s!

'. t n 200.0 I i

0.0 I I

0.0 50.0 100.0 450.0 200.0 250.0 300.0 350.0 400.0 I Bottom Head Temperature, F Figure 2: PressurelTemperatureLimit Curve for Recirculation mUnp Start VYC-829 R4,Attachment 1, Page 14 of 35

Leak Test and Hydm P-T C u m 40'Flhr HeatuplCooldownLimit Valid Through 4.46E8 MWH(t)

I Figure 3: Pressure Test P-T Curve (Curve A)

VYC-829 R4,Attachment 1, Page I5 of 35

Figure 4: Core Not Critical P-TCurve (Curve B) 1

t. I 8 0 4 3 9 86 474 93 513 9 5 5 %

lal 803 I 105 655

110 723 115 m m848 125 gas 130 1013 136 1106 140 1214 140 1214 l45 1312 I?

I 150

..,. I 155 160 165

'7 80 80 100 t20 140 180 180 200 TEMPERATURE('0 VYC-829 R4,Attachment 1, Page 16 of 35

Figure 5: Core Critical P-T Curve (Curve C) core Wcal P-1curve 7OO"flhr HeatuplCoordawn Llmit If Pmssure 253 p i g , Water Level must be within Normal Range for Power Operation Valid Through U S E 8 MWH(Q 0

253 253 402 407 413 439 474 513 555 603 655 713 m

848 926 1013 I108 12f4 1214 1312 120 140 160 180 200 TEMPERATURE('0 VYC-829 R4,Attachment 1, Page 17 of 35

Table 1: Initial R T ~ forT Materials in Vermont Yankee Reactor Vessel I

1. Limiting beltline piate used in initid surveillance capsule evaluation [9]

2. Bottom head dollar plate includes all bottom head control rod drive penetrations VYC-829R4, Attachment I, Page 18 of 3 5

Table 2-1: Calculation of Peak Fluence VaIues Calculation of Effective Peak Fluence Values Units EFPY YearS 32 I Seconds per Year =3600*365*24 sec per 3 1536000 P

Margin@ 3/4T=2*sqrt(Sig-IA2+SigdeltaA2) O F 9.2 12.6 11.3 10.3 6.7 Sig-delta, StandardDeviation of delta O F 4.6 6.3 5.6 5.1 3.3

- RTNDT @ 3/4T Adjusted RTNDT @ 1/4T "F 57.0 27.3 33.2 30.3 -50.3 Adjusted RTNDT @ 3/4T  ; OF \ 48 15 23 211 -57 NOTE: Sig-deIta lesser value of 17°F for base metals and 28°F for welds or 1i2 delta RTNDT VYC-829 R4,Attachment 1, Page 19 of 35

Table 3: Calculation of Equivalent Peak Beltline Fluence Values II I .

I .i Table 4: Pressure Margins at Locations of Interest VYC-829R4, Attachment 1, Page 20 of 35

I _

Table 5 : P-T Evaluation - Beltline Hydrostatic Test (Heatup)

PressureTemmrafure Curve Calculation (Pressure Test w/Heaiup = Curve A)

Plant =

Campanent =

Vessel thickness, t = inches, so 4t = 2.249 hch Vessel Radius, R = inches A R T N=~ "F Heatup Rate., HU = 'Fhr k= ksPinchu' (for cooldown rate above)

Mr= (From App G, Fig.6-2214-1)

ATlm" "F = (w) 0.92 using FQS. G-2214-1 & G-2214-2 Safety Factor = (for hydrotest)

Mm = {for inside surface axial flaw)

Temperature Adjustment = 'F i Pressure Adjustment = psis (hydrostatic pressure + Uncertainty)

Fluid Calculated Adjusted Adjusted Temperature 1!4? Pressure Temperature Pressurefor ~

T Temperature I(lc KIP P for P-1 Curve P-T Cunre

('0 ("F) (ksrInch=) (ksifinchm) (pig) (OF) (pig) 50.0 43.9 44.78 28.89 700 60.0 650

== 0 4P 7 45.99 29.51 720 65.0 670 47.34 30.40 742 70.0 692 48.83 31.39 766 75.0 716 1 u.u 33.3 50.47 32.49 793 80.0 743 75.0 58.9 52.29 33.70 823 85.0 773 2; 0 '3.9 54.29 35.04 855 90.0 805 85 D 78.9 56.51 36.52 891 95.0 &l 90.0 95 - 83.9 c

58.98 61.67 64.67 38.15 39.96 41.96 931 975 1024 100.0 105.0 110.0 881 925 974 67.98 44.46 1078 115.0 7,028

. I4.0 103.9 71-64 46.60 1138 120.0 1,088 115.0 108.9 75.68 49.30 1203 125.0 1,153 120.0 113.9 80.15 52.27 1276 130.0 1,226 125.0 118.9 85.08 55.57 1356 135.0 1,306 VYC-829 R4,Attachment 1, Page 21 of 35

Table 6: P-T Evaluation - Bdtline Hydrostatic Test (Cooldown)

Pressure-TemrPerature Curve Calculation (Pmssure Tesfw/Cooldown = Curve A) lnmts: Plant =

Component =

Vessel thickness. t = inches, M) 4 = 2.249 din&

Vessel Radius, R = inches

~TNDT= F' I

! Cooldown Rate, CR = 'Fhr

, . ksiiinch"' (for cooldown rate above)

Krr=

MT" (From App G, Fig. 62214.1)

AT$&= 'F = (W) '0.44 using Figs. G2214-1 & E2214-2 Safety Factor = (for hydrotest)

M, = (for inside surface axial flaw)

i. ..I i Temperature Adjustment =

Pressure Adjustment =

'F psig (hydrostaticpressure .iUncertainty) f ' 1 Fluid Cakulated Adjusted Adjusted i Temperature mi Pressure Tempeature Pressure for T Temperature .-

KIC K. P for P-T curve P-T Curve

('F) ('F) (ksI*inchin) (ksilnchm) (pslg) (OF) (pslg) i 50.0 50.0 42.70 27.01 636 60.0 586 55.0 55.0 43.70 27.67 651 65.0 601 60.0 60.0 44.81 28.41 669 70.0 619 1

85.0 65.0 46.03 29.22 688 75.0 638 70.0 70.0 47.38 30.12 709 80.0 659 75.0 75.0 48.87 31.12 . 733 85.0 683 80.0 80.0 50.52 32.22 758 90.0 708 85.0 85.0 52.34 33.43 787 95.0 737 90.0 90.0 54.35 34.77 819 100.0 769 95.0 95.0 58.58 36.25 853 105.0 803 100.0 100.0 59.04 37.89 892 110.0 842

. ..d 105.0 105.0 61.75 39.77 935 115.0 885 110.0 110.0 64.70 41.71 982 120.0 932 115.0 115.0 68.08 43.92 1034 125.0 984

-1 120.0 120.0 71.74 46.37 1092 $30.0 1,042

.I 125.0 125.0 75.80 49.07 1155 135.0 1,105 130.0 130.0 80.28 52.05 1225 140.0 1,175 135.0 135.0 85.23 55.35 1303 145.0 1,253 VYC-829 R4,Attachment 1, Page 22 of 35

I -

Table 7: P-T Evaluation - Beltline Level A/B (Heatup)

Pressure-Tenmeratwe Curve Caiculation (Core Not CffticaVHeatup = Curve 8)

Inmt.5: Plant =

Component =

Vessel thickness, t = inches, so Jt = 2.249 qinch Vessel Radius, R = inches N N D T= 'F Heatup Rate, HU = 'Fhr Kr' ksEnchIl2 (for heatup rate W e )

MT= (From Am 0, Fa. G-2214-1)

ATlf41= "F= (W)0.92 using Figs. G2214-I & G-2214-2 Safety Factor = (for level -1 Mm= (for outside surface axial flaw)

Temperature Adjustment= "F Pressure Adjustmmt = pig (hydrostaticpressure + uncertainty) i;,I Fluid Calculated Adjusted Adjusted Temperature f14t Pressure Temperature Pressurefor I T Temperature Icc P for P-TCurve P-TCurve CF) ('0 (ksWnchm) ("F) (pig) 50.0 34.7 42.83 60.0 420 55.0 39.7 43.84 19.75 482 65.0 432 60.0 44.7 44.96 20.31 496 70.0 446 85.0 49.7 46.20 20.93 511 75.0 461 70.0 54.7 47.57 2161 528 80.0 478 75.0 59.7 49.08 22.37 546 85.0 496 80.0 64.7 50.75 23.20 566 90.0 516 85.0 69.7 52.59 24.1 3 589 95.0 539 90.0 74.7 54.63 25.15 614 100.0 564 95.0 79.7 56.89 26.27 641 105.0 59?

1OO.O 84.7 59.38 27.52 672 110.0 622 105.0 89.7 6213 28.W 705 115.0 655 110.0 94.7 65.17 30.42 74i3 120.0 693 i 115.0 99.7 68.53 3210 784 125.0 734 120.0 104.7 72.25 33.96 829 130.0 779 125.0 109.7 76.36 36.01 879 135.0 8%

130.0 114.7 80.90 38.28 934 140.0 884 135.0 119.7 85.91 40.79 996 145.0 948 140.0 124.7 91.46 43.56 1063 150.0 1,013 145.0 129.7 97.58 46.62 TI38 155.0 1,088 150.0 134.7 104.36 50.01 1221 160.0 $,171 155.0 139.7 111.84 53.75 1312 165.0 1,262 VYC-829 R4,Attachment 1, Page 23 of 35

Table 8: P-T Evaluation - Beltline Level A/B (Cooldown)

Pressure-TemDerature Curve Calculation (Core Not CrificaV Cooldown = Curve B)

Piant =

Component =

i Vessel hiduress,t inches, so 4 = 2.249 din&

Vessel Radius, R = inches ARTm = "F Cooldown Rate, CR = 'F/hr Krr - ksPinchlR (for cooMown rate above)

MT - (From App G, Fg.(3-2214-1)

ATlwt - 'F = (W)0.44using Figs. G-2214-1 & (5-2214-2 Safely Factor = (for level N E )

Mm = (for inside surface axial flaw)

Temperature Adjustment = 'F I1 Pressure Adjustment = p i g (hydrostatic pressure + uncertainty)

Fluid Calculated Adjusted Adjusted Ternperature 114t PresSUre Temperature Pressure for T Temperature KK: KIP P for P-T Curve P-T Curve (OF} rF) (ksi'inchm) (keilnchm) (psfg) (.F) (pig) 50.0 50.0 42.70 18.61 438 60.0 388 55.0 55.0 43.70 19.14 450 65.0 400 60.0 60.0 4-82 19.66 463 70.0 413 I

65.0 Li5.0 48-03 20.27 477 75.0 427 70.0 70.0 47.38 20.95 493 80.0 443 75.0 75.0 48.87 21.69 511 85.0 461 80.0 80.0 50.52 22.51 530 90.0 480 85.0 85.0 52.34 23.43 551 95.0 501 90.0 90.0 54.35 24.43 575 100.0 525 95.0 95.0 56.58 25.54 601 105.0 551 100.0 100.0 59.04 28.77 630 110.0 580 105.0 105.0 61.75 28.13 662 115.0 612 110.0 110.0 64.78 29.63 698 120.0 648 115.0 115.0 68.08 31.29 737 125.0 687 120.0 120.0 71.74 33.13 780 130.0 730 125.0 125.0 75.80 35.15 828 135.0 778 130.0 130.0 80.28 37.39 880 140.0 830 135.0 135.0 85.23 39.87 939 145.0 889 140.0 140.0 90.70 42.61 1003 150.0 953 145.0 145.0 96.75 45.63 1074 155.0 1,024 150.0 150.0 103.43 48.97 1153 7 60.0 1,103 f55.0 155.0 110.82 52.66 1240 165.0 1,190 160.0 160.0 118.98 56.75 1336 170.0 1.286 VYC-829 R4,Attachment I, Page 24 of 35

Table 9: P-T Evaluation - Flange Hydrostatic Test (Heatup)

Pressure- Temperature Curve Calculation (Pressure T8St Upper Flange 2 Heatup)

Plant =

Component = Upper Flangmub IntersectionAxial Flaw Vessel thidmess, t = incloes Vessel Radius, R = inches ARTm OF===->

I<lr+ 1.5 x K m ksfiflch'" (Nok F Safely Fador = (for hyd-)

Kip for 1000 psis = ksi'Fnch'"

Te!mperatureAdjustment = "F Pressure Adjustment = pslg (hydrostatic pressure+ Uncertainty)

Ruid Calculated Adjusted Adjusted Temperature 1l4t Pressure Tempeature Pressure for T Ternperaturn itc Kp P for P-TCurve P-T Curve

(.F) RF) (ksrinch'n) (ksPlnch'") (wig) r9 (pig) 0 0.0 50.18 -13.63 -1323 IO -1358 5 5.0 51-96 -12.44 -1208 15 -1243 10 10.0 53.93 -11.13 -1 080 20 -1115 15 15.0 56.1 1 -9.67 -939 25 -974 20 20.0 58.52 4-06 -783 30 -818 25 25.0 61.19 -6.29 -611 35 -646 30 30.0 64.13 -4.33 -420 40 -455 35 35.0 67.38 -2.18 -210 45 -245

-10 40.0 70.98 0.24 23 50 -12 L j 45.0 74.95 2.89 280 55 245 5;. 50.0 79.34 5.81 565 60 530 55 55.0 a420 9.05 879 65 844 60 60.0 89.56 12.63 1226 70 1191 65 65.0 95.49 16.58 1609 75 1574 67 66.9 97.93 18-20 1767 77 1732 70 70.0 102-04 20.94 2033 80 1998 75 75.0 109.28 25.77 2502 85 2467 80 80.0 117.28 31.11 3020 90 2985 i

VYC-829 R4,Attachment 1,Page 25 of 35

Table 1 0 P-T Evaluation - Flange L,eveI A/B (Heatup) pressure-fermberature Curve Calculation (Corn Not CMiml- Upper Flange 2-Heatup)

Plant =

Component=

Vessel thickness, t Vessel RadJw, R =

ARTNOT'

&T+2*K, safety Fador = K ksi'inch

KIpfW l O O O p s i S = I(In=l .O*Preload=

TEtmperatureAdjustment = KrfThermal=

PressureAdjustment = 3static pressure + uncertainty)

Fluid Calculated Adl- Adjusted Temperaturn 114t Pressure Temperature Pressure for T Ternmature -

IGe KIP P for P-T CUNB P-TCurve (DF) rF) (ksPinchl") (ksrlncfi'? (psig) (*F) (wig)

-15  ! -15.0 45.78 -25.40 -2468 -5 -250f

-10 -10.0 47.10 -24.74 -2402 0 -2437

-5 -5.0 48.56 -24.01 -2331 5 -2366 0 0.0 50.18 -2320 -2253 io -2288 5 5.0 51.96 -22.31 -2166 15 -2201 10 40.0 53.93 -21.32 -2070 20 -2105 15 15.0 56.1 1 -20.23 -964i 25 -1999 20 20.0 58.52 -19.03 -1847 30 -1882 25 25.0 61.19 -17.70 -1718 35 -1 753 30 30.0 64.13 -16.22 -1575 40 -<ti10 35 35.0 67.38 60 -1417 45 -1452 40 40.0 70.98 12.80 -1243 50 -1278 45 6.0 74.95 -10.81 4050 55 -TO@

50 50.0 79.34 -8.62 -837 60 -872 55 55.0 84.20 -6.19 -601 65 -636 60 60.0 a9.s -3.51 -341 70 -376 65 65.0 95.49 -0.55 -53 75 -88 68 66.0 98.75 0.08 8 76 -27 67 67.0 98.03 0.73 70 n 35 68 68.0 99.34 1.38 134 78 99 69 69.0 100.88 2.05 199 79 164 70 70.0 102.04 2.73 265 80 230 71 71.O 103.43 3.42 333 81 298 72 72.0 104.85 4.13 401 82 368 73 73.0 106.30 4.86 472 83 437 74 74.0 107.77 5.60 543 84 508 75 75.0 109.28 6.35 616 85 581 76 76.0 110.82 7.12 691 86 656 n 77.0 . 112.38 7.90 767 a7 732 78 78.0 113.98 8.70 845 88 a10 79 79.0 115.62 9.52 924 89 889 80 80.0 127.28 10.35 1005 90 970 VYC-829 R4,Attachment 1, Page 26 of 35

Table 11: P-T Evaluation - Feedwater Nozzle Level A/B Pressure-Temperature Curve Calculation (Core Not Critical - FW Injechn - Comer Nozzle Crack)

Plant =

Component =

Vessel thickness, t =I V U Radius, R =

ARTNOT =

KiT far 552F 50F Step = Temp. Change 502 F Step Safety Factor =

KIP for 1025 psig =

TennperatureAdjustment =

Pressure Adjustment = pressure + uncertaii Fluid Calculated Adjusted Adjusted Temperature mt Pressurvi Temperature Pressure for T Temperature KIP P for P-T Curve P-T Curve (F) ,/ (F) _(ksPinchyn1 (ksmnthln) (ksl*inchm) (pslg) CF) (pslg) 50 50.0 58.52 0.00 29.26 887 60 842

~~

55 52.5 59.82 1.06 29.38 891 65 846 60 55.0 61.19 2.12 29.53 896 70 851 65 57.5 62.62 3.18 29.72 901 75 856 70 60.0 64.13 4.25 29.94 908 80 863 75 62.5 65.72 5.31 30.21 916 a5 871 80 65.0 67.38 6.37 30.51 925 90 880 85 67.5 69.14 7.43 30.85 936 95 891 90 70.0 70.98 8.49 312 4 948 100 903 95 72.5 72.92 9.55 31.68 962 105 916 100 75.0 74.95 10.61 32.17 976 110 931 105 77.5 77.09 11.67 32.71 992 115 947 110 80.0 79.34 12.74 33.30 I010 I20 965 115 t20 82.5 85.0 81.71 84-20 13.80 14.86 33.96 34.67 1030 1051 125 130 985 1006 P

125 87.5 86.81 15.92 35.45 1075 135 1030 130 90.0 89.56 ?6.98 3629 1fOO 140 1055 I35 92.5 92.45 18.04 37.20 1128 145 1083 140 95.0 95.49 19.10 38.19 1158 150 1113 145 97.5 98.68 20.17 39.26 1.191 155 1146 150 100.0 102.04 21.23 40.41 1225 160 1180 155 102.5 105.57 22.29 41.84 1263 i65 1218 160 105.0 1O9.28 23.35 42.96 1303 170 1258 VYC-829 R4,Attachment 1, Page 27 of 35

Tablel2: P-TEvaIuation - Recirculation N o d e Level AA3 Pressure- Temperature Curve Calculation (Core Not Critical - N2 Recirc Non - Cooldown) lnwts: Plant Component Vessel thickness, t Vessel Radius, R K

Sa%ty Fador Kip for 1025 P s ~

Temperature Adjustment ti PressureAdjustment itic pIresure + uncertain Fluid Calculated AdJusted Adjusted Temperature 114t Pressure Temperature Pressurefor T ~~ernperatm Kc KP P for P-T Curve P-1Curve (OF) (OF) (ksi^inch") (ksitinch*R) (pslg) (OF) (psig) 0 0.0 39.44 7.19 166 10 111 5 5.0 40.10 7.52 174 15 119 IO 10.0 40.83 7.88 183 20 128 15 15.0 41-63 8.28 192 25 137 20 20.0 42.52 8-72 202 30 147 25 25.0 43.50 9.21 213 35 158 30 30.0 44.58 9.75 226 40 171 35 35.0 45.78 10.35 240 45 i85 40 40.0 47.10 11.01 255 50 200 45 45.0 48.58 11.75 272 55 217 50 50.0 50.18 12.55 291 60 236 55 55.0 51.96 13.45 311 65 256 60 60.0 53.93 14.43 334 70 279 65 65.0 58.1 1 15.52 360 75 305 66 66.4 56.78 15.86 367 76 312 I I, 4 70 70.0 58.52 16.73 387 a0 332 70 70.3 58.70 16.81 389 80 334 75 75.0 61.19 18.06 418 85 363 80 80.0 64.13 19.53 452 90 397 85 85.0 67.38 21.16 490 95 435 90 90.0 70.98 22.95 532 100 477 95 95.0 74.95 24.94 578 105 523 100 100.0 79.34 27.14 629 110 574 105 105.0 84.20 29.56 685 115 630 110 110.0 89.56 32.25 747 120 692 115 . 115.0 95.49 35.21 816 125 761 120 120.0 102.04 38.48 891 130 836 125 125.0 109.28 42.10 975 1% 920 130 ' 130.0 117.28 46.11 1068 140 1013 VYC-829 R4,Attachment 1, Page 28 of 35

Table 13: P-TEvaluation - Bottom Head Hydrostatic Test (Cooldown)

Pressure-Temperafure Curve Calculaiion (Pressure Test w/ Cooldown = Curve A)

Inputs: Plant =

Component =

Vessel thickness, t = inches, so 4 = 2.437 din&

Vessel Radius, R = inches ARTNm = 'F Cooldown Rate, CR = "Flhr Kn= k s p i n d K(for cootdown rate above)

&= (From App 0, Fig. G-2214-1)

ATim = 'F = (m) 0.44 using Figs. G-2214-1 G-2214-2 L.

Safety Factor = (for hydrotest)

Factor = M, concentration factor M, = (for inside surface axial flaw) 1 Temperature Adjustment = "F Pressure Adjustment = psis (hydrostatic pressure + Uncertainty)

Fluid Cafculated Adjusted Adjusted Temperature 114t Pressure Temperature Pressurefor T Temperature KIC b P for P-7Curve P-T Curve

('F) ('F) (ksrInchln) (ksi%ch'") (psig) (OF) (pslg) 50.0 50.0 64.13 39.98 579 60.0 519 55-0 55.0 67.38 42.13 610 65.0 550

, 60.0 60.0 70.98 44.52 645 70.0 585 65.0 65.0 74.95 47.17 683 75.0 623 70.0 70.0 79.34 50.10 725 80.0 665 75.0 75.0 8420 53.34 772 85.0 712 80.0 80.0 89.56 56.91 824 90.0 764 85.0 85.0 95.49 60.86 88f 95.0 821 90.0 90.0 102.04 65.23 945 100.0 885 95.0 95.0 109.28 70.06 1014 105.0 954 100.0 100.0 117.28 75.39 1092 110.0 1 ,032 105.0 105.0 126.12 81.29 1177 315.0 1,117 110.0 110.0 135.90 87.80 1271 120.0 1,211 115.0 115.0 146.70 95.00 1376 125.0 4,316 VYC-829 R4,Attachment 1, Page 29 of 3 5

i Table 14: P-T Evaluation - Bottom Head Level A/B (Coo1do.m)

Pressure-TemDerature Cuwe Calculation (Core Not CritiCaY cooldown = Curve B) inmts:

2.437 hch Vessel Radius, R =

CooIdown Rate, CR =

ksi'inchTl2 (for cooldown rate above}

(From App 0, Fig. 02214-1)

"F= (W)0.44 using Figs. GZ214-1& 6-2214-2 (for inside surface m*alflaw)

Temperature Adjustment =

Height of Water for a Full Vessel =

Fluid Calculated Adjusted Adjusted Temperature 114t Pressure Temperature Pressure for T Temperature Klc b P for P-T Curve P-7 Curve (OF) (OF) (ksi'inchm) [ksi*lnchv?) (psig) ("F) (psig) 50.0 50.0 64.13 26.82 388 60.0 328 55.0 55.0 67.38 28.45 412 65.0 352 60.0 60.0 70.98 30.25 438 70.0 378 65.0 65.0 74.95 32.23 467 75.0 407 70.0 70.0 79.34 34.43 499 80.0 439 75.0 75.0 84.20 36.86 534 85.0 474 80.0 80.0 89.56 39.54 573 90.0 513 85.0 85.0 . 95.49 4250 615 95.0 555 90.0 90.0 102.04 45.78 663 100.0 603 95.0 95.0 109.28 49.40 715 105.0 655 100.0 100.0 117.28 53.40 773 110.0 713 105.0 105.0 328.12 57.82 837 115.0 777 110.0 110.0 135.90 62.71 908 j20.0 848 115.0 115.0 146.70 68.11 980 125.0 926 f20.0 120.0 158.63 74.07 1073 130.0 1,013 125.0 125.0 171.83 80.67 1188 135.0 1,108 130.0 130.0 186.40 87.96 1274 140.0 1,214 135.0 135.0 200.00 94.76 1372 145.0 1,312 VYC-829 R4,Attachment 1, Page 30 of 35

Table 15 Equivalent Margin Upper Shelf Energy Summary RG1.99 Ratioof NEDU322EApp 8 Capsule Measured Predicted Measuredto Worksheet Surveillance cu Auence Decrease Decrease predicted Info.  % n/cm"2  %  % Fi, Factor (Ref. Charpy (Ref. 9) (Ref, 1 , Z ) curves)

Surveillance Plate USE 0.71% 4.5Of-tl6 8.0% 5.5% 1.447 Surveillance Weld USE 0.03% 4.50E+16 4.80% 4.78% I.005 RG1.99 Adjusted EOLlI4T Predicted -

Decreasp. NEDO-32205 NEIX)32205App 6 cu Fluence Decrease fred*M Limit Worksheet Beltline Info.  %

(Table 2-2) nlw2 vable 2-1)

%  %  % I' Limiting plate USE O.q4% 22OE3-17 9.4% 13.5% 21%

limitingWeld USE 0.04% 2.20P17 7.3% 7.4% 34%

VYC-829 R4,Attachment 1, Page 31 of 35

. I

Table 16-1 Stress Intensity Value Summary I

I '

. )

f.1 1 I r I I I I I I L

Temperature KiT I RPV Component Load Condition Location (deg F) (lcsi*sqrt*(inch)>

1 Bottom Head CD 100 F / H R CD I/4T note 1 10.49 Bottom Head HU 100 F/HR IU 314T note2 8.28 FW Blend HU-CD Injection Transient 118 T (Tfluid + 50H see Table 16-2 I

m o t e HU-CD Injection Transient 118 T (Tfluid + 50)n see Table 16-3 ~

N2 Recirc Nozzle Cf 100 F/HR CD 1/4T note I 25.07

. : .J I Note 1 For cooldown transients, temperature lag of metal verses fluid conservatively ignored.

Note For these components both inside fluid temperature and outside skin temperature are monitored. The minimum temperature is used for monitoring PT limits. Therefore HU lag does not need to be used. .

VYC-829 R4,Attachment 1, Page 32 of 35

Table 16-2 Stress Intensity Value Feedwater Nozzle BIend Temperdureand K m V&er (FWInjection (Blend) - Corner Nozzle Crad) 1 Fluid Temperature lnrt

T Temperature KIC Kit i.1. !

0 (OF) (ksi*tn&'/l) (Jai'inchYL) 50 50.0 58.52 0.00 55 52.5 59.82 1.06 60 55.0 61.19 2.12 65 57.5 62.62 3.18 70 60.0 ' 64.13 4.25 79 62.5 65.72 5.3 1 80 65.0 67.38 6.37

, 85 67.5 69.14 7.43 90 70.0 70.98 8.49 95 72.5 72.92 9.55 100 75.0 74.95 10.61 105 f 10 77.5 80.0 77.09 79.34 11.67 1274 1 1 I5 82.5 81.71 13.80 120 85.0 84.20 14.86

! 25 87.5 86.8 1 15.92 130 90.0 89.56 16.98 135 92.5 92.45 18.04 I40 95.0 95.49 19.10 145 97.5 98.68 20.17 150 100.0 102.04 2123 155 1025 105.57 22.29 160 105.0 109.28 23.35 VYC-829 R4,Attachment 1, Page 33 of 35

Table 16-3 1 Stress Intensity Value Feedwater Nozzle Bore Temperaayeand K n Values (nvInjection &re)- Corner N o d e Cra+

IaLWS: Plant =

Component =

ARTw" DF-Anafysis Basis OF step KITfot552F 50F S t e p k'h&'R

+ &%r 1025 pslg=

Fluid Temperature 1Bt T Temperature Kit 55 52.5 59.82 1.33 60 55.0 61.19 2.66 65 575 62.62 3.99 70 60.0 64.13 5.3 1 75 62.5 65.72 6.64 80 65.0 67.38 7.97 L .

85 67.5 69. I4 9.30 90 70.0 70.98 10.63 95 72.5 72.92 11.96 loo 75.0 74.95 13.29 105 715 77-09 14.61 1IO 80.0 79.34 15.94 i 15 82.5 81.71 17.27 120 85.0 84.20 18.60 I I25 87.5 86.81 19.93 130 90.0 89.56 21,26 135 92.5 92.4s 22.59 140 95.0 95.49 23.91 145 975 98.68 25.24

'-' 1 150 155 160 100.0 I025 105.0 102.04 105.57 26.57 27.90 109.28 29.23 t

VYC-829 R4,Attachment 1, Page 34 of 35

Table 17 Bounding Flange Case with No Preload Pressure-fenmeratitre Curve Calculation (Core Not Cdtkal- Bounding Flange Case no Peload)

Inu&; Plant =

Component = Upper FIangeMub lntersedion Axial Flaw vessel thkkdtness, t = inches Vessel Radius, R =

ARTNDT=

Kn+Zxk Safely Factor = (for levelA#) K twiinch

KIP for lo00 psis = ksi~nchuL k=o.D^Preload =

7'emperature P jjustment = "F ~ ~ a l =

justment = ps$ (hydrostatic pressure .t uncertainty)

Calculated Adjusted Adjusted

• Wl. .:4t Pressure Temperature Pressure For r Temperature tGc KP P for P-T Curve P-TCurve

-9

.- -32 (ksPinchM) (ksPfnchiR] Ipslg) CF) (pig) 4C 45.78 20.30 650 -5 615 47.10 20.96 672 0 637 J.0 :a.s ' 21.69 695 5 660 0.0 ?O.fB 22.50 721 10 688 j 5.0 51.96 23.39 749 15 714 10 10.0 55.93 24.38 781 20 748 15 15.0 56.11 25.47 816 25 78i 20 20.0 58.52 26.67 855 30 820 25 25.0 61.19 28.00 897 35 862 I 30 30.0 64.13 29.48 944 40 909 35 SA 67.38 3j.10 997 45 962 40 40.0 70.98 32.90 1054 50 7019 45 45.0 74.95 34.89 I118 55 I083 50 50.0 79.34 37.08 1188 60 1753 55 55.0 84.20 39.51 1268 65 1231 60 60.0 89.56 42.19 1352 70 1317 65 65.0 95.49 45.15 1447 75 1412 66 66.0 96.75 45.78 1467 76 1432 67 67.O 98.03 46.43 1488 77 l453 68 68.0 99.34 47.08 1508 78 1473 69 69.0 100.68 47.75 1530 79 ?495 70 70.0 102.04 48 -43 1552 80 1517 VYC-829 R4,Attachment 1, Page 35 of 35

Docket No.50-271 BVY03-29 ,

Attachment 3 Vermont Yankee Nuclear Power Station Proposed Technical SpecificationChange No.258 RPV Fracture Toughness and Material Stu-ve~lanceRequirements Determination of No Significant Hazards Consideration

_ I C _

BVY 03-29/ Attachment 3 1Page 1 Description of amendment request:

The Proposed Change revises the reactor pressure vessel material surveillance program as currendy specified in Technical Specifications Surveitlanoe Requirement 4.6.A. 1 and the reactor coolant system Pressure-Temperature limit curves (Technical. Specifications Figures 3.6.1, 3.6.2 and 3.6.3). In addition, conforming changes are also being made to the associated Technical SpecificationBases and the Updated Final Safety Analysis Report. The Proposed Change incorporates contemporary methodologies and industry programs for establishing material surveillance and fracture toughness requirements that have been previously found to be acceptable tu the NRC staff. The two primary components to the Proposed Change are described in the accompanying safety assessment and meet the following regulatory bases:

First, Vermont Yankee (VY) is proposing to revise the licensing basis for the Vermont Yankee Nuclear Power Station by replacing the pIant-specific reactor pressure vessel (RPV) material

. surveillance program with the Boiling W ater Reactor Vessel lntemals Project (BWRVTP) Integrated Surveillance Program (ISP), which has been approved by the NRC staff as meeting the requirements ofparagraph ULC! of Appendix H to 10 CFR 50 for an integrated surveillance program.

Second, ?Tis proposing to revise the P-Tlimit curves for the reactor coolant system in accordance with the requirements of Appendix G to IOCFRSO and an NRC-granted allowance to use the American Society of Mechanical Engineers Boiler and Pressure Vessel Cqde Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit CurvesSection XI, Division 1."

There are no plant modifications associated with these changes.

Basis for No Significant Hazards Determination:

Pursuant to 10CFR50.92, Vermont Yankee has reviewed the proposed change and concludes that the change does not involve a significant hazards consideration since the proposed change satisfies the criteria in IOCFR50.92(c). These criteria require that the operation of the faciIity in accordance with the proposed amendment WilI not: (1) involve a significant increase in the probability or consequences of m acL-Jent previously evaluated, (2) create the possibility of a new or different kind of accident r*#ynany accident previously evaluated, or (3) involve a significant reduction in a margin of safety. ?he discussion below addresses each of these criteria and demonstrates that the proposed amendment does not constitute a significant hazard.

The proposed change does not involve a significant hazards consideration because the changes would not:

1) Involve a significant increase in the probabilitv or consequences of an accident tveviously evaluated.

The proposed change implements an integrated surveillance program that has been previously evaluated and accepted by the NRC staff as meeting the requirements of paragraph m.C of I Appendix H to IOCERSO. In addition, the proposed change revises P-T limits in accordance with Appendix G to 10CFRSO (as modified by use of an accepted ASME Code Caw). Brittle hcture of the reactor pressure vessel is not a postulated or evaluated design basis accident. No I

evaluations of other postulated accidents are affected by this proposed change. Because the i . '

I I

B W 03-29 /Attachment 3 /Page 2 applicable regulatory requirements continue to be met, the change does not significantly increase the probability of any accident previously evaluated. The proposed change provides the -e assurance of RPV integrity as previously provided.

I The change wiIl require that the reactor pressure vessel and interfacing coolant system continue b be operated within their design, operational or testhg limits. Also, the change will not dter any assumptions previously made in evaluating the radiological consequencesof accidents.

1 s Therefore, this change does not involve a significant increase in the probability or consequences i of an accident previously evaluated.

2) Create the uossibilitv for a new or different kind of accident fiom anv ureviouslv evaluated_.

The proposed change does not involve a modification of the design of piant structures, systems,or components. The change will not impact the manner in which the plant is operated and will not degrade the reliability of structures, systems, or components hnportant to safety as equipment protection featuks will not be deleted or modified, equipment redundancy or independence will not be reduced, supporting system performance d l Rot be affected, and no severe testing of equipment will be imposed. NO new failure modes or mechanisms will be introduced as a result of this proposed change.

Therefore, the changes to the material surveillance program. and pressuretemperature Iimits that compose this proposed change do not create the possibility of a new or different kind of accident than those previously evaluated.

3) Involve B sirmiticantredudon in a margin of sa&.

The proposed implementation of the BWRVXP ISP has been previously evaluated generically by the NRC staff and was found to provide an acceptable alternative to plant-specific RPV material surveillance programs. The NRC staff also found that the ISP met the requirements of Appendix H to IOCFRSO for an integrated RPV material surveillanceprogram.

Appendix G to IOCFRSO describes the conditions that require pressure-temperature (P-T) limits and provides the general bases for these limits. Operating limits based on the criteria of Appendix G, as defined by appIicabIe regulations, codes, and standards, provide reasonable assurance that non-ductile or rapidly propagating failure wit1 not OCCUT. The P-T limits are not derived fiom design basis accident analyses (DBA); but, are prescribed for all plant modes to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductiIe failure of the reactor coolant pressure boundary. Calculation of P-T limits in accordance with the criteria of Appendix G to IOCFR.50 and applicable reguIatory requirementsensures that adequate margins of safety are maintained and there is no significantreduction in a margin of safety.

The proposed change does not alter the manner in which safety iiiits, limiting safety system I settings, or limiting conditions for operation are determined. There is no change or impact on any  !

safety analysis assumption or in any other parameter affectingthe course of an accident analysis supporting the Bases of any Technical: Specification. The proposed change does not involve any increase in calculated off-site dose consequences. Shce the proposed change for RPV material surveillance is in accordance with the NRC staffs safety evaluation for the ISP, and P-Tcurves were revised in accordance with the requirements of Appendix G to lOCF.R50 (as modified by

BVY 03-29 /Attachment 3 1 Page 3 use of ASME Code Case N-640),adequate safety margins are maintained without any significant reduction.

Conclusion On the basis of the above, VY bas determined that operation of the facility in accordance with the proposed change does not involve a significant hazards consideration as defrned in 10CFR50.92(c), in that it: (1) does not invotve a significant increase in the probability or consequences of an accident previously evaluated; (2) does not create the possibility of a new or different kind of accident fiom any accident previously evaluated;and (3) does not involve a significant reduction in a margin of safety.

Docket No.50-271 BVY 03-29 It t Attachment 4 vennoit YankeeNuclear Power Station Proposed Technical Specification Change No. 258 RPV Fracture Toughness and Material Surveillance Requirements Revised Updated Final Safety Analysis Report

il ___-

-2 I BVY 03-29 1 Attachment 4 I Page 1 PROPOSED CHANGE 258 PROPOSED UFSAR MARK-UP I. WNPS UFSAR. Affected Pam List Current UFSAR Section 4-23 (pages 4-2-14 and 4.2-21)

2. Marked-up Panes See attached mark-up of UFSAR pages 4.2.14 and 4-2-27 (Table 4.2.4).

Note: Deleted text is shown by strikethrough. Added text is shown by underline.

J I

fabrication and q u a l i t y control organizations and a system capable of assuring and documenting the required quality l e v e l .

The q u a l i f i c a t i o n s are backed up with Rotterdam's extensive experience in core s t r u c t u r e fabrication with such United S t a t e s p l a n t s a s W A I , 11, and 111, Peach Bottom 11 and 1x1, KOntiCello, and Vermont Yankee. Also, Rotterdam f a b r i c a t e d parts of Quad Cities I1 r e a c t o r pressure vessels, a s well as complete v e s s e l s for f o r e i g n p l a n t s , such as AKM and Nuclenor.

The Reactor Coolant System was cleaned and flushed before fuel was loaded i n i t i a l l y . During the preoperational t e s t program, the r e a c t o r vessel and Reactor Coolant System were given a hydrostatic test i n accordance with code requirements a t 125% of design pressure. The vessel temperature i s maintained at a minimum of 6 0 a P above the NDZ temperature prior to pressurizing t h e vessel f o r h y d r o s t a t i c t e s t . A system leakage t e s t at a pressure n o t to exceed system operating pressure is made following each removal and replacement of t h e reactor vessel head. Other preoperational tests include c a l i b r a t i n g and t e s t i n g t h e r e a c t o r vessel flange seal-ring leakage detection instrumentation, adjusting r e a c t o r v e s s e l s t a b i l i z e r s , checking a l l vesael thermocouples, b d checking the operation of the vessel f l a n g e s t u d tensioner.

The r e a c t o r v e s s e l temperatures are monitored during vessel heatup and cooldown t o assure that thermal stress on the reactor v e s s e l is not excessive during s t a r t u p and shutdown.

4.2.6 Inspection and Testing The p l a n t has been designed t o prevent occurrence of a gross d e f e c t . The inservice inspection program has been designed t o provide or t h e inspection during s e r v i c e of those components and systems whose s t r u c t u r a l i n t e g r i t y must be maintained for coatinued safe operation of the p l a n t . The s e l e c t i o n of components and inspection locations is based on t h e AsMe Code, S e c t i o n XI.

and 10CFR50.55 (a] The program i s presented i n Reference 2 .

Vermont Yankee is a partfcipant in t h e Boilins Water Reactor V e s s e l and I n t e r n a l s Project (BWRVXPI Intesrated Surveillance Program ( ISP) for t h e purpose of monitoring chancres in the f r a c t u r e toughness p r o p e r t i e s of f e r r i t i c materials i n the reactor v e s s e l b e l t l i n e reqion due t o exposure of these materials to neutron i r r a d i a t i o n . The Nuclear Regulatory Commission staff has determined t h a t t h e BWRVIP ISP is an acceptable a l t e r n a t i v e t o p l a n t - s p e c i f i c material. s u r v e i l l a n c e programs for t h e ~ u rose p of maintaining compl lance with the requirements of Appendix H t o 1 0 C F R S 0 , "Reactor Vessel Material Surveillance Proqram Requirements. " Under the ISP, dosimetry data and the r e s u l t s of fracture touqhness t e s t s from surveillance capsules i n h o s t BWRs a r e shared with comparable BWRs. As required by Appendix H to 10CFR50, VY will evaluate changes i n t h e p r o p e r t i e s of representative materials f o r the purpose of deterrnininq whether chanqes are necessary i n pressure and temperature limits and operating procedures. The rbport, "BWRVIP-86-A: BWR Vessel and I n t e r n a l s Project Updated BWR Xntesrated Surveillance Proqram WNPS UFSAR Revision && [

x 4.2-14 of 21

(ISP) Xmulementation Plan, ' I establishes t h e requlatoi-y basis for t h e surveillance program.

The Vermont Yankee Nuclear Power Station iS not a host I S P p l a n t for providinq surveillance capsules; however, the remaininq two WNPS material surveillance capsules w i l l continue t o reside in the reactor in case they are needed in the future as a contingency. The VYNPS surveillance capsules-Psegxzm consist of tensile and Charpy V - N o t c h specimens representative of the three areas of i n t e r e s t : reactor vessel base metal, weld Heat-Affected Zone (mz)metal, and weld metal f r o m a reactor steel j o i n t which simulates a welded joint i n the reactor vessel. The specimens were placed in three separate surveil1 awe- ' capsules 9 I radially located adjacent to t h e inner vessel wall,

-a t core mid-plane,where the neutron flux U highest. The specimen types contained i n the capsules are l i s t e d in Table is 4.2.4. In addition t o the specimens l i s t e d i n Table 4 . 2 . 4 , sufficient specimens are provided for obtaining nnirradlated base line data and f o r r e t e n t i o n a s archive material.

vy's neutron fluence calculations (and future re-evaluations) that support reactor coolant' system pressure-temperature l i m i t s and the ZSP are based on a fluence methodoloqy that is acceptable t o the NRC s t a f f , consistent with the guidance in NRC Remlatow Guide 1.19 0 , "Calculational Methods or Determininq Pressure Vessel Neutron Fluence, '

I

VYNPS BASES: 3.6 and 4.6 (Cont'd)

A Note is included in Figure 3.6.2 that specifies test instrumentation uncertainty must be +/- 2'F and the flange region temperatures must be maintained greater than or equal to 72% when using such instrumentation in lieu of permanently installed instrumentation.

Qualified test instrumentation may only be used for the purpose of maintaining the temperature limit when the vessel is vented and the fluid level is below the flange region. If permanently installed instrumentation ( w i t h a 10OF uncertainty) is used during head tensioning and detensioning operations, the 8 0 % limit must be met.

In order to prevent undue stress on the vessel nozzles and bottom head region, the recirculation loop temperatures w i l l be maintained w i t h i n SO'?? of each other p r i o r to startup of an idle loop.

Vermont Yankee is a participant in the Boiling Water Reactor Vessel arid Intemals Project Integrated Surveillance Program ( I s P ) for monitoring IJ changes in the fracture toughness properties of ferritic materials in the reactor pressure vessel (RPV) beltline region. (See UFSAR Section 4 . 2 for additional ISP details.) As ISP capsule test reports become availqble for RPV materials representative of VYNPS, the actual shift in the reference temperature for nil-ductility transition (RT-) of the vessel material may be re-eqtablished. In accordance with Appendix H to 10CFR50, W is required to review relevant test reports and make a determination of whether or not a change in Technical Specifications is required as a result of the surveillance data.

B. Coolant Chemistry A steady-state radioiodine concentration limit of 1.1 pCi of 1-131 dose equivalent per gram of water in the Reactor coolant System can be reached if the gross radioactivity in the gaseous effluents is near the limit, as set f o r t h in the Offsite Dose Calculation Manual, or if there is a failure or prolonged shutdown of the cleanup demineralizer. In the event of a s t e a m line rupture outside the drywell, the NRC staff calculations show the resultant: radiological dose at the site boundary to be less than 30 Rem to the thyroid. This dose was calculated on the basis of the radioiodine concentration limit of 1.1 pCi of 1-131 dose equivalent per gram of water, atmospheric diffusion from an equivalent elevated release of 10 meters at the nearest site boundary (190 m) for a X/Q = 3.9 x sec/m3 (Pasquill D and 0.33 m/sec equivalent), and a steam line isolation valve closure time of five seconds with a

'1 steam/water mass release of 30,000 pounds.

The iodine spike limit of four ( 4 ) microcuries of 1-131 dose equivalent per gram of water provides an iodine peak or spike limit for the reactor coolant concentration to assure that the radiological consequences of a postulated LOCA are within 10CFR Part 100 dose guidelines.

The reactor coolant sample will be used to assure that the limit of Specification 3.6.B.1 is not exceeded. The radioiodine concentration would not be expected to change rapidly during steady-state operation over a period of 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. In addition, the trend of the radioactive gaseous effluents, which is continuously monitored, is a good indicator of the trend of the radioiodine concentration in the reactor coolant.

When a significant increase in radioactive gaseous effluents is indicated, as specified, an additional reactor coolant sample shall be taken and analyzed for radioactive iodine.

Amendment No. 33, G 3 , 41, 93, &6+, - 2 140

VYNPS BASES: 3.6 and 4 . 6 (Cont'd)

Due t o convection cooling, stratification, and cool CRD flow, the bottom head area is subject to lower temperatures than the balance of the pressure vessel. The R T m of t h e lower head is lower than the ARTNm used for the beltline. The lower head area is also not s u b j e c t to the same high level of stress as the flange and feedwater nozzle regions. The dashed Bottom Head Curve is less restrictive than the enveloping curve used f o r the upper regions of the vessel and provides Operator's with a conservative, but less restrictive P/T limit or the cooler bottom head region.

The solid line is the Upper Region Curve. This line conservatively bounds all regions of the vessel including the most limiting beltline and flange areas. At temperatures below the 10CFRS0 Appendix G minimum temperature requirement (vertical line) based on the downcomer temperature and flange temperature, the reactor pressure shall be maintained below the solid line. At temperatures in' excess o f the 10CE'RSO Appendix G minimum temperature requirement, the allowable pressure based on the flange is much higher than the beltline limit.

Therefore, when the flange temperature exceeds the 10CFRSO Appendix G minimum temperature requirement, the reactor pressure shall be maintained below the solid line based on downcomer temperature.

1 The Pressure T e s t curve (3.6.11 is applicable for heatuplcooldown rates up to 40QF/hr. The Core N o t Critical curve (3.6.2) ,and the Core Critical curve (3.6.3) are applicable for heatup/cooldown rates up to 100°F/hr. In addition to heatup and cooldown events, the more limiting anticipated operational occurrences (AOOs) were evaluated (Structural Integrity Report, SIR-00-155). For the feedwater nozzles, a sudden injection of 50'F cold water into the nozzle was postulated in the development of all three curves. The bottom head region was independently evaluated for AOOs in addition to 40°F/hr and 100°F/hr heatup/cooldown rates. This evaluation demonstrated that P/T requirements of the bottom head would be maintained for transients that would bound rapid cooling as well as step increases i n temperature.

The rapid cooling event would bound scrams and other upset condition (level B) cold water injection events. The bottom head was also evaluated for a series of step heatup transients. This would depict hot sweep transients typically associated with reinitiation of recirculation flow with stratified conditions in the lower plenum.

This demonstrated that there was significant margin to P/T limits with GE SIL 2 5 1 recornendations for reinitiating recirculation flow in stratified conditions.

Adjustments for temperature and pressure instrument uncertainty have been included in the P/T curves [Figures 3.6.'1, 3.6.2 and 3.6.3). The rnir&mm temperature requirements were all increased by 10eF to compensate or temperature loop uncertainty error. The maximum pressure values wexe all decreased by 3Opsi to account f o r pressure i 1

loop uncertainty error. In addition, the maximum pressure was reduced further to account for static elevation head assuming the level was at the top of the reactor and at 7OoF.

Specification 3.6.A.3 requires that the temperature of the vessel head lange and the head be greater than 70eF before tensioning. The 70°F is an analytical limit and does not include instrumentation uncertainty, which must be procedurally included depending upon which temperature monitoring instrumentation is being used. The temperature values shown on Figures 3.6.1, 3.6.2 and 3.6.3 include a 10aF instrumentation uncertainty.

Amendnent No. 2-83 139 ~

VYNPS BASES :

3.6 and 4.6 REACTOR COOLANT SYSTEM A. Pressure and Temperature Limitations All components fn the Reactor Coolant System are designed to withstand the effects of cyclic loads due to system temperature and pressure changes. These cyclic loads are introduced by normal load transients, reactor trips, and startup and shutdown operations. The various categories of load cycles used for design purposes are provided in Section 4.2 of the F S M . During startup and shutdown, the rates of temperature and pressure changes are limited so that the maximum specified heatup and cooldown rates are consistent with the design assumptions and satisfy the stress limits for cyclic operation.

The Pressure/Temperature (P/T) curves included as Figures 3.6.1, 3.6.2, and 3.6.3 were developed using 10CFRSO Appendix G , 1995 ASME Code,Section XI, Appendix G (including the Summer 1996 Addenda), and ASME Code Case N-640. These three curves provide P/T limit requirements for Pressure Test, Core Not Critical, and Core Critical. The P/T curves are ?ot derived from Design Basis Accident analysis. They are prescribed to avoid encountering pressure, temperature or temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the reactor pressure boundary, a condition that is unanalyzed.

During heating events, the thermal gradients in the reactor vessel wall produce thermal stresses that vary from compressive at the inner wall to tensile at the outer wall. During cooling events the thermal stresses vary from tensile at the inner wall to compressive at the outer wall, The thermally induced tensile stresses are additive to the pressure induced tensile stresses. In the flange region, bolt preload has a significant affect on stress in the flange and adjacent plates.

Therefore heating/cooling events and bolt preload are used in the determination of the pressure-temperature limitations for the vessel.

The guidance of Branch Technical Position - MTEB 5 - 2 , material drop weight, and Charpy impact test results were used to determine a reference nil-ductility temperature ( R T N ~ Ifor all pressure boundary components. For the pl-ates and welds adjacent to the core, fast neutron (E > I MeV) irradiation will cause an increase in the RTm.

For these p l a t e s and welds an adjusted RTm (ARTm) of 89'F and 73°F

(*1 and sl thickness locations) was conservatively used in development of these curves f o r core region components. Based upon plate and weld chemistry, initial RTm values, predicted peak fast neutron fluence (2.99 x IO1' n / a 2 at the reactor vessel inside surface) for a gross power generation of 4 . 4 6 x 10' MWH (t), these core region ARTm values conservatively bound the guidance of Regulatory Guide 1.99, Revision 2.

There were f i v e regions of the reactor pressure vessel {RPV) that were evaluated in the development of the P/T Limit curves: (1) the reactor vessel beltline region, (2) the bottom head region, ( 3 ) the feedwater nozzle, ( 4 ) the recirculation inlet nozzle, and ( 5 ) the upper vessel flange region. These regions will bound all other regions in the vessel with respect to considerations f o r brittle fracture.

Two lines are shown on each PJT limit figure. The dashed l i n e is the Bottom Head Curve. This is applicable to the bottom head area only and includes the bottom head knuckle plates and dollar plates. Based on bottom head fluid temperature and bottom head surface temperature, the reactor pressure shall be maintained below the dashed line at all times.

Amendment No. 33, 6% 4% 43, 9Q, m 8 %6,  ?AS 138

VYNPS FIGURE 3.6.3 Reactor Vessel Pressure-Temperature Urnitations Normal Opedon, Care Crkical 1DaFhr HeatuplCooldown Llmit If Pressure c 253 pslg, Water Level must be within Normal Range for Power operation Valid Through 4.46E8 AIwH(t) 2!3 253 432 407 413 439 I .,,..-

474 513 555 03 656 713 m

848 926 1013 1108 1214 1214 1312 60.00 80.00 100.00 120.00 140.00 t60.00 180.00 m.00 TEMPERANRE PF) 137 Amendment No. 33, 93, 203

VYNPS FIGURE 3.6.2 Amendment No. 33, 93, % 136

VYNPS F i g u r e 3.6.1 Reactor Vessel Pressure-Temperature Umttatlons Hydmstatlc Pressure and Leak Tests, Core Not CrfUcd 4O'Flhr HeatuplCooldown limit Vaild Through 4.46E8 MWH(t)

I.

135

3.6 LIMITING CONDITIONS FOR 4.6 SURVEILLANCE REQUIREMENTS OPERAT ION I1

3. Coolant Chemistry B. Coolant Chemistry

1. a. During r e a c t o r power 1. a. A sample of r e a c t o r operation, t h e coolant s h a l l be radioiodine taken a t least every c o n c e n t r a t i o n i n the 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> and r e a c t o r coolant analyzed f o r s h a l l not exceed radioactive iodines 1.1 microcuries of of 1-131 through i 1-131 dose 1-135 d u r i n g power L . .L e q u i v a l e n t per gram operation. In of water, except as a d d i t i o n , when steam allowed i n j e t a i r ej e c t o r

'1

_._ i Specification monitors i n d i c a t e an 3.6.B.l.b. increase i n r a d i o a c t i v e gaseous effluents of 25 p e r c e n t o r 5000 p C i / s e c ,

whichever i s greater, during steady state reactor operation a reactor c o o l a n t sample shall be taken and analyzed f o r radioactive iodines .

Amendment No. 33, 41, 283 116

~. .-___

BVY 03-29I Attachment 6 / Page 1 Listing of Affected Technical SpecificationsPages Replace the Vermont Yankee Nuclear Power Station Technical Specificationspages listed below with the revised pages included herein. The revised pages contain vertical lines in the margin indicating the areas of change.

Remove 116 Insert 116 I ..hi.

135 135

, 136 136 137 137 138 138 139 139 140 140 i

Docket No.50-271 B W 03-29

, I .

Attachment 6 I  ? Vermont Yankee Nuclear Power Station I .

Proposed Technical Specification Change No. 258 I . RPV Fracture Toughness and Materid Surveillance Requirements Retyped Technical SpecificationPages

I

8 WNPS BASES: 3.6 and 4.6 (Cont'd)

I material irr veillance s wall of the el in the c es and vess he next sur region, the recirculation loop temperatures will be maintained within S O O F of each other prior to startup of an i d l e loop.

vessel ion surveil1 B. Coolant Chemistry - . . - .

I A steady-state radioi-odine concentration limit of 1.1 pCi of. 1-131 dose

-. equivalent per gram-of-waterin the Reactor'Coolant System can be reached if the gross radioactivity in the gaseous efiluents is near t h e

,. limit, as set forth in the Offsite Dose Calculation Manual, or if there .. I is a failure or prqlonged shucdoe of the cleanup demineralizer. In I the event of a s t e m l i n e rupture outside the drywell, the NRC staff.

I ca-lcukations show the resultan!'radfological dose at the site'bbundary.

to be less than 30 Rem to the thyroid. This dose was calculated OR the basis of the radioiodine Concentration limit of 1.1 pCi of 1-131 dose equivalent per gram of water, atmospheric diffusion from an equivalent elevated release of 10 meters at the nearest site boundary (190 m) for a X/Q = 3.9 x loe3 sec/m3 (Pasquill D and 0.33 m/sec equivalent), and a steam line isolation valve closure time of f i v e seconds with a i

stearn/water mass release of 30,000 pounds.

The iodine s p i k e limit O f four ( 4 ) microcuries of 1-131 dose equivalent per gram o f water provides an iodine peak or spike limit for the reactor coolant concentration to assure that the radiological consequences of a postulated LOCA are within lOCE'R Part 100 dose guidelines.

i The reactor,coolant sample will be used to assure that the limit of 1 Specification 3 . 6 . B . 1 is not exceeded. The radioiodine concentration would not be expected t o change rapidly during steady-state operation over'a period o f 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. In addition', the trend of the radioactive I gaseous effluents, which is continuously monitored, i~ a good indicator of the trend of the,radioiodine concentration in the reactor coolant.

When a significant increase in radioactive gaseous effluents is indicated, as.specified, an additional reactor coolant sample shall be taken and analyzed for radioactive iodine.

140

BASES: 3.6 and 4.6 (Cont'd)

Two lines are shown on each P/T limit figure. The dashed line is the Bottom Head Curve. This 5s applicable to the bottom head area only a n d .

includes the bottom head knuckle plates and dollar plates. Based on bottom head fluid temperature and bottom head surface temperature, the reactor pressure s h a l l be maintained below the dashed line at all times .

Due to convection cooling, stratification, and cool CRD flow, the bottom head area is subject to lower temperatures than the balance of the pressure vessel. The R T m of the lower head.is lower than the ARTw used for the beltline. The lower head area is also not subject to the same high level of stress as the flange and feedwater nozzle i regions. The dashed Bottom Head Curve is less restrictive than the enveloping curve used for the upper regions o f the vessel and provides Operator's with a conservative, but less restrictive PJT limit f o r the il cooler bottom head region.

The,solid line is the Upper Region Curve. This line conservatively i .t boujlds all regions of the vessel including the most limiting beltline and flange areas. A t temperatures below the 10CFRS0 Appendix G minimum temperature requirement {vertical line) based on the downcomer temperature and flange temperature, the reactor pressure shall be .

I' maintained below the solid line. At temperatures in excess of the lOCF'RS0 Appendix G minimum temperature requirement, the allowable pressure based on the flange is much higher than the beltline limit.

1 i

.- Therefore, when the -flange temperature exceeds the 10CFR50 Appendix G minimum temperatme requiremezit, the reactor pressure shall be 4: maintained below the solid-line based on downcorner temperature.

I The Pressure Test carve (3.6.1) is applicable for -heatup/cookdown rates u i to 40°F/hr. The Core NGt Crilhac-curve (3.6.2) and the Core - -

Critical curve ( 3 . 6 . 3 ) are applicabie .for heatup/cooldown rates up to 100aF/hr. In addition to-beatup and cooldown events, the inore limiting anticipated operational occurrences {AOOs] were evaluated (Structural Integrity Report, SIR-00-155). For the feedwater nozzles, a sudden I

injection of 50°F cold water into the nozzle was postulated in the 1 ' development of all three curves. The bottom head region was independently evaluated for AOOs in addition to 40°F/hr and 100aF/hr heatup/cooldown rates. This evaluation demonstrated that P/T requirements of the bottom head would be maintained for transients that would bound rapid cooling as well as step increases in temperature.

The rapid cooling event would bound scrams and other upset condition

! {level BI cold water injection events. The bottom head was also evaluated or a series of step heatup transients. T h i s would depict hot sweep transients typically associated with reinitiation of recirculation flow with stratified conditions in the lower plenum.

This demonstrated that: there was significant margin to P/T limits with GE SIL 251 recommendations for reinitiating recirculation f l o w in stratified conditions.

t . b . f ,3 . G . a w b 3-4-3D Adjustments or been included in all increased by IOOFto compensate for temperature loop uncertainty error. The maximum pressure values were all decreased by 3Opsi to account for pressure loop uncertainty error. In addition, the maximum pressure was reduced further to account or static elevation head assuming the level was at the top of the reactor and at 70°F.

Amendment No. 203 139

VYNPS BASES :

3.6 and 4.6 REACTOR COOLANT SYSTEM A. Pressure and Temperature Limitations All components in the Reactor Coolant System are designed to withstand the effects of cyclic loads due to system temperature and pressure changes. These cyclic loads are introduced by normal load transients, reactor trips, and startup and shutdown operations. The various categories o f load cycles used for design purposes are provided in Section 4.2 of the FSAR. During startup and shutdown, the rates of I temperature and pressure changes are limited so that the maximum specified heatup and.cooldown rates are consistent with the design assumptions and satisfy the stress limits for cyclic operation.

The Pressure/Temperature (P/T) curves included as Figures 3.6.1, 3.6.2, and 3.6.3 were developed using 10CFR50 Appendix G, 1995 ASME Code,Section XI, Appendix G (including the Summer 1996 Addenda), and ASME Code,Case N-640. These three curves provide P/T limit requirements for Pressure Test, Core N o t Critical, and Core Critical. The P/T curves are not derfved from Design Basis Accident analysis. They are prescribed to-avoid encountering pressure, temperature or temperature rate of change.conditions that might cause undetected flaws to propagate and cause nonductile failure of the reactor pressure boundary, a con&tion t h a t is unanalyzed. ..

During heating events, the thermal gradients in the reactor vessel wall produce thermal stresses that vary from compressive at the inner wall to tensile at the outer wall. W r i n g cooling events the thermal stresses vary from tensile at the inner wall to compressive at the 0ute.r wall. The thermally induced tensile stresses are additive t o the

-- -pressure induced tensile stresses. In the flange region; bolt-preload has a significant affect on stress in the flange and adjacent p l a t e s .

Therefore heating/cooling events and bolt preload are used in the determination of the pressure-temperature limitations for the vessel.

The guidance of Branch Technical Position - MTEB 5-2, material drop weight, and Charpy impact test results were used to determine a reference nil-ductility temperature (RTNm) for all pressure boundary components. For the plates and welds adjacent to the core, fast neutron (E > 1 MeV) irradiation will cause an increase in the RTNm.

For these plates and welds an adjusted RTm (AFtTm) of 89°F and 73F (h and Jr thickness locations) ere were five regions of the reactor pressure vessel (RPV) that were evaluated in the development of the P/T Limit curves: (1) the reactor vessel beltline region, (2) the bottom head region, (3) the feedwater nozzle, ( 4 ) the recirculation inlet n o ~ ~ l eand

, (5) the upper vessel flange region. These regions will bound all other regions in the vessel with respect to considerations f o r brittle fracture.

c Amendment No. 33, #; W,. 93, 94, 3=?0, 44-6, 203 138

VYNPS FIGURE 3.6.2 ReaetorVes5el PreSsum-Ternperaturetfmitlatlons Normal Operalion, Core Not Ctftical y:p-;m 1

-I-4 1

1 1

- 1 1

4. -I-1 1

- - +-

I I

1 l

I I

l I. -I- 4 I

1 1

I

-1 1 I 1-1-1

- .. -eI 4- 4 I

- I- -

I I t I i 1

4 1-1-1 l

- + --c I

1 I

1 1-1

-11 C

Temperature Head Regions I;!

80 439 85 90 95 474 513 555 i"Ei 253 I

100 603 253' '

105 656 253 110 713 253

'215 777 I1 120 848 i I25 926 253 "I

130 1013 253 I35 1108 253

• 140 1214 253 ,I

,140 1214

. 145 1312 150 - 1Q24 155 160 - 1103 165 1190 7.1 170 1

1 1 ' 1 I

- I 1 I 1258 I I 1I 47

? I l l I I I I 1 1 1 1 I 1 F 100 120 140 160 180 200 m-0 During tensioning and detensbning operations with the vessel vented and the level below the flange region, the Range temperature may be' monitored with test instrumentation in lieu of pracesS instrumentationfor the downcomer region fluid temperature and permanent flange region outside surface temperature. The test instrumentation uncertainty must be less than +/- 2°F. The flange region temperatures must be maintained greater than or equal to 72°F when monitored with test instrumentation during tensioning, detensbning, and.when tensioned.

Amendment No. 33., 93, 203 1 3 P

i Amendment No. 33, #, e,43, w , 203 135

VYNPS 3.6 LIMITING CONDITIONS FOR OPERAT ION cordance with t h following schedul :

\ / CAPSULE

&R YEAR E. Coolant Chemistry B. Coolant Chemistry

1. a. During r e a c t o r power 1. a. A sample of r e a c t o r operation, the ' coolant s h a l l be radioiodine taken a t l e a s t every concentration i n t h e 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> and r e a c t o r coolant analyzed for s h a l l not exceed r a d i o a c t i v e iodines 1.1 microcuries of of 1-131 thxough 1-131 dose 1-135 during power equivalent p e r gram operation. I n '

of water, except a s a d d i t i o n , when steam allowed i n jet air ejector Specification monitors i n d i c a t e an 3.6.B. 1.b. increase i n r a d i o a c t i v e gaseous effluents of 25 percent o r 5000 pCi/sec, whichever i s

' g r e a t e r , during steady s t a t e reactor operation a r e a c t o r coolant sample s h a l l be taken and analyzed f o r radioactive iodines .

Amendment No. 33, S, 203 116

I BVY 03-291Attachment 5 f Page 2

6. Delete the first paragraph on current page 140 - Bases to 3.6.A and 4.6.A.

7. Delete the current, last paragraph of Bases 3.6.A and 4.6.A (on current page 140), and replace it with the following:

Vemont Yankee is a participant in the Soiling Water Reactor Vessel and lntemals Project Integrated Surveillance Program (ISP) for monitmng changes in the fracture I

toughness propertlesof ferritic materials h the reactor pressure vesel [Rf v) beltline region. (See UFSAR Section 4.2 for additional IS? details..) As ISP capsule test reports become available forRPV materiais representative of VYNPS* the actual shfi h the reference temperatun? for n&ductility transition (RTNDT) of the vessel material may be re-I r..J established. In nee with Appendix H to fOCFR50, W i s Equimd to muj..w relevafif tezt repods and make a determination of whether or not a change in Technical Specit7caiYGi:sis required as a result of the surveillm

B W 03-29/ Attachment 5 f Page 1 Descridon of Technical SDecification Chanaes I. Delete TS SR 4.6.A.5on current page 116 in its entirety.

2. Modify TS Figures 3.6.1, 3.6.2 and 3.6.3 (current pages 135-137) as follows:

0 The validity of each figure is changed fromthe 'end of cycle 23"to "4.46 E8 MWH(t)."

For each figure, the grid line divisions are changed, additional 100 psi increments are added to the ordinate axis, and more data are used to plot the curves.

A Note is added to Figure 3.6.2 for the use of test instrumentation during tensioning and detensioning operations with the vessel vented and fluid level below the flange region. I Corrkctions are made to the tabulation of pressure and temperature values in Figure 3.6.3. I:

3. -

Replace the last sentence of the 4* paragraph on current page 138 Bases to 3.6.A and 4.6.A - with the following:

Based upon plate and weld chernjstty, initial RTNDTvalues, predicted peak fast neutron fluence (2.99 x IOf7d c d at the reactor vessel inside surface) for a gross power generation of 4.46 x I@ MW(t), these core region ARTNOTvalues conservatively bound the guidance of Regulatory Guide f. 99, Revision 2. D I

4. Add amplifying clarification to the first sentence of the last paragraph on current page 139 Bases 3.6.A and 4.6.A.

t

5. - -

After the last paragraph on current page 139 Bases 3.6.A and 4.6.A insert the following two paragraphs:

Specification 3.6.A.3 requires that the temperature of the vessel head flange and the head be greater than 70°F before tensioning. The 70°F is an analjdical limit and does I not include instrumentation uncertainty, which must be procedurally included depending I upon which temperature monitoring insfturnentationis being used. The temperature values shown on Figures 3.6. I, 3.6.2and 3.6.3include a 70°F insbumentation I '

uncertainty. I A Note is included in Figure 3.6.2 that specifies test instrumentation uncertainty must be

+/- 2°F and the flange region temperatures must be maintained greater than or equal to 72O F when using such insfrumentation in lieu of permanently installed instrumentation.

Qualified test instrumentation may only be used for the purpose of maintaining the I

temperature limit when the vessel is vented and the nuid level is below the flange region, if permanently installed instrumentation (with a 70°F uncerfainiy) is used during head tensioning and detensioning operations, the 80°F limit must be met.

Docket No.50-271 BVY 03-29 '

i Attachment 5 Vermont Yankee Nuclear Power Station I

Proposed Technical Specification Change No.258 1

RPV Fracture Toughness and Materid Surveillance ReqUirernents I

i .

Marked-up Version of the Current Technical Specifications

TABLE 4 . 2 . 4 SURW3ILLANCP CAPSULE RMOVAL SCHEDULE Capsule Specimen Number of Specimens Vessel Withdrawal kxwsba Type= Azimuth Schedule (2)

No. Location lYlCr-Base Weld HA2 C.t 12 12 12 3O0 10 years (3)

T-t 2 2 2

-3-=

C 8 8 8 2200 Standby T 2 2 2 C 8 8 8 300O Standby T 2 2 2 C E standard Charpy V-Notch impact specimen T = t e n s i l e specimen Specified capsules will be withdrawn durinp the refueling outaqe following the year specified, referenced to the date of commercial operation.

Capsule No. 1 was removed from the v e s s e l for analysis in March

-1983.

VERMONT YANKEE NUCLEAR POWER STATION it PROGRAM PROCEDURE til PP 7027 RlEVISION 3 REACTOR VESSEL INTERNALS MANAGEMENT PROGRAM i

! I USE CLASSIFICATION: INFORMATION i .E RESPONSIBLE PROCEDURE OWNER: Manager, System Engineering REQUIRED REVIEWS Yes/No E-Plan 10CFR50.54(q) No Security 10CFR50.54(p) No Probable Risk Analvsis (PRA) No I I 1 LPC Effective Affected Pages M No. Date I

I I I

1 Implementation Statement: N/A

~ ~~

I I Effective Date: 12/02/04 PP 7027 Rev. 3 Page 1 of 20

~ _ -4 _ ~

I- ~

TABLE OF CONTENTS 1.0 PURPOSE, SCOPE, AND DISCUSSION ................................................................................... 3 2.0 DEFINITIONS ............................................................................................................................... 5 3.0 PRIMARY RESPONSIBILITIES................................................................................................ 5 4.0 PROCEDURE .............................................................................................................................. 11 5 .O REFERENCES AND COMMITMENTS .................................................................................. 15 6.0 FINAL CONDITIONS ................................................................................................................ 19 7.0 ATTACHMENTS ........................................................................................................................ 19 8.0 QA REQUIREMENTS CROSS RlWERENCE........................................................................ 20 I

PP 7027 Rev. 3 Page 2 of 20

1.0 PURPOSE, SCOPE, AND DISCUSSION 1.1. Purpose The purpose of the Vermont Yankee Reactor Vessel Internals Management Program Procedure is to identify all Reactor vessel internals required to be inspected and outline their inspection requirements. This program also provides direction for evaluation of flaws and repair of Reactor internal components. In addition, it provides guidance for control of Reactor water chemistry and mitigation of Intergranular Stress Corrosion Cracking (IGSCC). This program describes how Vermont Yankee complies with 10CFR 50 Appendix ByASME Section XI, and Boiling Water Reactor Vessel and Internals Program (BWRVIP) guidance with regard to reactor vessel internals inspection and program management.

This program procedure includes e f the Reactor vessel i e Methods acceptable for inspection e Required frequency of inspection e Planned schedule for inspection e Basis for inspection requirements e

e e

e In accordance with AP 6002, Preparing 50.59 Eval of an Applicability Determination (AD) has determined that an AD is not required for future changes provided the procedure scope is not changed. The basis for this conclusion is that this document provides directions for implementing a maintenance or administrative process, subject to 10CFRSO Appendix B, that does not alter the design, performance requirements, operation, or control of systems, structures, or components (SSCs).

1.2. Scope The Vermont Yankee Reactor Vessel Internals Management Program includes all of the Reactor vessel internals, with the exception of components that are considered consumable, such as the fuel bundles, control rods, and incore instruments. This program also includes the vessel shell cladding, but does not include any of the Reactor vessel'pressure boundary. The Reactor vessel pressure boundary shell, heads, nozzles, flange and RPV flange bolting are governed by the Vermont Yankee Inservice Inspection (TSI)Program, PP 7015.

There is one exception to the above statement. The BWRVIP augments the IS1 Program for one weld that is outside the Reactor vessel. This is weld N10-SE, the Standby Liquid Control safe-end-to-vessel nozzle connection. The requirements for this weld are discussed in Appendix A.

PP 7027 Rev. 3 Page 3 of 20

L - .

1.3. Discussion This program addresses the requirements of ASME Section XI, Table IWB-2500-1, Categories B-N-1 and B-N-2. It also meets the requirements of various B W R W documents, as Vermont Yankee has committed to do so. It also addresses additional other commitments to the NRC and I '

internal commitments, such as to address GE SILs. Finally, certain internals components and subcomponents have been determined to be significant as a risk to generation, and inspection recommendations have been assigned for these, as well.

Appendix A lists for each of the Reactor vessel internal components: method of inspection; frequency of inspection; and the planned schedule for inspection.

The inspection frequencies in Appendix A are based on an 18-month cycle. If cycle length is changed, Appendix A must be revised accordingly. In addition, when Vermont Yankee incorporates hydrogen water chemistry and if the NRC accepts BWRVIP-62, Technical Basis for Inspection Relief for BWR Internal Components with Hydrogen Injection, inspection frequencies for various internals components may be reduced.

Background

Vermont Yankee is a General Electric designed boiIing water Reactor (BWR) power plant built in accordance with the ANSI B31.1 Construction Code. Vermont Yankee is sometimes described as a BWR 3/4 pIant, however the more accurate designation is a BWR 4 with BWR 3 jet pumps and steam dryer. The Reactor vessel and shroud support were fabricated onsite by Chicago Bridge and Iron. The shroud and lower core spray piping was fabricated by Rotterdam Drydock in the Netherlands. The intemals were installed on-site by Installation and Services I Engineering for General Electric. i Until 1994, inspections of the Reactor vessel internals have been driven by the few required ASME Section XI inspections, NRC mandates, and the recommendations of GE Services Information Letters. In recent years Reactor vessel internals have received much attention because of intergranular stress corrosion cracking (IGSCC) that has been discovered at a significant number of BWRs. The BWR Vessel and Internals Project (BWRVIP) was formed in 1994 at the direction of the BWR Owners' Group to address this issue.

The BWRVIP identifies safety related internals components and their likely failure modes, specifies inspection methods and frequencies, and provides the methodology for evaluating flaws. It also specifies acceptable methods for demonstrating nondestructive examination (NDE) techniques and for determining technique uncertainty. It specifies requirements for repair or replacement of Reactor internals. FinaIly, it also addresses various methods of chemical control to mitigate potential future cracking. Every utility identifies members to represent the various BWRVIP disciplines. Each utility has also identified an executive for membership in the Executive Committee that controls funding and overall direction of the BWRVTP.

ENN-DC- 135, BWRVlP Inspection Program, provides guidance and requirements for managing and implementing the BWRWP program.

PP 7027 Rev. 3 Page 4 of 20

2.0 DEFINITIONS 2.1. None 3.0 PIUMARY RESPONSIBILITIES 3.1. Program Owner (WO):

3.1.1. Is responsible for the maintenance and coordination of the Vermont Yankee Reactor Vessel Internals Management Program. Is responsible for meeting the expectations of the program Owner, as described in Appendix A of AP 0098.

3.1.2. Prepares and maintains the inspection aspects of this program.

3.1.3. Reviews NRC Generic Letters, Information Notices, or regulations; BWRVP documents; 1' I and General Electric SlLs or RICSILs as they are issued for applicability to the Reactor Vessel Internals Management Program and documents this review per paragraph 4.1.4.

3.1.4. Ensures that technical justification are pre if an exception is t 3.1.5. Prepares the inspection plan for each refueling outage in accordance with this program.

3.1.6. Assists the VY Site Reactor Internals Coordinator with selection of examination vendor and personnel.

3.1.7. Determines any additional (expanded sample) inspections made necessary by discovery of unacceptable indications in accordance with ASME Section XI or BWRVIP Inspection and Evaluations Guidelines.

3.1.8. Provides input to the VY Site Reactor Internals Coordinator and Design Engineering of the details of inspection findings, inspection technique limitations, and inspection coverage.

.__ -1 3.1.9. Determines any successive (follow-up) inspections made necessary by discovery of unacceptable indications in accordance with BWRVIP Inspection and Evaluations Guidelines.

3.1.10. Determines, in conjunction with licensing, the necessity for communications with the NRC. Lf an exception is taken to BWRVIP guidelines, this determination will be made in accordance with BWRGVIP-94.

3.1.1 1. Maintains a history of all Reactor vessel internds inspections.

3.1.12. Provides a refueling outage inspection report to the BWRVIP.

3.1.13. Publishes the Reactor Vessel Internals Health Report within 90 days of completion of each refueling outage.

PP 7027 Rev. 3 Page 5 of 20

I -

1 3.2. VY Site Reactor Internals Management Program Coordinator (RJMPC):

3.2.1. Is responsible for site implementation of the Vermont Yankee Reactor Vessel Internals Management Program.

3.2.2. Provides technical advice and input for all aspects of the program.

3.2.3. Arranges for contractor on-site services for the performance of Reactor vessel internals inspection. Staffing levels should be adequate to provide coverage at all times during the inspection; for example, during In Vessel Visual Inspection (rVVI), at least one camera operator and one Level lI should be available on each bridge.

3.2.4. Ensures that specific site and vendor inspection procedures are prepared, reviewed, and approved in accordance with AP 0095, AP 0096, AP 0097, and AI? 0098, and administered in accordance with AP 6024.

3.2.5. Discusses requirements for voiding particular fuel bundle or control cell locations with Reactor Engineering.

I 3.2.6. Arranges for NDE Level I IIor other technical oversight including shared services.

I 3.2.6.1. Responsible for the review and approval of vendor NDE procedures.

I 3.2.6.2. Assures that, for NDE techniques other than visual, a performance demonstration has been conducted, which meets all key elements of the vendor NDE procedure.

3.2.6.3. Ensures that all NDE personnel qualifications are current and that they meet ASME Section XI and NE 8048, Procedure Paragraph I, as appropriate.

3.2.6.4. Oversees or conducts NDE personnel indoctrination to meet NE 8042 and NE 8048, Procedure Paragraph 1.3.

3.2.6.5. Provides assurance that inspection activities meet the requirements of the ASME Section XI Code, BWRVJP guidelines, and this program.

3.2.6.6. Provides assurance that NDE data is of high quality.

3.2.6.7. Initiates Indication Discrepancy Reports in accordance with DP 4027, as required.

3.2.6.8. Responsible for review of all NDE documentation, including the final report, to ensure proper documentation in accordance with BWRVIP-03, ASME Section XI, or NE 8048, as applicable.

3.2.6.9. Prepares a technical justification per 4.2.3 and notifies the Program Owner if the VY Site Internals Coordinator elects to take an exception to B W R W guidance.

Review is required by the Program Owner.

PP 7027 Rev. 3 Page 6 of 20

3.2.7. Responsible for completion of the refueling outage inspection plan.

3.2.8. Arranges for engineering evaluation of flaws.

3.2.9. Ensures that any additional (expanded sample) inspections specified by the Program Owner are completed.

3.2.10. Ensures ANTI has reviewed NDE procedures, NDE personnel qualifications, and NDE reports when ASME Section XI is applicable.

3.2.11, Verifies that contractor special process procedures to be used in repair or replacement have been reviewed and approved by Design Engineering prior to use.

NOTE 1 Repairs shall be performed in accordance with AP 0070, ASME Section XI if applicable - or, if not specified therein - in accordance with the construction Code. In addition, repairs shall be performed in accordance with applicable BWRVIP documents.

3.2.12. Arranges for contractor support for Reactor vessel internal repair or replacement activity.

3.2.13. Is responsible for proper installation of Reactor vessel internals repairs or replacements.

3.2.14. Verifies that repair or replacement procedures have been reviewed and approved in accordance with AI? 6001 and AP 0070, as appropriate, prior to use.

3.2.15. Monitors maintenance, repair, and replacement activities to ensure that required I in-service and baseline inspection specified by Program Owner are performed prior to placing systems or components into service.

3.2.16. Coordinates with site scheduling, radiation protection, and ALARA personnel as it pertains to the Reactor vessel internals inspections, repairs, or replacements.

3.2.17. Arranges for Authorized Nuclear Inservice Inspector (AND) review of appropriate Reactor internals inspection data, flaw analysis reports and repair or replacement activities.

3.2.18. Keeps the Code Programs Supervisor informed of inspection, repair, or replacement task progress of the Reactor vessel internals.

3.2.19. Ensures that cognizant departments are informed of unacceptable conditions to facilitate completion of appropriate paperwork (Condition Reports, Inservice Discrepancy Reports, WRs, etc.).

PP 7027 Rev. 3 Page 7 of 20

NOTE Unacceptable inspection results are reported to the RIMPC by the examination agency or cognizant department for resolution. The Authorized Nuclear Inservice Inspector (ANLI) is informed of the resolution.

3.3. Design Engineering Manager:

3.3.1. Is responsibIe for evaluation of any flaws found in Reactor vessel internals components; 3.3.2. Is responsible for the design of any Reactor vessel internals component repair or replacement.

I 3.3.3. Assures that Nobel Metal Chemical Application (NMCA) is scheduled as necessary and is accomplished to meet system goals.

3.3.4. Prepares a technical justification per 4.2.3 and notifies the RIMPC if Design Engineering elects to take an exception to BWRVIP guidance.

I 3.4. The examination vendor:

3.4.1. Provides staff andNDE services as specified in the purchase order andor contract.

I 3.4.2. Notifies the RWIPC and Program Owner if the examination agency intends to take an exception to BWRVIP guidance, and assists in preparing a technical evaluation per 4.2.3.

Also notifies the RIMPC if a Code requirement cannot be met.

3.4.3. Notifies the NDE Level ID in a timely manner of any rejectable indications.

3.4.4. Provides fvVI or NDE Reports, which meet the requirements of NE 8048 or BWRVIP-03, as applicable.

3.4.5. Provides NDE certifications and training records for NDE personnel.

PP 7027 Rev. 3 Page 8 of 20

3.5. The Chemistry Department Superintendent 3.5.1. Reviews BWRVlP guidance relative to water chemistry and IGSCC mitigation and incorporates that guidance into plant procedures. Ensures that other industry guidelines relating to IGSCC mitigation are reviewed in a timely manner and incorporated into plant procedures where applicable.

3.5.2. Prepares a technical justification per 4.2.3 and notifies the RIMPC if Chemistry elects to take an exception to BWRVlP guidance.

1 .

3.5.3. Assures that operation of the Mitigation Monitoring System ( M M S ) is conducted in a safe and efficient manner. Tracks MMS availability and works to maximize its availability to meet or exceed system goals. Ensures that the MMS is routinely monitored and that coupons from the panel are evaluated per GE recommendations. Assures that MMS coupon test results are fed back for system operation.

3.5.4. Ensures that adequate trending of Reactor vessel chemistry is done in order to identify adverse trends.

3.5.5. Ensures that procedures are in place to identify and mitigate transient conditions such as condenser le d resin intrusions.

3.5.6. m i s t r y Staff understands role in vessel internds management

' are adequately trained to accomplish required chemistry mitigation activities.

Operations Manager:

3.6.1. Assures the Reactor is shutdown when degradation of Reactor internals could potentially i I challenge safe plant operation.

L 3.6.2. Assures that Chemistry is informed when the MMS system trips or is taken out of service.

Mitigation Systems Engineer:

'='7 f 3.7.1. The functions of the Mitigation System Engineer, for complying with Industry Guidance related to IGSCC mitigation activities, will be performed by the Chemistry Department.

3.8. A L A M Engineer:

3.8.1, Works with Chemistry Department and Mitigation Systems Engineer to provide solutions for minimizing dose impact of the mitigation systems with regard to maximizing system availability.

PP 7027 Rev. 3 Page 9 of 20

I 3.9. Foreign Material Exclusion @!E)Coordinator:

3.9.1. Manages the FNEProgram. The FME Program assures that personnel perform their responsibilities in accordance with AP 6024 and AP 6026 relative to Reactor internal cIeadiness, and that foreign objects are removed or dispositioned prior to re-assembly of the Reactor vessel.

3.10. Licensing Program Manager:

3.10.1. Provides Interface with the NRC for notification when ASME requirements cannot be met or if notification is required for not following B W R V P guidance.

3.11. Code Programs Supervisor (Responsible Procedure Owner): (UND 2002-074-02) 3.11.1. Provides overall management of the Reactor Vessel Internals Management Program.

3.11.2. Functions as the overall single point of contact for Reactor vessel intemals I I .

interdepartmental issues.

3.11.3. Chairs the Reactor Internals Management Committee. This committee is comprised of I..

personnel from Code Programs, Systems Engineering, MechanicalIStructuralDesign I:

Engineering, Plant Chemistry, Reactor Engineering, and management. This group is structured to have a comprehensive background related to BWR Reactor internals issues. I This conmittee, through Code Programs, provides recommendations to VY management f related to key Reactor internals related issues.

I PP 7027 Rev. 3 Page 10 of 20

4.0 PROCEDURE 4.1. Governing Codes, Regulatory Commitments, and Basis for Inspection Requirements 4.1.1. ASME Section XI and PP 7015 - Title 10 Code of Federal Regulations, Part 50, Section 50.55a, Codes and Standards (10CFR50.55a) references the American Society for Mechanical Engineers (ASME) BoiIer and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components. PP 7015, Vermont Yankee Inservice Inspection Program for the Fourth Interval provides the requirements for I

compliance with most parts of ASME Section XI. However, contained within Section XI is Table IWB-2500 and Categories B-N-1 and B-N-2. These two categories address Reactor vessel internals inspection. This program (rather than PP 7015) addresses ASME

! . Section XI, Table IWB-2500-1, Categories B-N-1 and B-N-2. Category B-N-1, Item No.

addressed specifically within this tf to this program.

I which are contained in references) which contain requirements and recommendations for dealing with potential flaws in Reactor internals. The BWRVIP Executive Committee in a letter to the USNRC (Letter, Carl Terry to Brian Sheron, dated May 30, 1997) committed the U.S. utilities to the requirements of these BWRVIP documents. Vermont Yankee reiterated these commitments in its own letter to the NRC, BVY 97-123, dated September 30, 1997. Restated, those commitments are:

e Continue to provide the financial and technical resources needed to complete the BWRVIP Program Plan 0 Actively participate in completing the BWRVIP Program Plan 0 Implement the BWRVIP products at Vermont Yankee Nuclear Power Station as appropriate considering plant schedule, configuration and needs e Provide timely notification to the NRC staff if Vermont Yankee does not implement the applicable BWRVP product e Continue to work closely with the NRC staff for the successful and timely conclusion of the BWRVIP Program Plan PP 7027 Rev. 3 Page 11 of 20

4.1.3. Other Regulatory Commitments - In addition to the above documents, Vermont Yankee may make or may have made internal commitments or may have made commitments to the NRC, relative to various other industry documents, which deal with Reactor vessel internals. These may be GE Services Information Letters (SILs), Rapid Communication Services Information Letters (RICSILs), NRC Generic Letters, Infomation Notices, NUREGs, or others. These commitments are assimilated in this program in cases where they will continue to be followed, This program identifies where ongoing internal commitments are being revised and,which will in effect, act as the closeout of these old commitments. Old commitments, which have been closed out by completion of the commitment (e.g. a one-time component inspection), are not addressed in this program.

4.1.4. Inspection for Risk-to-Generation Purposes - In general, the inspections that are performed in accordance with the above documents or commitments are performed for safety related reasons. Notwithstanding, there are many Reactor vessel internals components which do not require inspections in accordance with the above documents or commitments. However, Vermont Yankee may elect to perform inspections on a regular basis of these components because they have been identified as a risk to generation. This type of inspection is also included in this program. When this is the case, this program (in Appendix A) identifies the non-mandatory nature of these inspections using should statements. These inspections may be driven by industry documents, such as GE Services Information Letters (SLs), Rapid Communication Services Information Letters (RICSILs), NRC Generic Letters, Information Notices, NUREGs, or others. Each new industry document relative to the Reactor intemals should be assessed. This assessment should be controlled through the PCRS LO-CA process. Each BWRVIP document, BWRVIP revision, or BWRVIP-to-NRC piece of correspondence should be assigned an individual tracking item.

1 I

PP 7027 Rev. 3 Page 12 of 20

4.2. Implementation of BWRVIP Documents - Vermont Yankee implements - the requirements

- of BI?RVIP documents as follows (BWRVIP-94, Section 1.3):

4.2.1. When a BWRVIP document is newly published or revised, Vermont Yankee shall assess the impact on this program and consider the guidance contained therein and determine if immediate compliance is warranted. In addition, Vermont Yankee shall evaluate in the same manner any BWRVIP correspondence approved by the BWRVIP Executive Committee to the NRC that supplements BWRVIP documents. (UND 2002-074-04, BWRVIP-94, Section 1.3). This assessment shall be controlled through the PCRS LO-CA process. Each BWRVIP document, BWRVlP revision, or BWRW-to-NRC piece of correspondence shall be assigned an individual tracking item. Typically BWRVIP documents will be implemented within 2 outages of Executive Committee (EOC) approval. The 2-outage implementation would be the start of any required frequency over a period of time. For example, if a BWRVIP document requires that a group of components be inspected in a 6 year period (100% in 6 years), this schedule must be started within 2 outages or the 2"drefueling outage from EOC approval of the BWRVIP document. Changes to the BWRVIP Water Chemistry guideline will be implemented within 6 months.

Regardless of this determination, Vermont Yankee shall revise this program accordingly prior to the ensuing refueling outage. However, Vermont Yankee may elect to take exceptions to this requirement under the following circumstances:

4.2.1.1. If it is within eigh utage and the guideline pertains to performance of additional in-vessel visual inspections 4.2.1.2. If it is within 24 months of the next refueling outage and the guideline pertains to performance of additional ultrasonic inspections, or 4.2.1.3. If the guideline would affect a potential repair, replacement, or plant modification, the lead-time for design changes and hardware may be considered.

4.2.2. If Vermont Yankee elects to not comply with a particular BWRVIP requirement, it shall notify the NRC within 45 days of the publication of a BWRVP document that incorporates all NRC/BWRVIP agreements OR the issuance of a closeout NRC Safety Evaluation Report (SER) on that document. A closeout NRC SER is one in which the NRC does not take any exceptions to the subject BWRVIP document as published.

Notification is not required for work completed prior to either of these times.

4.2.3. In addition, if Vermont Yankee elects to not comply with a particuIar B W R W requirement - at any time - it shall prepare a technical justification, which justifies the deviation using the guidance provided in BWRVIP-94, Appendix A. Use VYPPF 7027.01 form at the end of Appendix C to document this deviation.

PP 7027 Rev. 3 Page 13 of 20

4.3. The Level IlI prepares the Refueling Outage Inspection Plan using the inspection requirements and guidelines in Appendix A. This is done well in advance of the outage, so as to allow adequate preparation time for the plant and the examination vendor. The Refueling Outage Inspection Plan lists all welds and subcomponents that require inspection for the upcoming refueling outage and identifies the required type of inspection, e.g., EVT-1, VT-3,UT, etc.

4.4. NE 8067 contains implementation requirements for inspection of Reactor internals and provides details of Reactor internals components and their inspection.

4.5. If inspections are done by ultrasonic testing (UT) or eddy current testing (ET), they are performed in accordance with a vendor procedure qualified in accordance with BWRVIP-03, Standards 2.2 and 2.3. The vendor UT or ET procedure shall also meet the requirements of BWRVIP-03, Standard 2.6 or 2.7, and other sections, as applicable. Vendor UT or ET procedures shall be approved by Vermont Yankee.

4.6. If inspections are performed visually, they shall be performed in accordance with NE 8048.

4.7. NDE personnel indoctrination shall be conducted to meet NE 8042 and NE 8048. i

. 1 .

. .i e

i.2 . i 4.8. Disassembly of the Reactor vessel internals will not be required to examine any component, ...

beyond that which is normally performed for a refueling outage.

4.9. Flaws shall be reported in accordance with DP 4027. Flaws shall be evaluated.in accordance with B W R V P Inspection and Raw Evaluation Guidelines for components that perform a safety function. Subsequent BWRVIP/NRC correspondence should aIso be considered when evaluating flaws (BWRVIP-80-02).

4.10. If unacceptable indications are discovered, additional (expanded sample) inspections shall be performed in accordance with ASME Section XI or BWRVIP Inspection and Evaluations Guidelines, as appropriate.

4.11. Repairs or replacements of vessel internals shall be performed in accordance with AP 0070 and ASME Section XI if applicable - or if not specified therein - in accordance with the construction Code. In addition, repairs or replacements shall be performed in accordance with the appropriate B W R W Repair Guideline or BWRVIP Replacement Guideline. BWRVIP-04-A or BWRVIP-95, as applicable, will be used as a guide for format and content of a repair submittal to the NRC. (BWRVIP-004-A-01, BWRVIP-095-02) Subsequent BWRVIPNRC correspondence should also be considered in the design, installation, and inspection of repairs (BWRVIP-2003-250-02).

4.12. All NDE documentation, including the final report, shall be reviewed to ensure proper documentation in accordance with BWRVIP-03, ASME Section XI, or NE 8048, as applicable.

PP 7027 Rev. 3 Page 14 of 20

4.13. Program Procedure Revisions - This program shall be revised - or an LPC issued - as needed, which includes the following situations. Revisions or changes may be held until just prior to the next refueling outage.

e Upon adoption of a new ASME Section XI Code edition or addendum.

e Upon implementation of a new BWRVIP guideline or guideline revision, this program shall be revised as soon as practical.

e When flaws are found, this program shall be revised to address possible changes in frequency of inspection, foIlow-up inspections, and repair or replacement determinations.

e When new commitments are made - either internally, or to the NRC.

5.0 REFERENCES

AND COMMITMENTS 5.1. Technical Specifications and Site Documents 5.1.1. T.S. Section 3.6E 5.1.2. T.S. Section4.6.E.l 5.1.3. T.S. Section 6.

5.1.4. VOQAM, Vermont Yan al Quality Assurance Manual 5.1.5. UFSAR Secti 5.2. Administrative Limits 5.2.1. None 5.3. Code, Standards, and Regulations 5.3.1. Code of F Re&lations, 10 5.3.2. ASME Boiler and Pressure Vessel Code,Section XI, 1998 Edition through 2000 Addenda 5.3.3. NUREG-1544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds and Other Internal Components 5.3.4. CP-189-1995, ASNT Standard for Qualification and Certification of Nondestructive Testing Personnel 5.4. Commitments 5.4.1. Letter Vermont Yankee to USNRC, dated October 6, 1993, Reactor Vessel Clad Inspection during the 1993 Refueling Outage 5.4.2. Letter Vermont Yankee to USNRC, BVY 94-07, dated February 11, 1994, Request for Relief from NUREG-06 19 Inspection Requirements 5.4.3. Memorandum T. G. Stetson to R. E. McCullough, dated October 25, 1996, Response to Commitment SIL0465S1RE2 5.4.4. Letter Carl Teny (BWRVlP Executive Chairman) to Brian Sheron (USNRC),dated May 30, 1997, B W R Utility Commitments to the B W R W PP 7027 Rev. 3 Page 15 of 20

5.4.5. Letter Brian Sheron (USNRC) to Carl Terry (BWRWExecutive Chairman), dated July 29, 1997, BWR Utility Commitments to the BWRVIP 5.4.6. Letter Vermont Yankee to USNRC, dated September 30,1997, Vermont Yankee's Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals 5.4.7. Letter Carl Teny to Brian Sheron, dated October 30, 1997, BWR Utility Commitments to the B W R W 5.4.8. Letter USNRC to VYNPC, dated April 29,1999, NVY 99-46, Jet Pump Riser Circumferential Weld Inspections at Vermont Yankee Nuclear Power Station (TAC No.

MA5109) (includes two-cycle SER) 5.4.9. Letter Vermont Yankee to USNRC, dated May 27,1999, BVY 99-73, Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages 5.4.10. Action Item SIL-0462R1-01, dated March 27,2001, Evaluate SIL No. 462 Rev. 2

'Access Hole Cover Cracking' OE i 5.4.11. Letter Carl Terry (BWRW Executive Chairman) to Brian Sheron (USNRC), dated April I 16,2002, Utility Implementation of B W R W Products 5.4.12. Memorandum C.B. Larsen to D.C. Girroir, dated October 21,2002, Evaluation of Clad Crack Indications Under the Reactor Head and in the Vessel I.

5.5. Supplemental References , 1 -:

5.5.1. BWRVIP-03, dated December 2001, BWR Vessel and Internals Project Reactor Pressure Ii Vessel and Internals Examination Guidelines, Revision 4, EPRI TR-105696-R5 5.5.2. Letter NRC to BWRVIP, dated July 15, 1999, Final Safety Evaluation of BWRVIP Reactor Pressure Vessel and Internals Examination Guidelines (BWRVIP-03) Revision 1 1 5.5.3. BWRVIP-04-A, dated April 2002, Guide for Format and Content of Core Shroud Repair Design Submittals, EPRI TR-1006600 5.5.4. BWRVIP-06-A, dated March 2002, Safety Assessment of BWR Reactor Internals, EPRI L TR-105707 5.5.5. BWRVIP-16, dated March 1997, BWRVIP,Internal Core Spray Piping and Sparger Replacement Design Criteria, EPRI TR-106708 BWRVIP-18, dated July 1996, BWR Core Spray Internals Inspection and Flaw I Evaluation Guidelines, EPRI TR-106740 i 5.5.7. BWRV"-19, dated September 1996, Internal Core Spray Piping and Sparer Repair Design Criteria, EPRI TR-106893 5." 8. BWRVIP-25, dated December 1996, BWR Core Plate Inspection and Flaw Evaluation f

Guidelines, EPRI TR-107284 BWRVIP-26, dated December 1996, BWR Top Guide Inspection and Flaw Evaluation 1 Guidelines, EPRI TR- 107285 5.5,lcI. BWRVP-27-A, dated August 2003, BWR Standby Liquid Control SystedCore Plate AP Inspection and Flaw Evaluation Guidelines, EPRI TR-107286 5.5.11. BWRVIP-28-A, dated April 2002, Assessment of BWR Jet Pump Riser EIbow to Thermal Sleeve Weld Cracking 5.5.12. BWRVLP-38, dated September 1997, BWR Shroud Support Inspection and Flaw Evaluation Guidelines, EPRI TR-108823 5.5.13. BWRVIP-41, dated October 1997, BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines, EPRI TR-108728 5.5.14. BWRVIP-42, dated December 1997, LPCI Coupling Inspection and Flaw Evaluation Guidelines, EPRI TR-108726 PP 7027 Rev. 3 Page 16 of 20

5.5.15. BWRVIP-47, dated December 1997, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines, EPRI TR-108727 5.5.16. BWRVIP-48, datedFebruary 1998, Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines, EPRI TR-108724 5.5.17. BWRVIP-49-A, dated March 2002, Instrument Penetration Inspection and Flaw Evaluation Guidelines, EPRI TR-108695 5.5.18. BWRVIP-50, dated May 1998, BWRVIP,Top GuideKOre Plate Repair Design Criteria, EPRI TR-108722 5.5.19. BWRVIP-51, dated May 1998, BWRVIP, Jet Pump Repair Design Criteria, EPRI TR-108718 5.5.20. BWRVIP-52, dated June 1998, BWRVIP, Shroud Support and Vessel Bracket Repair Design Criteria, EPRI TR-108720 5.5.21. BWRVIP-53, dated July 1998, BWRVIP, Standby Liquid Control Line Repair Design Criteria, EPRI TR-108716 5.5.22. BWRVIP-55, dated September 1998, BWRVIP, Lower Plenum Repair Design Criteria, EPRITR-108719 5.5.23. BWRVIP-57, dated December 1998, BWRVIP, Instrument Penetrations Repair Design Criteria, EPRI TR-108721 5.5.24. BFVRVIP-58, dated D CRD Internal ACC Weld Repair, EFFtI ed D ical Basis for Inspection Relief for BWR Internal Components with Hydrogen Injection, EPRI TR-108705 5.5.26. BWRVIP-76, dated Core Shroud Inspection and Haw Evaluation Guidelin 5.5.27. BWRVIP-79, dated Water Chemistry Guidelines - 2000 Revision, EPRI TR-1035 5.5.28. BWRVIP-94, dated Implementation Guide 5.5.29. BWRVIP-95, dated October 2001, BWRVIP Guide for Format and Content of BWRVP Repair Design Submittals 5.5.30. BWRVIP-104, dated September 2, BWRVIJ? Evaluation and Recommendations to Address Shroud Support Cracking in BWRs, EPRI TR-1003555 5.5.31. EDCR 75-30, Revision 2, dated September 15, 1976, Feedwater Sparer Replacement 5.5.32. EDCR 80-52, dated October 30, 1980 with Change No. 1 dated November 11,1980, Change No. 2 dated December 12,1980, and Change No. 3 dated March 4,1982, Design and Installation of Clamping Device for Core Spray Sparer Junction Box C 5.5.33. EDCR 95-406, Revision 2, dated July 30, 1996, Specification for Design, Fabrication, and Installation Services for Reactor Pressure Vessel Core Shroud Repair at Vermont Yankee Nuclear Power Station, VYS-046, Revision 2 5.5.34. ENN-NDE-2.10, Certification of NDE Personnel 5.5.35. ENN-NDE-2.11, Certification of Ultrasonic Examination Personnel 5.5.36. ENN-NDE-2.12, Certification of Visual Testing (VT) Personnel 5.5.37. GE-NE-523-B13-01805-66, Revision 0, dated September 1996, Core Spray Flaw Evaluation for Vermont Yankee 5.5.38. GE-NE-B13-01935-02, Revision 1, dated July 1998, Jet Pump Assembly Welds Flaw Evaluation Handbook for Vermont Yankee 5.5.39. Letter BWRVIP to USNRC, dated January 11, 1999, BWRVIP Response to NRC Safety Evaluation of BWRVIP-18 PP 7027 Rev. 3 Page 17 of 20

5.5.40. Letter USNRC to BWRVIP, dated December 2, 1999, Final Safety Evaluation of Core Spray Internals Inspection and Flaw Evaluation Guidelines (BWRVIP-18) 5.5.41. Memorandum C. B. Larsen to D. C. Girroir, dated May 13, 1999, Definition of Core Support Structures (ASME Section XI, Category B-N-2) 5.5.42. Memorandum Carl Larsen to Dennis Girroir, dated September 26,2002, Bases for PP 7027 Requirements and Recommendations 5.5.43. Memorandum John Hoffman to D. C. Girroir, dated November 26,1999, Jet Pump Assembly Inspection Discrepancy Report Evaluation 5.5.44. MPR-1730, Revision 0, dated April 1996, Vermont Yankee Nuclear Power Station Core Shroud Repair - Design Report 5.5.45. Technical Evaluation No. 2001-030, dated May 14,2001, Evaluation of Jet Pump Riser Flaws 5.5.46. Technical Justification 2003-03, dated August 18,2003, Justification to Perform Less Than 5% of CRD Guide Tube Weld Exams Within the First Six-Year Interval 5.5.47. Technical Justification 2003-04, dated August 18,2003, Continued Operation Without a Feedwater Zinc Injection System 5.5.48. Technical Justification 2003-05, dated December 17,2003, Feedwater Copper Concentrations above Recommended Limits 5.5.49. Technical Justification 2004-01, dated March 26,2004, Justification for Alternative Inspection of Core Plate Rim Hold-Down Bolts 5.5.50. Technical Justification 2004-02, dated March 26,2004, Justification for Deferral of Inspection of Inaccessible Welds 5.5.5 1. Technical Evaluation 2004-0018, dated April 2004, Justification to Inspect Portions of Shroud Horizontal Welds H1, H2, H3 on the OD in Lieu of the Top Guide Spacer Block Welds, the Shroud Range Ring Segment Welds, and the Top Guide Rmg Segment Welds 5.5.52. Technical Justification TE-2003-0021, dated April 9,2003, Justification to Revert to EVT-1 Inspection of Jet Pump Circumferential Welds with U T Indications 5.5.53. Technical Justification TE-2003-0023, dated July 7,2003, Technical Assessment for Delaying Hydrogen Injection Into the Reactor Core 5.5.54. VY Calculation, VYC-2218, dated November 25,2002, Structural Evaluation of RPV Top Guide Aligner I 5.5.55. VY Snapshot Self Assessment Report BWRVIP Program, dated July 21,2004 5.5.56. VYDC 2003-12, dated April 2004, Steam Dryer Strengthening 5.5.57. ENN DC-135, BWRVIP Inspection Program 5.5.58. AP 0009, Condition Reports 5.5.59. AP 0028, Learning Organization Action Tracking 5.5.60. AP 0070, ASME Section XI Repair and Replacement Procedure 5.5.61. AP 0095, Plant Procedures 5.5.62. AP 0096, Procedure Development, Review, Issuance and Cancellation 5.5.63. A p 0097, Limited Procedure Changes 5.5.64. AP 0098, Procedure Writers Guide 5.5.65. OP 1111, Control Rod Removal and Installation 5.5.66. OP 1417, DisassemblyRe-Assembly of Fuel Cell 5.5.67. OP 2617, Chemistry Action Response Guide 5.5.68. OP 2638, Operation of the Mitigation Monitoring System (MMS) 5.5.69. DP 4027, Disposition of Inservice Inspection Findings 5.5.70. OP 4612, Sampling and Treatment of the Reactor Water System 5.5.7 1. AP 6001, Installation, Test and Special Test Procedures PP 7027 Rev. 3 Page 18 of 20

. I

5.5.72. AP 6024, Plant Housekeeping and Foreign Material ExclusiodCleanliness Control 5.5.73. AP 6026, Refuel Floor Foreign Material Exclusion Control Procedure 5.5.74. AP 6045, Engineering Record Correspondence @RC) and Technical Evaluations ("E) 5.5.75. AP 6807, Collection, Temporary Storage and Retrieval of Quality Assurance Records 5.5.76. PP 7015, Vermont Yankee Inservice Inspection Program 5.5.77. NE 8042, Training for Contract NDE Personnel 5.5.78. NE 8048, In-Vessel Visual Inspection 5.5.79. NE 8067, Reactor Vessel Internals Inspection Details 6.0 FINAL CONDITIONS 6.1. All required inspections and evaluations have been completed.

6.2. The NRC has been notified when required by BWRVIP-94 where Vermont Yankee has taken exception to BWRVIP guidance.

6.3. The B W R W has been notified where Vermont Yankee has taken exception to BWRVIP guidance. The B W R W has been notified when meaningful results are not obtained or when examinations cannot be performed because NDE techniques or equipment do not exist. The B W R W Program Manager has been notified of modifications to plant operation or configurations that may affect BWRVIP guidance (e.g., power uprate).

6.4. The vendor final report has been received and reviewed.

6.5. Applicable ASME Section XI inspections have been entered on the NIS-1 report.

6.6. All NDE inspection results, including IVVI,with supporting documentation and resolution of nonconformances (if applicable) shall be submitted for filing in accordance with AP 6807.

6.7. In-vessel inspection results pertinent to BWRVIP guidelines have been reported to the BWRVlP within 90 days of completion of the refueling outage.

6.8. Reactor Vessel Internals Health Report has been published within 90 days of completion of each refueling outage.

6.9; This program has been updated to include information and any additiona1 requirements that have resulted from an inspection, including supplemental inspections.

6.10 This program has been updated to include any new BWRVIP commitments.

7.0 ATTACHMENTS 7.1. Appendix A Reactor Vessel Internals Components Inspection Scope and Schedule 7.2. Appendix B Reactor Vessel Internals Components Basis for Inspection and Other Management Requirements 7.3. Appendix C Technical Justifications PP 7027 Rev. 3 Page 19 of 20

8.0 QA REQUIREMENTS CROSS REFERENCE Source Document Section Procedure Section 8.1 QAPM Section B.11 Special Process Control, Subsections A, B.3, and C 8.2 ANSIN18.7 Section 5.2.18 Control of Special Processes i

PP 7027 Rev. 3 Page 20 of 20

APPENDIX A REACTOR VESSEL INTERNALS COMPONENTS INSPECTION SCOPE AND SCHEDULE 1.0 Control Rod Drive (Including Guide Tubes and Stub Tubes)

By RFO 23 (2002), at least five of the 89 CRD guide tube assemblies were due to have been I inspected by the EVT-1 and VT-3 methods. One CRD guide tube 10-19 WAS inspected late in RFO 24 (2004). (Ref. 5.4.47) By RFO 27 (2008), a total of nine CRD guide tube assemblies shall have been inspected. (BWRVIP-47, TabIe 3.2-1) It is recommended that those inspections be grouped into outages where this minimum amount may be performed in conjunction with blade change-outs. These inspections are scheduled for RFO 22 (2001) and RFO 26 (2007) so that if the minimum number is not completed in that refueling outage they are completed in the refueling outage in which they are due. Inspection of the same location during different outages does not count towards satisfying the minimum sample requirement.

If access is gained to the lower plenum (areas below the core plate) for any reason, accessible surfaces of the CRD housings, RD housing caps, and CRD stub tubes shall be visually inspected by the VT Table IWB-2500-1, Category B-N-2, Item B13.40) 2.0 Core Plate Core plate rim hold-down bolts shall be inspected by the U T method when tooling becomes available. (BWRVIP-25, Table 3-2) Until that time VT-3 shall be conducted of the topside of 50% of the rim hold-down bolts every other refueling outage.

If access is gained to the lower plenum (areas below the core plate) for any reason, accessible core plate beam fillet welds, rim hold-down bolts, and alignment hardware should be inspected by the VT-3 method. (Appendix B, 2.4) 3.0 Core Shroud (Including Tie Rod Repair and Spa Welds H1, H2,and H3 were inspected by EVT-1 in RFO 24 (2004) and shall be reinspected by EVT-1 in RFO 28 (2010) (TE 2004-0018). The reinspection by either EVT-1 or UT of the vertical welds and core plate ring segment welds required by RFO 25 (2005) were performed by EVT-1 during RFO 24 (2004) The vertical welds and core plate ring segment welds shall be reinspected by EVT-1 in RFO 28 (2010). (BWRVIP-76,Figure 3-3, TE 2004-0018)

I All four of the tie-rods were reinspected in RFO 21 (1999). Two tie-rods were reinspected by the VT-3 method in RFO 24 (2004), the other two shall be reinspected in RFO 27 (2008),and so forth. If the tie-rods ever require retorquing, they shall be inspected for a baseline inspection following that activity, and then again following one cycle of operation. (BWRVIP-76, Section 3.5)

Appendix A PP 7027 Rev 3 Page 1 of 11

APPENDIX A (Continued)

Accessible surfaces of the core shroud shall be visually inspected once per Ten-year IS1 Interval by the VT-3 method. (ASME Section XI, Table IWB-2500-1, Category B-N-2, Item B13.40)

The Third Ten-year Interval inspection was performed in FtFO 23 (2002).

4.0 Core Shroud Sup~ort(Including Access Hole Cover)

Welds H8 and H9 of the shroud support shall be reinspected by UT in lU?O 25 (2005). A minimum coverage of 10%of weld H8 and 10%of weld H9 shall be achieved. (BWRVIP-38, Figures 3-4 and 3-5)

The two access hole cover welds should be inspected by the EVT-1 method every other refueling outage until a BWRVIP document is published that addresses this component or until this internal commitment is changed. (SILO46Rl-01)

There are also radial welds in the shroud support baffle plate and vertical welds in the shroud I support cylinder, which are not specifically required to be inspected except as part of the overall VT-3 inspection described below.

Accessible surfaces of the core shroud support shall be visually inspected once per Ten-year IS1 Interval by the VT-3 method. (ASME Section XI, Table IWB-2500-1,Category 3-N-2, Item B13.40) This was performed for the Third Interval in RFO 23 (2002).

Because of a risk to generation the two shroud support flange vertical welds located between 37 and H8 will be visually examined by EVT-1 during RFO 25 (2005) and reinspection shall be both welds per 6 year cycle thereafter.

If access is gained to the lower plenum (areas below the core plate) for any reason, accessible surfaces of the shroud support legs and their welds, and the underside of the shroud support baffle plate and its welds shall be inspected by the VT-3 method. (ASME Section XI, Table IFsrs-2500-1, Category B-N-2, Item B13.40)

The annulus floor should be inspected by the VT-3 method for debris and loose parts each refueling outage. (Appendix 3,4.4) 5.0 Core Sprav Internal Pipine and h a r p e r s 5.1 Thermal Sleeve Welds There are three hidden welds inside each of the two core spray nozzles, which shall be inspected when an ultrasonic technique becomes available. (BWRVIP-18, Section 3.2.4) 100%of the welds shall be inspected. The reinspection frequency for this inspection is every eight cycles, (BWRVIP-18, Figure 3-3)

Appendix A PP 7027 Rev. 3 Page 2 of 11

APPENDIX A (Continued) 5.2 Internal Piping The BWRVIP core spray piping reinspection frequency for ultrasonic inspection is two cycles and for EVT-1 it is one cycle. For either inspection method, all target welds shall be inspected.

(BWRVIP-18, Figure 3-3) The target welds include the 24 creviced welds and the four tee-box-to-piping (P3) welds, and five or six of the 16 remaining welds (the elbow welds), for a total of 33 or 34 target welds. The 16 elbow welds shall be inspected on a rotating basis over three inspections, The fourth inspection slot will be filled by the thermal sleeve weld UT (BWRVIP-18, Figure 3-3) if a technique and tooling become available. Welds 1P9 and 3P9 shall be inspected when an ultrasonic technique becomes available. (UND2002-243-03) 5.3 Spargers The five large circumferential welds (identified as S 1, S2, and S4 in BWRVIP-18) in each sparger (20 welds total) shall be inspected every other cycle with the EVT-1 method. Fifty percent of the nozzle welds (identified as S3 in BWRW-18) shall be inspected every other cycle with the VT-1 method. The sparger welds received a baseline inspection in RFO 20 (1998), so sparger reinspections (the 20 large circumferential welds and two of four spargers worth of nozzle welds on an alternating basis) would be performed in RFO 22 (2001), RFO 24 (2004), etc.

(BWRVIP-18, Figure 3-4)

The sparger tee-box repair at 193 degrees shall be reinspected every other refueling outage with the VT-1 method. (BWRVIP-18, Section 3.3.3) 5.4 Piping and Sparger Brackets The core spray piping brackets shall be inspected every four cycles with the EVT-1 method beginning in RFO 23 (2002). The core spray sparger brackets shall be inspected every other cycle with the VT-1 method beginning in RFO 23 (2002). (BWRVIP-18, Section 3.3.3, BWRVIP-48, Table 3-2, References 5.4.40 and 5.4.41, ASME Section XI, Table IWB-2500-1, Category B-N-2, Item B 13.30, ER-2001-2480-01) 6.0 Feedwater Saarpers The feedwater sparger tee welds and end bracket-to-vessel attachment welds shall be inspected by the VT-1 method every other refueling outage, Le. RFO 22 (2001), RFO 24 (2004), RFO 26 (2007), etc. The other locations in the feedwater spargers shall be inspected by the VT-3 method during the same refueling outages. (Reference 5.3.2)

In addition, inspection by the EVT-1 method of the sparger end bracket-to-vessel attachment welds shall be performed once per Ten year IS1 Interval. (BWRVIP-48, Table 3-2, and ASME Section XI, Table IWB-2500-1, Item B13.30) The Third Ten-year Interval inspection was performed in RFO 23 (2002).

Appendix A PP 7027 Rev. 3 Page 3 of 11

-c

- 1 __

APPENDIX A (Continued) 7.0 Guide Rods The entire guide rod assembly should be inspected by the VT-3 method in conjunction with the guide rod attachment welds (see Appendix K, Miscellaneous Vessel Internal Attachments) once per Ten-year IS1 Interval. (Appendix B, 7.4) The Third Ten-year Interval inspection was I performed in RFO 23 (2002). The next VT-3 inspection shall be performed in RFO 29 (2011).

8.0 Incore Flux Monitors (Including Housings, Guide Tubes, Dry Tubes)

Two dry tubes out of the ten total number shouId be inspected by the VT-1 and VT-3 methods every third refueling outage. (Appendix B, 8.3) Two dry tubes were inspected in RFO 21 (1999)

I and two more were inspected in RFO 24 (2004). Starting in RFO 25 (2005), 50% of the dry tubes that are 20 years old should be inspected every refueling outage. (SE-409R2-02)

If access is gained to the lower plenum (areas below the core plate) for any reason, accessible incore housings, incore guide tubes, and incore guide tube stabilizers should be visually inspected by the VT-3 method. (Appendix B, 8.4) 9.0 Instrument Penetrations No inspections of the instrument penetrations are required (beyond those contained in PP 7024 for nuclear boiIer pressure testing).

10.0 Jet Pumps 10.1 Jet Pump Beams UT inspection of 100% of the beams is required in RFO 23 (2002). Following that, reinspection of 100% of the beams using UT is required in the six-year interval between and including RFO 24 (2004) and RFO 27 (2008), and in each six-year interval thereafter. (BWRVIP-41, Table 3.3-1) 10.2 Jet Pump Riser Thermal Sleeve Welds These welds inside the ten inlet nozzles shall be inspected when an ultrasonic technique becomes available. Between 50% and 100% of the welds shall be inspected at that first opportunity. If all of the welds are inspected, they do not require reinspection for twelve years after that. If only 50% are inspected, the other 50% shall be inspected in the next six-year interval. Reinspection of 25% of the welds would be required in the six-year interval following that. (BWRVIP-41, Table 3.3-1 and Section 3.2.4)

Appendix A PP 7027 Rev. 3 Page 4 of 11

APPENDIX A (Continued) 10.3 Jet Pump Riser Welds The two thermal sleeve-to-elbow welds with flaws shall be reinspected by the EVT-1 method in RFO 24 (2004), RFO 26 (2007), and RFO 28 (2010). (Reference 5.4.53) If there is no flaw growth, these two welds could continue to be inspected every other cycle after that. It is also I possibIe that if there were no flaw growth, the inspection frequency (which follows here) for the two flawed welds could be reassessed and extended.

Reinspection by the EVT-1 method of 50%of the riser welds was performed during RFO 24 (2004). Reinspection is 25%of the Jet Pump Riser Welds in the six year interval beginning RFO 28 (2010) and so on. (BWRW-41,Table 3.3-1) 10.4 Jet Pump Riser-to-Restrainer and Riser-to-Brace Welds Inspection by the EVT-1 method of 50% of the riser-to-restrainer and riser-to-brace welds that were not inspected in W O 20 (1998) were completed in RFO 24 (2004). Reinspection of 25%

of the welds would be required in the six-year interval following RFO 27 (2008). (BWRVIP-41, Table 3.3-1) 1

! 10.5 Jet Pump Riser Braces Inspection by the EVT-1 method of 50%of the riser brace welds that were not inspected in RFO 20 (1998) were inspected in RFO 24 (2004). Reinspection of 25%of the welds would be required in the six-year interval following RFO 27 (2008). (BWRVIP-41, Table 3.3-1, BWRVIP-48, Table 3-2, and ASME Section XI, Table IWB-2500-1, Category B-N-2, Item B13.20) 10.6 Jet Pump Inlet Clamp Bolts Inspection by the VT-3 method of the inlet clamp bolted connections in Loop B (50% of the total) was performed in RFO 24 (2004). Reinspection of 25% of the bolted connections would be required in the six-year interval following RFO 27(2008). (BWRVIP-41, Table 3.3-1) 10.7 Jet Pump Restrainer Assemblies Since RFO 20 (1998) VY has visually examined 50% of the jet pump wedge assemblies every other outage. During RFO 22 (2001) and RFO 24 (2004) 100%of the jet pump wedge assemblies were examined by VT-1. The re-inspection cycle for jet pump wedge assemblies is 25% over each inspection cycle (6 years). Therefore, during RFO 25 (2005),RFO 26 (2007),

RFO 27 (2008), and RFO 28 (2010) 5 jet pump wedge assemblies will have to be inspected and then 25%more over the next 6-year interval and so on. Current B W R W 41-A guidance does not require jet pump set screw inspections to identify vibration. This is because jet pump wedge assembly wear would be a tell tale sign that vibration was occurring. If wedge bearing surface wear is detected, inspection of the adjusting screws, hex nuts, etc. as applicable shall be examined during the sanie outage when the wedge wear was detected to determine the cause of wear.

Appendix A PP 7027 Rev. 3 Page 5 of 11

APPENDIX A (Continued) 10.8 Jet Pump Mixer Inlets No inspections are currently required. (Reference 5.3.3) 10.9 Jet Pump Mixer/Diffuser Circumferential Welds above Diffuser Shell 25% of the mixer/diffuser welds above the diffuser shell shall be reinspected by either the UT or I EVT-1 methods sometime in the six-year interval following October 2009. The welds included in this group are MX-1, MX-2, MX-4, and DF-1. (BWRVIP-41, Table 3.3-1) 10.10 Jet Pump Diffuser/Adapter Circumferential Welds below Diffuser Shell The four diffuser welds with flaws shall be reinspected by the EVT-1 method in RFO 25 (2005),

RFO 27 (2008), and RFO 29 (2011). (Reference 5.4.53) If no flaws are detected, these welds can revert to the normal inspection frequency (which follows here). Reinspection by either the UT or EVT-1 methods of the diffuser/adapter circumferential welds below the diffuser shell is required in the six-year interval between and including RFO 24 (2004) and RFO 27 (2008) and in each subsequent six-year interval. The welds included in this group are DF-2, DF-3, AD-3b, AD-1, and AD-2. (BWRVIP-41, Table 3.3-1) 10.11 Jet Pump Sensing Lines Inspection by the VT-3 method of the sensing lines and their brackets should be performed in one loop every other outage. Inspection of the sensing lines in Loop B (jet pumps 1 through 10) was performed during RFO 22 (2001). In RFO 24 (2004), the sensing lines in Loop A (jet pumps 11 through 20) should be inspected, and so forth. (Appendix B, 10.1.11, 10.4) 11.0 Lower Plenum If access is gained to the lower plenum (areas below the core plate) for any reason, accessible areas of the foIIowing components shalI be inspected by the VT-3 method (ASME Section XI, Table MTB-2500-1, Category B-N-2, Item B 13.40):

0 CRD housings e CRD housing caps e CRD stub tubes 0 Core shroud support legs e Core shroud support baffle plate underside Appendix A PP 7027 Rev. 3 Page 6 of 11

APPENDIX A (Continued)

If access is gained to the lower plenum (areas below the core plate) for any reason, accessible areas of the following components should be inspected by the VT-3 method (Appendix B, 2.4, 8.4, 15.4):

e Core plate beam fillet welds 0 Core plate rim hold-down bolts Core plate alignment hardware e Incore flux monitor housings e Incore flux monitor guide tubes e Incore flux monitor guide tube stabilizers e SLC and core plate AP lines In addition, if access is gained to the lower plenum, the vessel bottom head and the bottom head drain should be inspected by the VT-3 method for debris or crud buildup. (Appendix B, 11.2) 12.0 Miscellaneous Vessel Internal Attachments (Including Steam Dryer, Specimen Holder, Guide Rod)

The steam dryer support attachment welds (Em-l), the surveillance specimen holder bracket attachment welds (VT-l), the steam dryer hold-down bracket attachment welds (VT-3), and the guide rod bracket attachment welds (VT-3) shall be inspected once per Ten-year IS1 Interval.

The Third Ten-year Interval inspection was performed in RFO 23 (2002). (BWRVIP-48, Table 3-2, and ASME Section XI, Table IWB-2500-1, Category B-N-2, Item Nos. B13.20 andB13.30)

The dryer support bracket at 215 degrees was inspected in the Third Period of the Third Interval during RFO 22 (2001). T h s exam was performed in a similar fashion to the reinspections performed in RFO 17 (1993) and RFO 20 (1998). These exams are now complete. (Reference 5.3.1) 13.0 Orificed Fuel Supaort Castinw No inspection requirements. (Reference 5.4.42) 14.0 Specimen Holders An inspection of the surveillance specimen holders should be performed each Ten-year IS1 Interval. These inspections can be performed in conjunction with the bracket attachment welds (see Miscellaneous Vessel Internal Attachments above). (Appendix B, 14.4) 15.0 Standby Liauid ControVCore Plate Delta Pressure The nozzle-to safe end weld and the safe-end extension shall be volumetrically inspected once every 10-year IS1 Interval in accordance with the requirements of ASME Section XI, Appendix VIII, Supplement 10, when UT detection and sizing techniques are available and the weld surface condition is determined to be acceptable for U.T. Until such time they shall be examined by PT every other refueling outage. (TJ-2004-05, BWRVIP-27, Sections 3.3.1 and 3.4.1)

Appendix A PP 7027 Rev. 3 Page 7 of 11

APPENDIX A (Continued)

The SLC and core plate AP lines should be inspected if they are made accessible through other vessel activities. (Appendix B, 15.4) 16.0 Steam Drver Steam dryer modifications performed at VY during RFO 24 (2004) were done in support of scheduIed operation at Extended Power Uprate conditions GE performed complete In Vessel Visual Inspection (IVVI) on the interior and exterior of the dryer plus eight (8) types of modifications and repairs. Attachment 4 of proposed technical specification change No. 263 (Reference 16.5.19), requires a detailed inspection of the steam dryer during the next and subsequent two refueling outages following power uprated operation. Additionally, inspections will be performed in accordance with the recommendations of SlL 644, Revision 1, (VYDC2003 12).

A VT-3 inspection of the steam dryer lifting lugs and associated hardware should be performed every fourth refueling outage. (Appendix B, 16.4), etc. This was performed in RFO 24 (2004) and should be reinspected in RFO 28 (2010).

17.0 Steam SeDaratorlShroud Head (Including Hold-down Bolts)

A VT-3 inspection of the steam separator/shroud head lifting lugs and associated hardware, standpipes, peripheral standpipe attachments, peripheral standpipe assembly welds, the tie bars, the tie bar attachment welds, the shroud head flange, and accessible areas of the shroud head I should be performed every fourth refueling outage. (Appendix B, 17.4) This was performed in RFO 24 (2004), and should be reinspected in RFO 28 (2010), etc.

18.0 Too Guide Two top guide hold-down assemblies 180 degrees apart shall be inspected every other refueling outage. The assemblies at 108 and 288 degrees were inspected in RFO 23 (2002), the assemblies at 18 and 198 shall be reinspected in RFO 25 (2005),and so forth. (BWRVTP-26, Table 3-2)

As part of the power uprate approval process VY committed to perform inspection of the top guide grid beams in accordance with the methods of SIL 544. The selection sample and frequency will be the same sample of cell locations chosen for CRD guide tube examination per BWRW-47, except the sample should be biased towards the higher fluence areas of the top guide. Over a twelve-year period 10% of the top guide grid beam cells are to be inspected, with RFO 25 (2005), RFO 26 (2007), and RFO 27 (2008). Five ( 5 ) of the 89 top guide grid beam cells are required to be inspected in the first 6-year interval.

An inspection of one quadrant of the top guide rim bolts and the perforated cover sheet bolts should be performed every fourth refueling outage on a rotating basis beginning in RFO 22 (2001). (Appendix B, 18.4)

There are no other top guide inspection requirements, pending a decision by the BWRVIP regarding the analysis of the removed Oyster Creek top guide grid samples.

Appendix A PP 7027 Rev. 3 Page 8 of 11

APPENDIX A (Continued) 19.0 Vessel Cladding A sample of Reactor vessel cladding indications was reinspected in RFO 17 (1993), RFO 19 I (1996), and RFO 23 (2002). These inspections are now complete. (Reference 5.3.1)

During refueling outage RFO 24 (2004) crud deposits were identified on the reactor vessel she11 cladding at the elevation of the steam dryer support lugs. It resembled the "white stucco" that has been noted at other BWRs. The extent of the crud deposit was not determined, but it did not affect or mask any of the areas that were examined (e.g. core spray piping under head hold down brackets). This crud has not been observed prior to RFO 24. VY implemented NMCA in Spring 2001, with H W C implemented in November 2003.

f .I f

I. t Appendix A PP 7027 Rev. 3 Page 9 of 11

11 JO 01 assd C LZOL dd

APPENDIX A (Continued)

Table Kev Standard Print = Inspections mandated by ASME, BWRVlk, or NRC commitments Italics = Inspections recommended for Risk-to-Generationpurposes UT = Ultrasonic Testing performed or planned UT (aut or man) = Either automated or manual Ultrasonic Testing ET = Eddy Current Testing performed or planned PT = Penetrant Testing performed or planned VT = Visual Testing performed or planned EVTl = EVT-1; Enhanced Visual Test to look for cracking; 1/2 mil wire resolution with cleaning assessment EVT2* = Enhanced Leakage Inspection (direct view of component during pressure test)

VTl = VT-1; Visual Test to look for cracks, wear, corrosion, etc.; resolution required: 1/32 black lie VT3 = VT-3; Visual Test to determine general mechanical/structural condition; no resolution requirements CSVTl or MVT1 = CSVT-1 or MVT-I; Core Spray Visual Test or Modified VT-1, no longer a defined test method; 1 mil wire resolution

= Inspections not yet determined

= If necessary (to complete minium number of inspections not performed in previous outage)

(all, number, %, = Perform inspection on all components, limited number (or percentage) of components, or or flaw) just fiawed components Appendix A PP 7027 Rev. 3 Page 11 of 11

APPENDIX B REACTOR VESSEL INTERNALS COMPONENTS BASIS FOR INSPECTION AND OTHER MANAGEMENT REQUIREMENTS  !

t I

I r

I i

1 ,

1 I

i Appendix B PP 7027 Rev. 3  !

Page 1 of 65

APPENDIX B (Continued) 1.0 Control Rod Drive (Including Guide Tubes and Stub Tubes) 1.1. BWRVIP Document ADplicability BWRVIP-47, published in December 1997, governs inspection of the control rod drive assemblies internal to the vessel, including the guide tubes and stub tubes. With the exception of two circumferential welds in one guide tube (Reference 1,5.21), Vermont Yankee will complete the minimum required inspections within the periods established in BWRVIP-47 as of the date of its publication. The document establishes six-year inspection intervals for specific inspections described below. Vermont Yankee defines the first six-year intervd to include RFO 20 (1998),

RFO 21 (1999), RFO 22 (2001), and RFO 23 (2002). The second six-year interval will include RFO 24 (2004), RFO 25 (2005), RFO 26 (2007), and E 0 2 7 (2008). The third six-year interval will begin with RFO 28 (2010) and RFO 29 (2011).

The inspection requirements are established in BWRVIP-47, Table 3.2-1. This table requires inspection of four items on a CRD guide tube assembly: the guide tube sleeve-to-alignment lug weld (CRGT-l), the guide tube body-to-sleeve weld (CRGT-2), the guide tube base-to-body weld (CRGT-3), and the guide tube and fuel support alignment pin-to-core plate weld and the pin itself (FS/GT-ARPlN-l). CRGT-1 and FS/GT-ARPIN-1 require a VT-3 inspection and CRGT-2 and CRGT-3 require an EVT-1 inspection. Over a twelve-year period 10% of the CRD guide tube assemblies are to have had these four inspections performed, with 5% performed within the first six years. Those twelve and six-year intervals begin at the date of publication of B WRVIP-47, December 1997.

The two VT-3 inspections are actually satisfied during the orificed fuel support reinstallatiodrealignment procedure. The criteria for satisfying these VT-3 requirements are stipulated in BWRVIP-47, Table 3.2-1. The 10% sample will be completed during the normal course of blade change-outs over a twelve-year period. (Blade change-out requires orificed fuel support reinstallation and realignment). There are 89 CRD guide tubes at Vermont Yankee.

Typically, there are between three and ten blade change-outs each outage, so it is reasonable to expect that there will be at least nine blade change-outs during the next twelve years. These inspections began in RFO 22 (2001). During RFO 22 (2001) and RFO 23 (2002) only four blades were changed out. Therefore, the 5% sample was not quite satisfied (four of 89 is 4.5%)

in the first six-year inspection interval, as defined above. A technicd justification in accordance with BWRVIP-94 was produced (see Reference 1.5.21).

Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MVT-1 method (such as for CRGT-2 and CRGT-3) with the EVT-1 method. These EVT-1 inspections may be performed from the ID of the guide tubes in conjunction with the blade change-out procedure. A minimum of five CRD guide tubes must have these inspections performed within the first six-year interval, and a minimum of nine must be performed within the next twelve years.

The stub tubes do not require inspection per BWRVIP-47.

Appendix B PP 7027 Rev. 3 Page 2 of 65

APPENDIX B (Continued)

The BWRVlP stated in response to NRC SE Issue 3.2.2 (Reference 1.5.13) that when utilities have access to the lower plenum due to maintenance activities not related to the inspection recommendations of the BWRVIP, they will have the opportunity to perform a visual inspection of a portion of the lower plenum and that results of this inspection will be reported to the BWRVIP. This will be treated as a commitment for those items listed in 1.2below in the event that Relief Request RI-01 is accepted.

1.2. ASME Section XI Applicability The CRD housings and stub tubes are part of the core support structure and are integrally welded.

i Therefore, the CRD housings and stub tubes will be examined in accordance with ASME Section XI, Table IWB-2500-1, Category B-N-2, Item B13.40, "Core Support Structure". Table TWB-2500-1 requires accessible surfaces to be visually inspected by the VT-3 method once per ten-year interval. VY has submitted a Relief Request (RI-01) for the fourth ten-year Section XI interval that would allow using the BWRVIP guidance rather than the Section XI Categories B-N-1 and B-N-2 requirements. VY will perform inspections accordingly, based on the outcome of the Relief Request. These surfaces are not accessible during the normal course of a refueling outage and would only be accessible if there were another reason to gain access below the core plate. The last time this area was accessible and, therefore, inspected was in 1983. Because this Occurrence is so rare, any time that there is an opportunity for this ASME Section XI inspection, it must be used. The inspection would include the control rod drive housing, control rod drive housing-to-stub weld, and the stub tube-to-vessel weld.

1.3. Other Commitments - None.

1.4. Inspections for Risk to Generation Purposes - None.

1-5. References 1.5.1. GE RICSIL No. 042, dated June 7,1989, "BWR Under-Vessel Leakage"  !

1.5.2. Letter J. W. Lukas (GE) to M. P. Benoit, September 29, 1993, "Guide Tube Integrity" I.

1.5.3. Memorandum M. P. Benoit to J. T. Herron, October I, 1993, "Recommendation On Reuse of Guide Tube 22-15" 1.5.4. Memorandum F.J. Helin to J. R. Hoffman,July 8,1994, "VY Guide Tube" 1.5.5. Memorandum F. J. Helin to AP0028 File 'UND94010', November 7, 1994, "Reuse of Guide Tube 22-15" ,

1.5.6. GE Nuclear Energy Report GE-NE-523-A190-1294DRF 137-0010-7, December 1994, "Vermont Yankee Control Rod Guide Tube Impact Analysis" 1.5.7. BWRVIP-03, dated October 1995, "Reactor Pressure Vessel and Internals Examination Guidelines" 1.5.8. Memorandurn E. J. Taintor to D. C. Girroir, dated October 20, 1995, "Inservice Inspection of Vessel Internal Items Located Below the Core Support Plate" 1.5.9. BWRVIP-47, dated December 1997, "BWR Lower Plenum Inspection and Haw Evaluation Guidelines" 1.5.10. BWRWP-55, dated September 1998, "Lower Plenum Repair Design Criteria" 1.5.11. BWRVIP-58, dated December 1998, "CRD Internal Access Weld Repair" Appendix B PP 7027 Rev. 3 Page 3 of 65

APPENDIX B (Continued) 1.5.12. Letter Vermont Yankee to USNRC, dated May 27, 1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 1.5.13. Letter BWRvIp to USNRC, dated June 2, 1999, "BWRVIP Response to NRC SE on BWRVIP-47" 1.5.14. Letter USNRC to BWRVIP,dated October 13, 1999, "Final Safety Evaluation of

'BWVIP, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines (BWRVIP-47),' EPRI Report TR-108727, (TAC No. MA1 102)"

1.5.15. Letter NRC to BWRVIP, dated December 7,2000, "Acceptance for Referencing of BWRvIp, BWR Lower Plenum Inspection and Evaluation Guidelines (BWRvIp-47) for Compliance with the License Renewal Rule (10 CER Part 54)"

1.5.16. Memorandum T. G. Stetson to Outage 22 File, dated January 25,2001, "2001Refuel Outage Blade Changeout Recommendation" 1.5.17. Action Item / Regulatory Commitment BWRVIP-047-01, dated November 28,2001 1.5.18. Action Item / Regulatory Commitment BWRVIP-047-A-01, dated August 5,2002 1.5.19. Action Item / Regulatory Commitment UND-2002-282-01, dated December 12,2002 1.5.20. Action Item / Regulatory Commitment SEN-238-01, dated June 3,2002 1.5.21. Technical Justification 2003-03, dated August 18,2003, "Justification to Perform Less Than 5% of CRD Guide T 2.0 Core Plate 2.1.

BWRVP-25 governs inspection of th ore plate. Vermont Yankee was not able to complete the minimum required inspections in BWRVIP-25 as of the date of publication of that document December 1997), and Vermont Yankee has not performed an inspection that would comply with this document as of yet. Therefore, Vermont Yankee is not in compliance with BWRVIP-94 for this component (compliance within two cycles following the publication of BWRW-25). Also, per BWRVIP-94, Vermont Yankee is required to notify the BWRVIP that VY will not be performing inspections in accordance with BWRVIP-25, until such time as this is possible.

Vermont Yankee is w planning to install core plate wedges. Table 3-2 of BWRVIP-25 requires an EVT-1 inspection below the core plate of the rim hold-down bolts for BWW4 plants without installed wedges. As an alternative, a UT of these bolts may be performed from the top.

Vermont Yankee did not or will not perform either of these examinations in RFO 21 (1999),

RFO 22 (2001), RFO 23 (2002), or RFO 24 (2004) due to the difficulty of removing CRD guide tubes for the EVT-1 (this amount of vessel disassembly is not normally performed during a refueling outage), and because no tooling now exists to perform the UT.

Appendix B PP 7027 Rev. 3 Page 4 of 65

APPENDIX B (Continued)

In the absence of cure plate wedges during RFO 21 (1999), and RFO 22 (2001), and RFO 23 (2002), the tops of 50% of the core plate rim hold-down bolts were inspected during each outage with the VT-3 method. The NRC was notified that this was an alternative examination to EVT-1 from beneath the core plate, as stipulated in Table 3-2 of BWRVIP-25 for B W 4 plants without installed wedges (see References 2.5.17 and 2.5.19). In RFO 24 (2004), VY will again inspect 4 50% of the core plate rim hold-down bolts with the VT-3 method. Technical Justification TJ-2004-01 was prepared in accordance with PP 7027, Paragraph 4.2.3 and BWRVIP-94 to perform this alternative examination (50%every other refueling outage) until such time that tooling to perfom UT of the rim hold-down bolts becomes available. I Internal commitments in References 2.5.7 and 2.5.9 below to address S E No. 588 will no longer be applicable with periodic inspection of the core plate rim hold-down bolts (or if core plate 1 wedges were installed). These commitments are considered revised accordingly, with the issuance of PP 7027.

If new core plate wedges are ever installed, they may require some periodic inspection.

I . s BWRW-50, Paragraph 10.2, states, "Inspections required for the entire repaired top guidekore I L

plate structures for the remaining life of the unit, shall be specified commensurate with design 1.-

considerations and code requirements applicable to the specific design. This shall include inspections of the repair hardware and inspection of the reactor internal components utilized for repair anchorage." These inspection requirements would be delivered as a piece of the wedge design scope. Barring any guidance, the new wedges would all be reinspected after one cycle of operation. Thereafter, two wedges would be alternately inspected every third outage. This would ensure that all four core plate wedges are inspected every ten years.

I Core plate plugs will reach their end of life (14 EFPY) in the cycle following RFO 25 according to Reference 2.5.21. This will require that the plugs be replaced or re-evaluated. 1 The B W R W stated in response to NRC SE Issue'3.2.2(Reference 1.5.13)that when utilities have access to the lower plenum due to maintenance activities not related to the inspection recommendations of the BWRVIP, they will have the opportunity to perform a visual inspection I of a portion of the lower plenum and that results of this inspection will be reported to the BWRVIP. This will be treated as a commitment for those items listed in 2.4 below. i 2.2. ASME?Section XI Atqlicabilitv f1 The core plate is part of the core support structure; however, the core plate is not integrally I

welded as stated in the title of ASME Section XI, Table IWB-2500-1, Category B-N-2.

Therefore the core plate is not subject to ASME Section X I (see Reference 2.5.15 below).

I 2.3. Other Commitments - None. I Appendix B PP 7027 Rev. 3 Page 5 of 65

APPENDIX B (Continued) 2.4. . Inspections for Risk to Generation Purposes The only surfaces accessible for visual inspection would be on the underside of the core plate and these surfaces are not accessible during the normal course of a refueling outage. They would only be accessible if there were another reason to gain access below the core plate. The last time this area was accessible and was inspected was in 1983. Because this occurrence is so rare, any time that there is an opportunity for inspection, it should be used. This nonmandatory inspection would include accessible core plate beam fillet welds, rim hold-down bolts and alignment hardware. The rim hold-down bolts and alignment hardware would not be considered a part of the safety-related core support structure when the core plate wedges are in place; however, they would be inspected from underneath the core plate for loose part considerations when accessible for other reasons.

2.5. References 2.5.1. Letter from Paul J. Kinder, GENE, to BWR Owners Group Core Plate Plug Evaluation Committee, dated August 11,1992, "Transmittal of Final Evaluation Report" 2.5.2. GE RICSIL No. 071, Revision 0, dated November 22, 1994, "Top Guide and Core Plate Cracking" 2.5.3. Letter from BWRVlP to USNRC, dated January 3,1995, "Request for Information Regarding the Impact of BWR Core Plate and Top Guide Ring Cracking" 2.5.4. GE SIL No. 588, dated February 17, 1995, "Top Guide and Core Plate Cracking" 2.5.5. NRC Information Notice 95-17, dated March 10,1995, "Reactor Vessel Top Guide and Co ngtr 2.5.6. GE SIL No. 588, Revision 1, dated May 18, 1995, "Top Guide and Core Plate Cracking" 2.5.7. Memorandum T. G. Stetson to R. E. McCullough, dated February 5,1996, "Response to Commitment SILO588 on Top Guide and core Plate Cracking" 2.5.8. Memorandum T. G. Stetson to R. E. McCullough, dated February 5,1996, "Response to Commitment INF 95017 on Top Guide and core Plate Cracking" 2.5.9. Memorandum T. G. Stetson to R. E. McCulIough, dated July 11,1996, "Response to Commitment SILO588-01" 2.5.10. BWRVIP-25, dated December 1996, "BWR Core Plate Inspection and Flaw Evaluation Guidelines" 2.5.11. Letter Vermont Yankee to NRC, dated September 30, 1997, "Vermont Yankee's Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Intemals" 2.5.12. Letter NRC to Vermont Yankee, dated March 25,1998, "Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals - Vermont Yankee Nuclear Power Station" 2.5.13. BWRVIP-50, dated May 1998, "Top GuideKOre Plate Repair Design Criteria" 2.5.14. Memorandum E. J. Taintor to D. C. Girroir, dated April 23, 1999, "Accessibility Following Installation of Proposed Top Guide and Core Support Assemblies" 2.5.15. Memorandum C. B. Larsen to D. C. Girroir, dated May 13, 1999, "Definition of Core Support Structures (ASME Section XI, Category B-N-2)"

Appendix B PP 7027 Rev. 3 Page 6 of 65

APPENDIX B (Continued) 2.5.16. Letter Vermont Yankee to USNRC, dated May 27, 1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 2.5.17. Letter Vermont Yankee to USNRC, dated October 29,1999, BVY 99-137, "Deferral of Top Guide and Core Plate Wedge Installation" 2.5.18. Letter USNRC to BWRVIP, dated December 19, 1999, "Final Safety Evaluation of

'BWR Core Plate Inspection and Flaw Evaluation Guideline ( B W " - 2 5 ) , ' EPRI Report TR-107284, December 1996 (TAC No. M97802)"

2.5.19. Letter Vermont Yankee to USNRC, dated September 26,2000, BVY 00-89, "Cancellation of Top Guide and Core Plate Wedge Installation" 2.5.20. Letter NRC to BWRVIP, dated December 7,2000, "Acceptance for Referencing of BWRVIP, BWR Core Plate Inspection and Evaluation Guidelines (BWRVIP-25)

Report for Compliance with the License Renewal Rule (10 CFR Part 54) and Appendix B, BWR Core Plate Demonstration of Compliance with the Technical Information Requirements of the License Renewal Rule" 2.5.21. Memorandum T. G. Stetson to Core Plate Plug Lifetime File, dated May 15,2003, "Surveillance 9021 on Core Plate Plug Removal" I 2.5.22. Technical Justification 2OO4-0 1, dated 03/26/04, "Justification for Alternative Inspection of Core Plate Rim Hold-down Bolts" 3.0 Core Shroud (Includin~Tie Rod Repair and Spacer Rind 3.1. BWRVIP Document Applicability BWRW-01, published in September 1994, governed the baseline inspection of the horizontal welds in the core shroud. Vermont Yankee completed its baseline examination of the horizontal welds in RFO 18 (1995). As a result of this baseline examination, Vermont Yankee installed a tie-rod repair of the core shroud horizontal welds in RFO 19 (1996). BWRVIP-07, published in February 1996, governed reinspection of the core shroud welds and associated repairs. Vermont Yankee performed a baseline examination of the vertical welds in RFO 19 (1996). BWRVIP-63 governed inspection of the core shroud vertical welds. BWRW-76 was issued in November 1999, with the intent of subsuming BWRVIP-01, BWRW-07, and BWRW-63. Vermont Yankee has complied with these documents as of their publication.

Appendix B PP 7027 Rev. 3 Page 7 of 65

APPENDIX B (Continued) 3.1.1. Core Shroud Horizontal Welds - Per UFSAR, Appendix K, the tie-rod repair has structurally replaced core shroud horizontal welds H3 through H7. Therefore, in accordance with BWRVIP-07, Paragraph 4.4.1.1, and BWRVIP-76, Section 3.2, horizontal welds H3 through H7 do not require any further inspection. Welds H1 and H2 are considered design-reliant welds for the tie-rod repair. ER 2001-2481 (Reference 3.5.75) identified additional design-reliant welds for the shroud repair.

The corrective action for this ER was to examine portions of H1, H2,and H3 in place of these other structures (which included the top guide support blocks). Accordingly, weld H3 will also be considered design-reliant. Technical Evaluation 2004-0018 (Reference 3.5.83) provides the basis for this decision. The reinspection frequency of "un-repaired (design-reliant) horizontal welds is established in BWRVIP-76, Section 3.2, and Figure 3-1, which reference Figure 2-3 and Table 2-1. That frequency is ten years for welds that underwent UT and had minimal cracking (less than lo%),such as H1, H2,and H3.The NRC, in Reference 3.5.72, c with this determination.

The next required examination would therefore be in RFO 24 (2004 (nine years later).

Vermont Yankee has elected not to perform 100%of the accessible length of these welds in accordance with Technical lhaluation 2004-0018 (Reference 3.5.83) as would have been required. Appendix K of the FSAR will be revised accordingly.

Venn has also elected to perform these exams by EVT-1, Per BWR gure 2-3, a full volumetric andor two-sided surface technique is required. At VY, the inside of the shroud is not accessible at H1, H2,and H3 tospray spargers cover H1 and H2 and because of the ery of the top guide, access to the shroud ID would be through vacated fuel cells, and this would result in the camera being too distant from the inspection surfaces to perform an adequate EVT-1 of H1, H2,or H3. Technical Evaluation 2004-0018 (Reference 3.5.83) provides the basis for a one-sided EVT-1, as well. Following the RFO 24 (2004) inspection, horizontal welds will again require inspection in RFO 28 (2010), per Technical Evaluation 2004-0018 (Reference 3.5.83). Although no BWRVIP guidance is given for one-sided visual examinations of horizontal welds, this six-year inspection frequency follows the guidance for a one-sided EVT-1 of vertical welds per BWRVIP-76, Figure 3-3.

Appendix B PP 7027 Rev. 3 Page 8 of 65

APPENDIX B (Continued) 3.1.2. Core Shroud Vertical and Ring Segment Welds - The vertical and ring segment welds were inspected in RFO 19 (1996) in conjunction with the tie-rod installation. Option "A" of BWRVIP-07, Paragraphs 4.4.1.4 and 4.4.2.2, required that a minimum uncracked length be determined for both vertical and ring segment welds. For Vermont Yankee, MPR - the designer of the tie-rod repair - determined that this minimum length would be 41 inches (including allowance for crack growth rate).

The RFO 19 (1996) inspection verified this minimum ligament for each vertical weld.

Six ring segment welds received full coverage, except for one top guide ring segment weld (S3R3), which received 80%coverage due to a scanning limitation. No flaws were found. At the time the only document governing shroud vertical welds was BWRVIP-07, which followed the methodology used above for inspecting minimum ligaments for structural integrity. The Vermont Yankee RFO 19 (1996) vertical weld inspection met this criterion. Subsequently, BWRVIP-63 was issued, which required in Section 3.2, Option A, that 100%of the accessible length of all vertical welds (between H3 and H7 in Vermont Yankee's case) in repaired shrouds be inspected.

BWRVIP-76, which was issued later, echoes this requirement. The reason that the vertical welds between H1 and H2 do not require inspection is that per BWRVIP-63, Section 3.1.1, or BWRVIP-76, Section 2.3.3.1, no inspection is required for vertical iI 1

welds if the as found cracking in each horizontal weld at the ends of the vertical welds is less than 10%of the inspected length. This was as documented for the H1 and H2 1 I

welds in the 1995 inspection. Technical Evaluation 2OO4-OO18 (Reference 3.5.83) provides the new basis for not inspecting the vertical welds between H1 and H2 going forward. Appendix K of the FSAR will be revised accordingly. The W O 19 (1996) I I

vertical weld inspection achieved 100%of all the accessible areas, with the exception of welds S5V1 and S5V2. Although more coverage could have been obtained on I these welds, 56.5% and 68.3%was achieved, respectively. Vermont Yankee will I comply with the BWRVIP coverage requirements in effect at the time of the next required reinspection. The reinspection frequency of vertical welds is found in BWRVIP-76, Figure 3-3. For vertical welds that were examined volumetrically and found to have no cracking, the inspection interval is ten years. Therefore, the next required inspection of the vertical welds would be in RFO 25 (2005 (nine years later). i.

Technical Evaluation 2004-0018 provides the basis for only inspecting the OD of the vertical welds. During RFO 24, the vertical welds were inspected by EVT-1.

Therefore, these welds shall be reinspected in RFO 28 (2010) (BWRVIP-76 t . I Figure 3.3).

f Appendix B PP 7027 Rev. 3 Page 9 of 65

APPENDIX B (Continued)

The RFO 19 (1996) examination included the six ring segment welds in the rings at the top guide and core plate. The three ring segment welds in the shroud flange were not examined based on the good results obtained on weld H1 in RFO 18 (1995).

Weld H1 will be used to ensure that the shroud flange (top ring) segment welds have sufficient design reliant weld length; therefore, the top ring segment welds will not be inspected. BWRVIP-07 did not require inspection of the shroud flange ring segment welds. BWRVP-76 states that the repair designer should establish the need to inspect ring segment welds; if the repair designer is able to demonstrate that the repair hardware does not rely on the integrity of particular ring segment welds in order for it i to function properly, then no inspection is necessary. Technical Evaluation 2004-0018 (Reference 3.5.83) states that only the ring segment welds at the core plate will be required for future inspections. Welds H1, H2,and H3 will need to be inspected one cycle sooner than the ring segment and vertical welds, because welds H1 and H2 were examined in RFO 18 (1995); the other welds were examined in RFO 19 (1996). The core plate ring segment welds were inspected by EVT-1 during RFO 24 and shall be reinspected in W O 28 (2010). (BWRW-76 Section 3.4) 3.1.3. Core Shroud Tie-Rod Repair - BWRVIP-07, Paragraph 4.2, contained requirements for inspection of repair components of core shrouds. It required a VT-3 of critical areas of 25%of the repair assemblies following the first operating cycle after repair installation and every ten years thereafter of all assemblies. The NRC requested that utilities perform this inspection of 100%of the assemblies following the first cycle of operation, in light of the Nine Mile Point 1 incident. The repair was installed in RFO 19 (1996) and Vermont Yankee satisfied the first-cycle inspection requirement in RFO 20 (1998). However, the tie-rods were retorqued to a higher value during that outage. Therefore, Vermont Yankee considered the repair a new installation and reinspected all four of the tie-rods again in RFO 21 (1999). If the tie-rods are to be retorqued again, a baseline inspection should be performed following that activity and the tie-rods should be examined again following one cycle of operation.

BWRVIP-76 has now replaced BWRVIP-07. BWRVIP-76, Paragraph 3.5,Option 1, which makes the best sense for Vermont Yankee, requires reinspection of repair component assemblies once every ten ye r a first cycle inspection. Vermont Yankee decided the best way to comply was to perform inspection of two tie rods every three outages.

MPR, the designer of the tie-rod repair, has designated inspection requirements (all by the VT-3 method) for the tie-rods. The inservice inspection requirements were derived from the MPR installation (PSI) inspection requirements. (Reference 3.5.47)

Appendix B PP 7027 Rev. 3 Page 10 of 65

APPENDIX B (Continued) 3.2. ASME Section XI Amlicabilitv i

The core shroud is part of the core support structure, Therefore the core shroud will be examined in accordance with ASME Section XI, Table IWB-2500-1, Category B-N-2, Item B13.40, "Core Support Structure". Table IWB-2500-1 requires accessible surfaces to be visually inspected by the VT-3 method once per ten-year interval. This was conducted during RFO 23 (2002) for the third ten-year Section XI interval, VY has submitted a Relief Request (RI-01) for the fourth ten-year Section XI interval that would allow using the BWRVIP guidance rather than the Section XI Categories 3-N-1 and B-N-2 requirements. VY will perform inspections accordingly, i

based on the outcome of the Relief Request.

3.3. Other Commitments - None. i 3.4. Inspections for Risk to Generation Pumoses - None.

3.5. References L.

3.5.1. GE RICSIL No. 054, Dated October 9, 1990, "Core Support Shroud Crack Indications" 3.5.2. Memorandum E. J. Betti to J. R. Hoffman, dated October 26,1990, "RICSIL No. 054, Core Support Crack Indications" 3.5.3. Memorandum T. G. Stetson to C. B. Cameron, dated December 26, 1990, "Response to Commitment RICSLO054, Core Support Shroud Crack Indications" 3.5.4. Memorandum T. G. Stetson to C. B. Cameron, dated February 15,1991, "Delaying Commitment RICSILO054REl 'I 3.5.5. Memorandum T. G. Stetson to R. E. McCullough, dated July 17, 1991, "Response to Commitment RICSIL0054REl" 3.5.6. Letter C. B. Cameron to A. D. Himle, dated July 22, 1991, regarding SIL 462, RICSU54, RICSlL059 and GE support for possible inspection findings P

3.5.7. OP 1428, Issued January 15, 1992, "Core Shroud Support Visual Inspection" 3.5.8. GE RICSIL No. 054 Revision 1, Dated July 21, 1993, "Core Support Shroud Crack Indications" 3.5.9. Memorandum T. G. Stetson to R. E. McCullough, dated August 9, 1993, "Response to Commitment RICSTLoO54R1" 3.5.10. NRC Information Notice 93-79, dated September 30, 1993, "Core Shroud Cracking i!

At Beltline Region Welds In Boiling Water Reactors" 3.5.11. Letter Michael E. Shepherd to D. A. Reid, dated October 4, 1993, "GE Nuclear Energy SIL No. 572" 3.5.12. GE SIL No. 572, dated October 1, 1993, "Core Shroud Cracks" 3.5.13. GE SIL No. 572, Revision 1, dated October 4, 1993, "Core Shroud Cracks" 3.5.14. Memorandum J. R. Hoffman to S. R. Miller, dated October 12, 1993, "Independent Assessment of R&CE Inspection of Vermont Yankee Core Shroud" 3.5.15. Memorandum W. F. Miller (GE) to M. P. Benoit, dated October 27, 1993, "Summary of Vermont Yankee Core Shroud Visual Examinations During RF017" Appendix B PP 7027 Rev. 3 Page 1 1 of 65

APPENDIX B (Continued) 3.5.16. Memorandum Jim Brooks to Rick McCullough, dated November 19,1993, "Review of NRC Information Notice 93-79: Core Shroud Cracking At Beltline Region Welds In Boiling Water Reactors, and SEN 103, Circumferential Crack of a Boiling Water Reactor Core Shroud" 3.5.17. Memorandum T. G. Stetson to R. E. McCullough, dated February 14,1994, "Response to Commitment SILO572R1 On Core Shroud Cracks" 3.5.18. GE RICSXL No. 068, dated April 8, 1994, YJpdate On Core Shroud Cracking" 3.5.19. GE RICSIL No. 068, Revision 2, dated May 6, 1994, "Update On Core Shroud Cracking" 3.5.20. NRC Information Notice 94-42, dated June 7,1994, "Cracking In the Lower Region of the Core Shroud In Boiling Water Reactors" 3.5.21. Memorandum T. G. Stetson to R. E. McCullough, dated July 11, 1994, "Response to Commitment RICSILO05 3.5.22. Memorandum T. G. Stetson to R. E. McCullough, dated July 12,1994, "Response to Commitment NCSIL06 8" 35 2 3 . Letter BWROG to US ted July 13,1994, "Response to NRC Request for Shroud Information" 3.5.24. NRC Information Notice 94-42, Supplement 1, dated July 19,1994, "Cracking In the Lower Region of the Core Shroud In Boiling Water Reactors" 3.5.25. NRC Generic Letter 94-03, dated July 25,1994, "Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling Water Reactors" 3.5.26. Letter BWROG to USNRC,dated August 5,1994, "Revision 1 to BWROG Shroud Document" 3.5.27. Letter VY to USNRC, BVY 94-82, dated August 17,1994, "Response to USNRC Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds in BWRS" 3.5.28. BWRVIP-01, dated September 1 ud Inspection and Raw Evaluation Guidelines" 3.5.29. BWRVIP-02, Revision 1, dated September 1994, "BWR Core Shroud Repair Criteria" 3.5.30. Memorandum Bryan Croke to Mark Palionis, dated September 27,1994, "NRC Information Notice 94-42, Cracking In the Lower Region of the Core Shroud In Boiling Water Reactors" 3.5.31. Memorandum Bryan Croke to Mark Palionis, dated September 27,1994, "NRC Information Notice 94-42 Supplement 1, Cracking In the Lower Region of the Core Shroud In Boiling Water Reactors" 3.5.32. BWRVIP Core Shroud NDE Uncertainty & Procedure Standard, dated November 21, 1994 3.5.33. Letter VY to USNRC, BVY 94-125, dated December 15, 1994, "Vermont Yankee Plans to Inspect the Core Shroud Circumferential Welds During the Spring 1995 Refueling Outage" 3.5.34. Letter USNRC to VY, NVY 95-01, dated January 5, 1995, "Safety Evaluation for Vermont Yankee Nuclear Power Station Regarding Generic Letter 94-03, "Intergranular Stress Corrosion Cracking of Core Shrouds In Boiling Water Reactors" 3.5.35. Letter USNRC to VY, NVY 95-22, dated March 14,1995, "Summary of March 9, 1995, Meeting with Representatives of Vermont Yankee Nuclear Power Corporation" Appendix B PP 7027 Rev. 3 Page 12 of 65

- ,, - ~ E.- I APPENDIX B (Continued) 3.5.36. BWRVIP Report, dated April 1995, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines Revision 1 I' 3.5.37. Letter VY to USNRC, BVY 95-45, dated April 21,1995, "Vermont Yankee 1995 Outage Core Shroud Inspection" 3.5.38. Letter USNRC to VY, NVY 95-52, dated April 25, 1995 "Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds In Boiling Water Reactors, Vermont Yankee NucIear Power Station" 3.5.39. Memorandum D. C. Girroir to J. M. DeVincentis, dated April 26, 1995, "CAT A Item

1. GENLETR9403MEC3, re. Core Shroud Inspections

3.5.40. B&W Nuclear Technologies Report dated April 27, 1995, "1995 Vermont Yankee Nuclear Power Corporation Project File Report for Core Shroud Examinations" 3.5.41. Letter USNRC to VY, NVY 95-55, dated April 27,1995, "Core Shroud Inspection and Flaw Evaluation, Vermont Yankee Nuclear Power Station" (Safety Evaluation Attached) 3.5.42. Letter VY to USNRC, BVY 95-55, dated May 24,1995, "Generic Letter 94-03, i 1

htergranular Stress Corrosion Cracking of Core Shrouds in BWRs" 3.5.43. BWRVIP-04, dated October 1995, "Guide for Format and Content of Core Shroud Repair Design Submittals" I .-

3.5.44. BWRVIP-07, dated February 1996, "Guidelines for Reinspection of B W R Core Shrouds" I 3.5.45. NUREG-1 544, dated March 1996, "Status Report: Intergranular Stress Corrosion i Cracking of BWR Core Shrouds and Other Internal Components" I 3.5.46. Letter Vermont Yankee to USNRC, dated April 15,1996, "Vermont Yankee Core I Shroud Modification" 3.5.47. MPR-1730, Revision 0, dated April 1996, "Vermont Yankee Nuclear Power Station 1:

Core Shroud Repair - Design Report" 3.5.48. GE RICSIL No. 077, May 30, 1996, "Core Shroud Vertical Weld Cracking" 3.5.49. Operating Experience Information Review, dated June 10,1996, "RICSMf77" 3.5.50. Memorandum D. C. Girroir to P. B. Corbett, July 10, 1996, "CAT A Item

1. GENLETR9403MEC4, Discuss Core Shroud with NRC" I I

3.5.51. VYS-046, Revision 2, dated July 26, 1996, "Design, Fabrication, and Installation I Services for Reactor Pressure Vessel Core Shroud Repair at Vermont Yankee Nuclear 3.5.52.

Power Station" Operating Experience Information Review, dated September 23, 1996, "Procedure f

Revisions To Reflect Core Shroud Modification" I BWRVIP-01, dated October 1996, "BWR Core Shroud Inspection and Flaw I 3.5.53. 1 Evaluation Guideline, Revision 2" 325-54. Letter USNRC to Vermont Yankee, NVY 96-153, dated October 2, 1996, "Safety  !

Evaluation Regarding the Vermont Yankee Core Shroud Repair P A C No. M95207)"

3.5.55. Memorandum J. R. Hoffman to J. J. Duffy, dated October 8, 1996, "Review of USNRC SER for Shroud Repair" 3.5.56. Memorandum W. D. Fields to J. J. Duffy, dated November 25,1996, "Core Shroud Repair Inspections" 3.5.57. Framatome Technologies Report dated December 18,1996, "1996 Vermont Yankee Nuclear Power Corporation Project File Report for Core Shroud Examinations of the Vertical, Ring Segment, and H8/H9 Baffle Plate Welds" Appendix B PP 7027 Rev. 3 Page 13 of 65

APPENDIX B (Continued) 3.5.58. Vermont Yankee Final Safety Analysis Report, Revision 14, dated November 5, 1997, Appendix K, "Core Shroud Repair" 3 s.59. Letter P. Butler (MPR) to D. Winterich 0, dated April 9, 1997, "BWR Core Shroud Repair Problems" 3.5.60. GE RICSIL No. 079, dated April 15,1997, "Cracking of Vertical Welds On Core Shroud Outer Surface" 3.5.61. NRC Information Notice 97-17, +ted April 17,1997, "Cracking of Vertical Welds In the Core Shroud and Degraded Repair" 3.5.62. Memorandum D. C. Girroir to P. B. Corbett, dated May 18,1997, "GE RICSJL 079 Response (AP0028, CAT A Item)"

3.5.63. Memorandum D. C. Girroir to P. B. Corbett, dated June 18,1997, "NRC Info Notice 97-17 (AP 0028 Item)"

3.5.64. Memorandum J. R. Hoffman to R. E. McCullough, dated September 5,1997, "AP0028for Core Shroud Tie Rod Retensioning" 3.5.65. Letter Vermont Yankee to NRC dated September 30,1997, "Vermont Yankee's Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals" 3.5.66. Letter NRC to Vermont Yankee dated March 25,1998, "Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Intemals - Vermont Yankee Nuclear Power Station" 35 6 7 . BWRVP-02, Revision 2, dated March 1999, "BWR Core Shroud Repair Criteria" 3.5.68. Letter Vermont Yankee to USNRC, dated May 27,1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 3.5.69. BWRVIPl63, dated June 1999, "BWR-Vessel and Internals Project Shroud Vertical Weld Inspection and Evaluation Guidelines" 3.5.70. Letter William Bateman,'NRC, to Cai.fTerry, BWRVIP, dated August 13,1999, "Staff Reevaluation of Table 1 in the BWRVIP-07 Report (TAC No. M94959)"

3.5.71. BWRVIP-76, dated November 1999, "BWR Vessel and Internals Project BWR Core Shroud Inspection and Evaluation Guidelines" 3.5.72. Letter NRC to BWRVIP,dated April 18,2000, "Safety Evaluation of the "BWRVIP, S Vertical Weld Inspection aid Evaluation Guidelines (BWRVIP-63)," EPRI Report TR-113170, June 1999 (TAC No. MA6015) 3.5.73. BWRVIP-080, dated May 2000, "Evaluation of Crack Growth in B W R Shroud Vertical Welds" 3.5.74. Letter BWRVIP to all Committee Members, dated October 23,2000, "Modification to Core Shroud I&E Guidelines (BWRW-63 and BWRVIP-76)"

3.5.75. Event Report 2001-2481, Dated December 3,2001, "BWRVIP Documentation" 3.5.76. Action Item / Regulatory Commitment ER-2001-2481-01, dated January 9,2002, "Investigate Options" 3.5.77. Action Item / Regulatory Commitment UND-2002-074-13, dated March 22,2002, "Assess the need to inspect radial ring segment welds in the shroud flange and top guide support plates

3.5.78. Action Item / Regulatory Commitment BWRVIP-04-A-01, dated June 6,2002, "Evaluate BWRVIP-04-A and define solutions as required" 3.5.79. Action Item / Regulatory Commitment BWRVIP-04-A-02, dated June 20,2002, "Revise PP 7027 - Shroud Repair Submittal Format" Appendix B PP 7027 Rev. 3 Page 14 of 65

APPENDIX B (Continued) 3.5.80. Event Report 2003-0267, initiated January 31,2003, "New RPV Internals Generated by GE for ARTSNEUA Project that have Not Been Previously Considered by VY" 3.5.81. Letter USNRC to BWRVIP, dated February 19,2003, "Safety Evaluation of 'BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Shroud Vertical Welds (BWRVIP-80)'"

3.5.82. Action Item / Regulatory Commitment BWRVIP-100-03, dated July 15,2003 3.5.83. Technical Evaluation 2004-0018, "Justification to Inspect Portions of Shroud Horizontal Welds H1, H2,and H3 on the OD in Lieu of the Top Guide Spacer Block Welds, the Shroud Flange Ring Segment Welds, and the Top Guide Ring Segment Welds I' 4.0 Core Shroud Support (Including Access Hole Cover) 4.1. BW R W Document Apulicability BWRVIP-38, published in September 1997, governs inspection of the core shroud support, with the exception of the access hole cover. Vermont Yankee has complied with this document as of its publication. The BWRVlP has not yet prepared an inspection and evaluation guideline that addresses the access hole cover.

In RFO 19 (1996) Vermont Yankee performed an inspection of welds H8 and H9 which meets the requirements of BWRVP-38 for a baseline examination. The following describes the rationale for this statement. The baseline strategies for welds H8 and H9 are shown in Figures 3-4 and 3-5 of BWRVIP-38. The load multiplier is determined from Table 5-1. In Vermont Yankee's case this is 0.41. The flaw tolerance is determined from Figures 5-1 (for H8) and 5-2 (for H9) for plants with support legs, For both welds the flaw tolerance is 100%. The minimum examination coverage for a flaw tolerance of 100% is 10%for both H8 and H9. The coverage was 25% for weld H8 and 22% for weld H9 during the RFO 19 (1996) examination. No flaws were found. Therefore an adequate baseline of welds H8 and 39 was performed.

No welds other than H8 and H9 require examination in accordance with BWRVIP-38 for a plant with Vermont Yankee's core shroud support configuration.

The reinspection interval is established in BWRW-38, Paragraph 3.3.2, which states that, "ifno flaws were found during the previous inspection, reinspections are performed on ten-year intervals if U T techniques were used.. The RFO 19 (1996) H8 and H9 examination was an

.I' ultrasonic test augmented with eddy current and no flaws were found. Therefore the reinspection interval is ten years if UT techniques are used, and six years if EVT-1 techniques are used (but see below). Accordingly, reinspection of H8 and H9 are due in RFO 25 (2005), nine years following the baseline exam. (Examination in RFO 26 (2007) would be six months late.)

Appendix B PP 7027 Rev. 3 Page 15 of 65

APPENDIX B (Continued)

BWRVIP-104 was issued in September 2002 to address extensive transverse cracking at the Tsuruga plant. BWRVIP-104, Section 9 revises the guidance of BWRVIP-38 for weld H9.

Section 9.2.1requires that an EVT-1 visual examination, or ultrasonic examination, of both top and bottom surfaces of the H9 weld. Therefore, the option in BWRVIP-38 to perform an EVT-1 examination of just the top surface at a six-year frequency is voided. Section 9.2.3 requires that the ultrasonic examination technique be capable of detection of both axial and circumferential flaws in the weld material and be able to determine whether the flaws have propagated into the RPV low alloy steel. This also effectively deletes the EVT-1 option. Section 9.2.5 further states, "An ultrasonic examination from the RPV ID is an acceptable alternative if OD access is limited (an OD exam is preferred). UT from the ID may require additional flaw evaluation or inspection sampling due to current limitations in flaw characterization in the low alloy steel." Per BWRVIP-94, new BWRVIP guidance is required to be implemented within two outages. Per PP 7027, Paragraph 4.2.lb, new BWRVIP guidance is required to be implemented within 16 months if it pertains to UT. This latter more restrictive requirement would require that VY implement the new BWRVIP-104 requirements in RPO 24(2004). However, no examination technique from the ID has been demonstrated to detect or size transverse flaws. Therefore, Technical Justification 2004-04 (Reference 4.5.39) was prepared because VY cannot meet BWRW-104. The BWRVIP has a 2004 budget and schedule item to attempt to demonstrate detection of transverse flaws from the vessel 03,but even if detection is demonstrated, it is highly unlikely that the technique will be able to determine if the flaws penetrate the RPV low alloy steel. Therefore, VY will postpone inspection of weld H9 until the originally scheduled time in RFO 25 (2005) and use the best demonstrated techniques available at that time. If a technique to detect transverse flaws from the ID becomes available, VY would reassess the feasibility of inspecting weld H9 accordingly at that time. Otherwise, the Technical Justification will remain in effect.

The BWRVIP stated in response to NRC SE Issue 3.2.2 (Reference 1.5.13) that when utilities have access to the lower plenum due to maintenance activities not related to the inspection recommendations of the B W R W , they will have the opportunity to perform a visual inspection of a portion of the lower plenum and that results of this inspection will be reported to the BWRVIP. This will be treated as a commitment for those items below the baffle plate listed in 4.2 below in the event that Relief Request RI-01is accepted.

Appendix B PP 7027 Rev. 3 Page 16 of 65

APPENDIX B (Continued) 4.2. ASME Section XI Applicability The core shroud support is part of the core support structure. Therefore the core shroud support will be examined in accordance with ASME Section XI, Table TWB-2500-1, Category B-N-2, Item B13.40, "Core Support Structure". Table IWB-2500-1 requires accessible surfaces to be visually inspected by the VT-3 method once per ten-year interval. This would normally include the upper side of the shroud support baffle plate and the shroud support shell course between welds H7 and H8. Such an examination was conducted during RFO 23 (2002) for the third ten-year Section XI interval. VY has submitted a Relief Request (RI-01) for the fourth ten-year Section XI interval that would allow using the BWRVIP guidance rather than the Section XI Categories B-N-1 and B-N-2 requirements. VY will perform inspections accordingly, based on the outcome of the Relief Request. The surfaces below the baffle plate are not accessible during the normal course of a refueling outage and would only be accessible if there were another reason to gain access below the core plate. The last time this area was accessible and, therefore, inspected was in 1983. Because this occurrence is so rare, any time that there is an opportunity for thisSection XI inspection, it must be used. The under-core plate inspection would include accessible surfaces of the shroud support legs and their welds, and the underside of the shroud support baffle plate and its welds.

4.3. Other Commitments SIL No. 462, Revision 1, (Reference 4.5.34recommended ultrasonic examination of the access hole cover welds. SIL, No. 462 Supplement 3 also recommended ultrasonic examination. A UT inspection has never been performed at Vermont Yankee; the oval shape of the weld does not lend itself to existing inspection tooling. In lieu of UT, Vermont Yankee has conducted visual inspections of the access hole cover welds every outage since at least 1993, with enhanced visual inspection performed in 1999. No relevant indications have ever been identified. An EVT-1 method should be specified, because the visual examination substitutes for what would normally be a UT examination.

F Normally, VY would follow BWRW guidance for inspection of vessel internals components, with a nod to the guidance given in GE SILs. But the access hole cover is the only component important to safety for which the B W R W does not specify inspection requirements. In fact, BWRVIP-38 states that SIL 462 adequately addresses this area.

Appendix B PP 7027 Rev. 3 Page 17 of 65

APPENDIX B (Continued)

GE SIL 462, Revision 1, recommends the following inspection schedule:

e For a normal water chemistry ( N W C ) plant where the previous inspection was top surface VT-1 only and no crack indications were found, subsequent inspections, either top surface VT-1 or UT, should be performed during a refueling outage within 4 years of the previous inspection.

For a NWC plant where the previous inspection was UT and no crack indications were found, subsequent inspections, either top surface VT-1 or UT, should be performed during a refueling outage within 6 years of the previous inspection.

e For a plant with an effective program of hydrogen water chemistry (HWC) or noble metal chemistry with H W C ,a baseline UT inspection should be conducted according to the recommendation for subsequent inspections as noted above (dependent on the previous inspection method). Once the baseline has been established and no crack indications are found, future top surface VT-1 inspections should be conducted every 8 years and future UT inspection should be conducted every 12 years. (Effected HWC is then defined.)

If indications are found, the inspection frequency may change, depending upon structural analysis results.

It is notable that the SIL now gives guidance for plants that do not perform UT. It appears that under the GE recommendations for VY's circumstances, VY would have the following options:

e Perform the visual examination every other outage 0 Perform a baseline UT and then a visual reexamination every eight years thereafter I

Perform a baseline UT and then a UT reexamination every twelve years thereafter 4

The position can be taken that ultrasonic examination of the access hole weIds is not necessary.

'! BWRVIP-38 allows an enhanced VT-1 examination of the H8 and H9 shroud support welds as

..I an alternative to ultrasonic examination. It is evident that the HS and H9 welds are more safety significant than the access hole cover welds, because they also provide structural support to the shroud - in addition to providing containment for 2/3 core height. The access hole cover welds only provide containment for 2/3 core height.

Vermont Yankee will adopt SIL 462, Revision 1, as the guidance for examination of the access hole cover welds. This will allow VY to perform visual examination of these welds every other refueling outage. However, VY wilI maintain the position that these welds should be examined by enhanced VT-1. This commitment will be honored until the BWRVIP issues guidance for the inspection of these welds.

Appendix B PP 7027 Rev. 3 Page 18 of 65

APPENDIX B (Continued) 4.4. InsDections for Risk to Generation Purposes Vermont Yankee intends to continue to inspect the shroud support baffle plate (the annulus floor) for debris and loose parts. This is typically performed just prior to vessel reassembly near the end of each refueling outage. Although nonmandatory, this inspection provides a significant benefit with regard to assurance of fuel clad integrity.

The two shroud support vertical seam weIds located between H7 and H8 will be examined by EVT-1 in RFO 25 (2005). Re-examination will be 100% each cycle, which means both seam welds will be inspected every 6 years (EO1 201 1) as prescribed by BWRVIP-76, Section 2.3.3 for a one sided visual examination. This examination is being performed as a lesson learned from the J A F IVVI Program audits.

4.5. References 1 ;.= a 4.5.1. GE SIL No. 462, dated February 1,1988, "Shroud Support Access Hole Cover Cracks" 4.5.2. Information Notice 88-03, dated February 2,1988, "Cracks In Shroud Support Access Hole Cover" 4.5.3. Memorandum J. R. Hoffman to S . R. Miller OPVY 157/88, dated February 25, 1988, "NRC Meeting - Shroud Access Hole" 4.5.4. Memorandum J. R. Hoffman to S. R. MillerD. A. Reid, March 7,1988, "Reactor Pressure Vessel Shroud Access Hole Cover Cracking" 4.5.5. Letter T. Wilders (GE) to J. P. Pelletier, March 10, 1988, "Access Hole Cover Cracking" 4.5.6. Letter T. Wilders (GE) to J. C. Brooks, June 13, 1988, "In-vessel Inspections" 4.5.7. GE SIL No. 462, Supplement 1, dated February 22,1989, "Shroud Support Access Hole Cover Cracks" 4.5.8. Memorandum C. 3.Cameron to R. E. McCulIough, dated March 7, 1989, "Preliminary Review to Supplement 1 of SIL-462" 4.5.9. Memorandum J. C. Brooks to R. D. Pagodin, May 12,1989, "Review of SIL 462 i Supplement 1" 4.5.10. GE SIL No. 462, Supplement 2, August 10, 1990, "Shroud Support Access Hole Cover Cracks

4.5.11. Memorandum C. B. Cameron to B. R. Buteau, November 16, 1990, "Request for Extension to Commitment SIL0462S2" 4.5.12. GE SIL No. 462, Supplement 2, Revision 1, December 19, 1990, "Shroud Support Access Hole Cover Cracks" 4.5.13. Memorandum C. B. Cameron to R. D. Pagodin, February 4, 1991, "Commitment SIL0462S2" 4.5.14. Memorandum C. B. Cameron to D. C. Porter, March 1, 1991, "Service Request, Shroud Support Access Hole Covers" 4.5.15. Memorandum S. K. Naeck to S. R. Miller, April 2, 1991, "Service Request 91-21, Shroud Support Access Hole Covers" 4.5.16. Letter C. B. Cameron to A. D. HimIe, dated July 22, 1991, regarding SIL 462, RICSILO54, RICSILO59 and GE support for possible inspection findings Appendix B PP 7027 Rev. 3 Page 19,of 65

APPENDIX B (Continued) 4.5.17. Memorandum C. B. Cameron to R. E. McCullough, September 11,1991, "Response to Commitment SILO462S2REl" 4.5.18. Calculation VYC-1021, Revision 0, dated November 15, 1991, "Loss of Shroud Access Hole Cover Analysis" 4.5.19. Letter A. D. Himle (GE) to C. B. Cameron, January 13,1992, "Engineering Support of IS1 Work at Vermont Yankee" 4.5.20. Memorandum C. B. Cameron to R. E. McCullough, January 30,1992, "Responseto Commitment SM3462SZRE3" 4.5.21. GE SIL No. 462 Supplement 3, June 8,1992, "Radial Cracking In Creviced Incone 600 Access Hole Cover Weldments" 4.5.22. NRC Information Notice 92-57, dated August 11, 1992, "Radial Cracking of Shroud Support Access Hole Cover Welds" 4.5.23, Memorandum C. B. Cameron to R. E. McCullough, September 16,1992, "Commitment SM)462S3" 4.5.24. BWROG Report GE-NE-523-107-0892, dated October 1992, "BWR Access Hole Cover Radial Cracking Evaluation" 4.5.25. Framatome Technologies Report dated December 18,1996, "1996 Vermont Yankee Nuclear Power Corporation Project File Report for Core Shroud Examinations of the Vertical, Ring Segment, and H8H9 Baffle Plate Welds" 4.5.26. BWRVIP-38, dated September 1997, "Shroud Support Inspection and Flaw Evaluation Guidelines" 4.5.27. Letter Vermont Yankee to NRC dated September 30, 1997, "Vermont Yankee's Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals" 4.5.28. Letter NRC to Vermont Yankee dated March 25,1998, "Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals - Vermont Yankee Nuclear Power Station" 4.5.29. BWRVIP-52, dated June 1998, "Shroud Support and Vessel Bracket Repair Design Criteria

4.5.30. Letter Vermont Yankee to USNRC, dated May 27,1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 4.5.31. GE STL No. 624, March 24,2000, "Stress Corrosion Cracking In Alloy 182 Welds In Shroud Support Structure" 4.5.32. Memorandum, C. B. Larsen to D. C. Girroir, dated May 11,2000, "Response to Commitment SIL-0624-00" 4.5.33. Letter NRC to B W R W dated March 1,2001, "Acceptance for Referencing of BWRVIP,Shroud Support Inspection and Flaw Evaluation Guidelines (BWRVIP-38), and Appendix B, Demonstration of Compliance with the Technical Information Requirements of the License Renewal Rule" 4.5.34. GE SIL No. 462, Revision 1,dated March 22,2001, "Access Hole Cover Cracking" 4.5.35. Action Itefiegulatory Commitment SIL-0462R1-01, dated March 27,200 I, "Evaluate SIL No. 462, Rev. 1, 'Access Hole Cover Cracking'"

4.5.36. BWRVIP-104, dated September 2002, "BWRVIP Evaluation and Recommendations to Address Shroud Support Cracking in BWRs" 4.5.37. Action Item / Regulatory Commitment BWRVIP-104-01, initiated September 30, 2002, "Evaluate BWRVIP-104 for new commitments in accordance with BWRVIP-94" Appendix B PP 7027 Rev. 3 Page 20 of 65

APPENDIX 3 (Continued) 4.5.38. Action Item / Regulatory Commitment BWRVIP-104-02, initiated November 20, 2002, "Revise PP 7027 to require examination of the shroud support H9 weld in accordance with the revised guidance of BWRVIP-104" 4.5.39. Technical Justification TJ-2004-04, dated March 26,2004, "Justification to Defer Inspection for Detection of Transverse Flaws in Shroud Support Weld H9" 5.0 Core Spray Internal Pipiw and Suargers I 5.1 BWRVIP Document Amlicability BWRW-18, published in July 1996, governs inspection of the core spray system internal to the vessel. Vermont Yankee has complied with this document as of its publication. Additionally, i

Vermont Yankee has committed to its use in References 5.5.18 and 5.5.20 as further described below. Per BWRVIP-94, letters from the B W R W Executives to the NRC are also considered mandatory. To that end, Vermont Yankee has also complied with the NRC's Final Safety I:.  :

Evaluation on BWRVlP-18 (Reference 5.5.22), with the exception that the core spray piping and sparger brackets were not inspected every two cycles per that letter. Event Report 2001-2480 (Reference 5.5.28) was initiated and the corrective action was to inspect these brackets RFO 23 I.

(2002). I 1

BWRV1P-48, published in February 1998, governs inspection of the core spray bracket attachment welds. Vermont Yankee has complied with this document as of its publication. I f

5.1.1. Thermal Sleeve Welds I

i i

These welds are currently inaccessible for inspection, but per B W R W - 18, Paragraph 3.2.4, inspection is recommended when a technique becomes available. Because a technique still does not exist, VY has complied with this document as of its publication. Inspection of 100% of these welds would be required immediately upon development of a technique, considering scheduling as allowed under PP 7027. I Until such time as an inspection technique is available, BWRVIP-18, Section 3.2.4 "Hidden Welds", states.. ."a qualitative assessment of thermal sleeve integrity can be I.

based on a plant-specific evaluation of similar core spray piping welds. If a plant has uncreviced thermal sleeve welds, the evaluation welds should be the junction 1 I

box-to-pipe welds and the upper elbow welds. If the thermal sleeve welds are t creviced, the evaluation welds should be the junction box cover plate weld, where applicable, the P1 weld in BWW3-5 plants where accessible for inspection, and the downcomer sleeve welds." Regardless of whether VY's thermal sleeve welds are creviced, none of the above "evaluation welds" at VY show any indications of cracking. Therefore, the qualitative assessment of the core spray thermal sleeve welds is satisfactory (UND 2002-074-08). A Technical Justification in accordance with PP 7027, Paragraph 4.2.3 and B WRVIP-94 is in the course of preparation to defer examination of these welds until such time that tooling and an NDE technique become available.

Appendix B PP 7027 Rev. 3 Page 21 of 65

APPENDIX B (Continued)

BWRVIP-18, Paragraph 3.2.4references Figure 3-1 for inspection requirements, which references the reinspection flowchart (Figure 3-3).

BWRVIP-18, Paragraph 2.2.1, states that most thermal sleeve welds are full penetration welds, but that some are creviced fillet welds, and at least one is a creviced partial penetration weld. Then from the way that is worded, full penetration thermal sleeve welds would be considered to be non-creviced. Vermont Yankee has three welds upstream of P1 in each of two nozzles that are full penetration butt welds:

0 ing fork-to-10 schedule 40 pipe weld 0 A 10" pipe-to-10" to 8" std. weight concentric reducer weld i 0 A 10"to 8" reducer-to-8" schedule 40 pipe weld 4 -

These six welds will be inspected as part of the 25% target weld sample on a rotating basis with the other 16 non-creviced welds. Therefore, of the 22 non-creviced welds, if only UT was used, five or six non-creviced welds would be inspected every other I.I cycle, and the six hidden welds would be inspected all together every eighth cycle for convenience. The same will be true - inspection of the thermal sleeve welds every eight cycles - if the bulk of the core spray welds are inspected with the EVT-1 method every cycle (see below).

I 5.1.2. Internal Piping A full baseline inspection of the core spray piping was performed in RFO 19 (1996) with the majority performed with the UT method. BWRVIP-18, Paragraph 3.3, specifies that certain target welds be reinspected. Target welds are defined as all of the creviced welds, the tee-box-to-pipe welds, and 25% of the non-creviced welds.

For Vermont Yankee there are 24 creviced welds, four tee-box-to-pipe welds, and 16 non-creviced welds (22 non-creviced welds counting the thermal sleeves). The BWRVIP core spray piping reinspection frequency for ultrasonic inspection is two cycles, and for EVT-1 it is one cycle. Consequently, the welds that were examined visually in W O 19 (1996) were reexamined visually in RFO 20 (1998). Of the 44 welds that were inspected ultrasonically and visually in RFO 19 (1996), 32 required reinspection in RFO 21 (1999); these examinations were performed visually.

However, two creviced welds, AP1 and BP1, are essentially inaccessible for visual examination, so only a best effort inspection was performed.

Appendix B PP 7027 Rev. 3 Page 22 of 65

APPENDIX B (Continued)

In RFO 19 (1996), core spray piping welds 1P8b and 3P8b were found to be flawed by UT. Vermont Yankee received permission from the NRC to forgo U T reinspection of those welds in RFO 20 (1998) and RFO 21 (1999); however those welds were examined using EVT-1. The lP9 and 3P9 welds are redundant to the two flawed welds, so in RFO 22 (2001) UT examination of all four P9 welds was attempted using UT. Welds 1P9,2P9, and 3P9 were found to have indications, and were found to be acceptable for continued service (Reference 5.5.26), but the UT examination technique was subsequently disqualified by the BWRVIP in the spring of 2002 (References 5.5.36,5.5.39, and 5.5.40). Experimentation at FRA-ANP using newly-built BWRVIP mockups determined that ultrasound was never entering the weld examination volume. Therefore, the RFO 22 (2001) P9 UT examination was ruled invalid; the P9 welds have been determined to never have undergone inspection to date; and the P9 welds are now assumed to be flaw-free (indications in the RFO 22 (2001) UT data are from component geometry or from some other non-flaw source).

EPRI performed a comparison of the 1P8b and 3P8b UT data from RFO 19 (1996) 1.

1 and RFO 22 (2001) and it was determined that none of the indications on those two welds had changed over those three cycles (Reference 5.5.41). Vermont Yankee will examine the P9 welds when an examination technique becomes available, but until that time will perform EVT-1 examination of the P8b welds.

In the future, the creviced welds, the four tee-box-to-pipe welds, and 25% (five or six) of the 22 non-creviced welds will be inspected with either the EVT-1 method or the UT method. The inspection frequency will depend on the inspection method chosen: one cycle for EVT-1 or two cycles for UT.

5.1.3. Spargers Vermont Yankee informed the NRC in References 5.5.18 and 5.5.20 below that VY will be following the BWRVIP-18 inspection guidelines rather than IE Bulletin 80-13 for the core spray spargers. In RFO 20 (1998), following the published BWRVIP-18 guidance for a geometry-tolerant plant, Vermont Yankee performed a modified VT-1 1 (with cleaning) of the core spray sparger circumferential welds and a VT-3 of the nozzles and brackets. No cracking was found. Since that time, the BWRVIP has agreed with the NRC to revise BWRVIP-18 and discontinue the designation of I

geometry-tolerant plant status. Therefore, in the future Vermont Yankee will perform EVT-1 (see reference 5.5.19) inspection of the sparger circumferential and bracket [

welds and a VT-1 inspection of the nozzle welds. In References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to inspect all the major Circumferential welds I i

and 50% of the nozzle welds in the core spray spargers every other refueling outage.

Appendix B PP 7027 Rev. 3 Page 23 of 65

APPENDIX B (Continued)

BWRW-18, in Figure 3-2, identifies the method of inspectionJor the large circumferential welds as CS VT-1. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the CS VT-1 and MVT-1 methods with the EVT-1 method. These welds were inspected with the MVT-1 method during RFO 20 (1998).

BWRW-18, in Figure 3-2, identifies the method of inspection for the nozzle welds for geometry tolerant plants as VT-3. Because the BWRVIP dropped the distinction of geometry-tolerant plants, the BWRVIP committed to the NRC to inspect the nozzle welds by the VT-1 method. The nozzle welds were inspected with the VT-3 method in RFO 20 (1998). The large circumferential and nozzle welds were inspected in accordance with the BWRVTP document that was published at the time.

In the future, these welds will be inspected in accordance with the revised philosophy.

A repair was installed on the spager "C"tee-box during RFO 8 (1980) or RFO 9 (1981) to address cracking of the tee-box cover plate. BWRVIP-19, Section 10.2.3 states, "Inspections required for the entire repaired internal core spray piping and sparger assembly for the remaining life of the unit shall be specified commensurate with design considerations and Code requirements applicable to the specific design."

Since the repair was installed prior to the existence of the B W R W , no ongoing inspection requirements were originally established. The tee-box repair has received a VT-3 inspection every refueling outage for the most part from its installation through RFO 21 (1999). However, BWRVIP-18, Section 3.3.3, under "Repairs",

states, "For bolted repairs, reinspection should be with the same methods described for the baseline in Section 3.2.4". Since the spargers require VT-1, the repair will be inspected by VT-1. Section 3.3.3 also states, "Reinspection of bolted repairs should be every 2 cycles unless cracking or damage is found".

5.1.4. PiDinn and Sparger Brackets Vermont Yankee has informed the NRC in References 5.5.18 and 5.5.20 below that VY will be following the BWRVIP-18 guidelines rather than IE Bulletin 80113 for the core spray spargers and their brackets. The piping brackets were inspected in accordance with BWRVIP-18 during RFO 19 (1996), and no cracking was found.

The sparger brackets were inspected in accordance with BWRVIP-18 during RFO 20 (1998), and no cracking was found. BWRVIP-18, Section 3.3.3, states that if there is no cracking, reinspection of piping and sparger brackets every four cycles is appropriate. However, in a response to the NRC Safety Evaluation on BWRVIP-18 (Reference 5.5.19), the B W R W states that the sparger brackets should be inspected every other cycle. Because the sparger brackets were not inspected after two cycles, Event Report 2001-2480 (Reference 5.5.28) was initiated and the corrective action was to inspect these brackets in RFO 23 (2002) and every other cycle in the future.

BWRVIP-48, Table 3-2, applies for the piping bracket vessel attachment welds. The inspection frequency for these welds is listed as every four cycles.

Appendix B PP 7027 Rev. 3 Page 24 of 65

APPENDIX B (Continued)

BWRW-18 identifies the method of inspection for the core spray piping brackets in Section 3.2.4 to be CS VT-1. BWRW-48, Table 3-2, identifies the method of inspection to be modified VT-1. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the CS VT-1 and MVT-1 methods with the EVT-1 method. In those same letters, the inspection method of core spray sparger brackets was changed to VT-1. Future inspections of the core spray piping brackets will be by the EVT-1 method. Future inspections of the core spray sparger brackets will be by the VT-1 method.

5.2. ASME Section XI ADplicabilitv Inspection of the core spray piping bracket attachment welds is also governed by ASME Section XI, Table IWB-2500-1, Category B-N-2, Item No. B13.30, "Interior Attachments Beyond Beltline Region," which requires a VT-3 inspection once each ten-year interval, typically performed at the end of the interval. The method and frequency of inspections given above by the B W R W requirements exceed the ASME Section XI requirements. Therefore, this Program will consider ASME Section XI requirements to be satisfied by performing inspection of the core spray piping bracket attachment welds in accordance with BWRVIP requirements. Additionally, VY has submitted a Relief Request (RI-01) for the fourth ten-year Section XI interval that would allow using the B W R W guidance rather than the Section XI Categories B-N-1 and B-N-2 requirements.

5.3. Other Commitments In Reference 5.5.13 below, Vermont Yankee committed to perform inspection of the core spray spargers during RFO 19 (1996) in accordance with Bulletin 80-13, however, it was indicated that Vermont Yankee intended, in the future, to perform such inspections in accordance with BWRVIP-18. In Reference 5.5.18 below, Vermont Yankee did indeed commit to follow the BWRVIP Guidelines for core spray spargers and their brackets. This commitment took effect with JXFO 20 (1998).

5-4. Inspections for Risk to Generation Pumoses - None.

5.5. 'ieferences 5.5.1, GE S L No. 289, Revision 0, dated February 1, 1979, "Core Spray Piping Visual Inspection" 5.5.2. NRC Bulletin 80-13, dated May 12, 1980, "Cracking In Core Spray Spargers" 5.5.3. EDCR 80-52, dated October 30,1980 with Change No. 1 dated November 11, 1980, Change No. 2 dated December 12,1980, and Change No. 3 dated March 4, 1982, "Design and Installation of Clamping Device for Core Spray Sparger Junction Box

'C'It 5.5.4. Letter USNRC to Vermont Yankee, NVY 80-qq, dated November 5, 1980, "Summary of Meeting Held On October 31, 1980 To Discuss Vermont Yankee Core Spray Sparger Cracking" Appendix B PP 7027 Rev. 3 Page 25 of 65

APPENDIX B (Continued) 5.5.5. Letter Vermont Yankee to USNRC, WVY 80-164, dated December 1,1980, Results of Core Spray Sparger Inspection" 5.5.6. GE SIL No. 289, Revision 1, Supplement 1, dated February 23,1989, "Core Spray Piping Visual Inspection

5.5.7. GE SIL No, 289, Revision 1, Supplement 1, Revision 1, dated March 15, 1989, Tore Spray Piping Visual Inspection" 5.5.8. Letter J. C. Brooks to R. D. Pagodin, dated May 3,1989 5.5.9. GE RICSIL No. 074, dated November 1 , 1995, "Cracking In Core Spray Piping" 5.5.10. GE SIL No. 289, Revision 1 Supplement 2, dated January 5, 1996, "Cracking In Core Spray Piping" 5.5.11. Memorandum D. C. Girroir to P,3. Corbett, May 1, 1996, "Core Spray Piping Weld, CAT A Items (SM)289Rl_S2, RICSILO74)"

5.5.12. BWRVIP-18, dated July 1996, "BWR Core Spray Inspection and Evaluation Guidelines" I,. 5.5.13. Letter Vermont Yankee to USNRC, BVY 96-1 10, dated September 25,1996, "Core Spray System Inspection at Vermont Yankee"

t. : 3 5.5.14. Letter USNRC to Vermont Yankee, NVY 96-176, dated November 20, 1996, "Review of Core Spray System Collar-to-Shroud Weld Flaw Evaluation and Core I 8 Spray System Inspection Plan at Vermont Yankee Nuclear Power Station (TAC Nos.

L M96671 and M96689)"

5.5.15. Memorandum J. R. Hoffman to J. J. Duffy, dated December 12,1996, "Review of 1

NRC SER for Core Spray Collar Cracking" 5.5.16. BWRVIP-16, dated March 1997, "Internal Core Spray Piping and Sparger Replacement Design Criteria" 5.5.17. Letter Vermont Yankee to USNRC, dated September 30, 1997, "Vermont Yankee's Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals" Letter USNRC to Vermont Yankee, dated March 25,1998, "Plans for the 1998 and WI 5.5.18.

1999 Refueling Outages Regarding Reactor Vessel Internals - Vermont Yankee Nuclear Power Station"

. 1 5.5.19. Letter BWRVIP to USNRC, dated January 11,1999, "BWRVIPResponse to NRC Safety Evaluation of BWRVIP-18" 5.5.20. Letter Vermont Yankee to USNRC, dated May 27,1999, BVY 99-73, "Reactor "1 I: Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 5.5.21. Letter USNRC to BWRVIP, dated September 29, 1999, "Final Safety Evaluation of

? 'Vessel ID Attachment Weld Inspection and Haw Evaluation Guidelines (BWRVIP-48)"'

5.5.22. Letter USNRC to BWRVIP, dated December 2, 1999, "Final Safety Evaluation of Core Spray Internals Inspection and Flaw Evaluation Guidelines (BWRVIP-18)"

5.5.23. Letter Vermont Yankee to USNRC, dated February 14,2000, 'Vermont Yankee's Plans for Reactor Vessel Internal Core Spray Piping" 5.5.24. Letter NRC to BWRVIP,dated December 7,2000, "Acceptance for Referencing of BWRVIP, BWR Core Spray Internals Inspection and Evaluation Guidelines (BWRVIP-18) Report for Compliance with the License Renewal Rule (10 CFR Part 54)"

5.5.25. Framatome ANP UT Exam Report, dated May 11,2001, "Core Spray Piping P9P8b Weld Examination Field Report for Vermont Yankee", Revision 0 Appendix B PP 7027 Rev. 3 Page 26 of 65

APPENDIX B (Continued) 5.5.26. Technical Evaluation No. 2001-029, dated May 14,2001, "Evaluation of Internal Core Spray Piping Flaws" 5.5.27. Event Report 2001-2479, initiated December 3,2001, "BWRVIP Cleaning Requirements" 5.5.28. Event Report 2001-2480, initiated December 3,2001, "Scheduling of BWRVIP Core Spray Piping Brackets" 5.5.29. Action Item / Regulatory Commitment ER-2001-2479-01, dated January 22,2002, "Revise NE 8048" 5.5.30. Action Item / Regulatory Commitment ER-2001-2480-01, dated January 22,2002, "Revise PP 7027 - revision applies to Core Spray inspection scope" 5.5.31. Action Item / Regulatory Commitment UND-2002-074-05, dated March 21,2002, "Perform an EVT-1 of core spray piping bracket vessel attachment welds" 5.5.32. Action Item / Regulatory Commitment UND-2002-074-06, dated March 21,2002, "Schedule an inspection of the core spray sparger bracket in accordance with BWRVIP-18" 5.5.33. Action Item / Regulatory Commitment UND-2002-074-08, dated March 21,2002, "Provide a qualitative evaluation for inaccessible core spray welds in accordance with BWRVIP-18" 5.5.34. Action Item / Regulatory Commitment UND-2002-074-09, dated March 21,2002, "Ensure that components with crud buildup are sufficiently cleanedf 5.5.35. Action Item / Regulatory Commitment UND-2002-074-10, dated March 21,2002, "Improve the timeliness and review of vendor NDE activities during outage activities" 5.5.36. Memorandum D. C. Girroir to J. Dreyfuss, dated May 9,2002, "Core Spray P9 Weld Status" 5.5.37. Action Item / Regulatory Commitment BWRVIP-006-A-01, dated June 6,2002, "Evaluate BWRVIP-06-A and define solutions as required" 5.5.38. Action Item / Regulatory Commitment BWRVIP-006-A-02, dated June 20,2002, "Reactor Internals Modifications prior to B W R W guidance" 5.5.39. Event Report 20022877, initiated December 3,2002, "CS P9 Weld UT Technique Qualification Revocation" 5.5.40. BWRVIP-03, Revision 5, December 2002, "BWRVIP Examination Guidelines" 5.5.41. Letter EPRI to Vermont Yankee, dated December 15,2003, "Review of Ultrasonic Inspection Information for Vermont Yankee Core Spray Internal Piping Welds 1P8b and 3P8b" I 5.5.42. Technical Justification 2004-02, dated 03/26/04, "Justification for Deferrd of Inspection of Inaccessible Welds" Appendix B PP 7027 Rev. 3 Page 27 of 65

APPENDIX B (Continued) 6.0 Feedwater Spargers 6.1. B W R W Document Apdicability No BWRVIP Inspection and Evaluation document addresses the feedwater sparger, which is considered a non-safety related component, with the exception that BWRVTP-48, published in February 1998, governs inspection of the reactor vessel internal attachment welds. Vermont Yankee has complied with this document as of its publication. BWRW-48, Table 3-2, states that, "No additional inspections (for the feedwater sparger bracket attachments) are required above those specified in a plant's ASME Section XI program." One exception is listed in BWRVIP-48, Table 3-2, which requires that feedwater bracket attachment welds which use furnace-sensitized stainless steel or Alloy 182 material be examined by the modified VT-1 method. The inspection frequency is per ASME Section XI, Table TWB-2500-1, Category B-N-2, and this end-of-interval inspection will be performed in RFO 23 (2002). The reactor vessel was heat treated subsequent to welding of these attachment pads. There is no evidence at this time that the feedwater bracket attachment welds were not furnace-sensitized. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MVT-1 method with the EVT-1 method. Therefore the feedwater bracket attachment welds were inspected with the EVT-1 method in RFO 23 (2002) for the Third Interval inspection, and will be examined likewise in the Fourth Interval.

6.2. ASME Section XI Apulicability Inspection of the feedwater sparger bracket welds is also governed by ASME Section X I , Table IWB-2500-1, Category B-N-2, Item No. B13.30, "Interior Attachments Beyond Beltline Region,"

which requires a VT-3 inspection once each ten-year interval, typically performed at the end of the interval. However, the BWRVTP requirement above exceeds this requirement. Therefore, this Program will consider ASME Section XI requirements to be satisfied by performing inspection of the feedwater bracket attachment weIds in accordance with the BWRVIP.

Additionally, VY has submitted a Relief Request @I-01) for the fourth ten-year Section XI interval that would allow using the BWRVIP guidance rather than the Section XI Categories B-N-1 and B-N-2 requirements.

Appendix B PP 7027 Rev. 3 Page 28 of 65

APPENDIX B (Continued) 6.3. Other Commitments In References 6.5.5,6.5.6, and 6.5.7 below Vermont Yankee commits to continue to perform visual examinations of the feedwater spargers on a two-cycle frequency. The visual inspections are performed in accordance with NUREG-0619, which in Table 2 requires, for plants with interference fit spargers and cladding, a visual inspection of the flow holes and welds in sparger arms and sparger tees. It requires a VT-3 of the sparger piping, spacer brackets, and end brackets, and a VT-1 of the tee welds and end bracket-to-vessel weld. BWROG report GE-NE-523-A71-0594-A, Revision 1, (Reference 6.5:20) was issued in May 2000 to formalize substitution of UT for PT of the feedwater nozzle inner radius area. The use of that document by VY for nozzle inner radius examination does not alter VY's commitments for visual inspection of the spargers and brackets.

6.4. Inspection for Risk to Generation Pumoses - None.

6.5. References 6.5.1. EDCR 75-30, dated June 28, 1976, "Feedwater Sparger Replacement" 6.5.2. NUREG-0619, dated November 1980, "BWR Feedwater Nozzle and CRD Return Line Nozzle Cracking" 6.5.3. Letter Vermont Yankee to USNRC, FVY 86-29, dated March 28,1986, "Request for Revision of Routine Inspection Interval Guidance Provided by NUREG-0619, Based on Accumulated Plant-Specific Experience" 5.4. Letter USNRC to Vermont Yankee, NVY 86-73, dated April 18, 1986, "Alternate Inspection of Feedwater Nozzle for the 1986 Refueling Outage" 6.5.5. Letter Vermont Yankee to USNRC, FVY 87-02, dated January 5, 1987, "Request for Permanent Revision of Routine Inspection Interval Guidance Provided by NUREG-0619 for Feedwater Nozzle PT Examinations" F.6. Letter Vermont Yankee to USNRC, FVY 87-60, dated June 2, 1987, "Request for Permanent Revision of Routine Inspection Interval Guidance Provided by NUREG-0619 for Feedwater Nozzle PT Examinations - Response to Request for Additional Information" 6.5.7. Letter Vermont Yankee to USNRC, BVY 94-07, dated February 11,1994, "Request for Relief from NtlREG-06 19 Inspection Requirements" 6.5.8. Letter USNRC to Vermont Yankee, NVY 94-157, dated September 9, 1994, "Summary of August 30, 1994, Meeting with Representatives of Vermont Yankee Nuclear Power Corporation" 6.5.9. Letter Vermont Yankee to USNRC, BVY 94-110, dated November 8,1994, "Feedwater Nozzle Inspection Relief Request" 6.5.10. Letter USNRC to Vermont Yankee, NVY 95-16, dated December 29, 1994, "Inspection Report No. 50-27 1/94-29" 6.5.11. Letter Vermont Yankee to USNRC, BVY 95-08, dated January 19, 1995, "Feedwater Nozzle Inspection Relief Request - Supplementary Information" 6.5.12. Letter USNRC to Vermont Yankee, NVY 95-02, dated February 6, 1995, "Evaluation of Request for ReIief from NUREG-0619 for Vermont Yankee Nuclear Power Station" Appendix B PP 7027 Rev. 3 Page 29 of 65

APPENDIX B (Continued) 6.5.13. Letter Vermont Yankee to USNRC, B.VY 95-78, dated July 14,1995, "Feedwater Nozzle Inspection Technique Qualification - Final Report" 6.5.14, Letter USNRC to Vermont Yankee, NVY 95-142, dated October 12, 1995, "Feedwater Nozzle Inspection Relief Request - Vermont Yankee Nuclear Power Station" 6.5.15. Letter USNRC to Vermont Yankee, NVY 96-182, dated December 5, 1996, "Erratum To the Safety Evaluation of Vermont Yankee Nuclear Power Corporation's Request for Relief from NUREG-06 19 Feedwater Nozzle Inspection Requirements - Vermont Yankee Nuclear Power Station" 6.5.16. Letter Vermont Yankee to USNRC, dated May 27,1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 6.5.17. Memorandum C. B. Larsen to D. C. Girroir, dated August 27,1999, "Future Examinations of Feedwater Nozzle Inner Radii with Regard To Proposed BWROG NUREG 0619 Relief" 6.5.18. Letter USNRC to BWRVTP, dated September 29, 1999, "Final Safety Evaluation of

'Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines (BWRVIP-48)"'

6.5.19. Letter USNRC to BWR Owners' Group, dated March 10,2000, "Final Safety Evaluation of BWR Owner's Group Alternate Boiling Water Reactor (BWR)

Feedwater Nozzle Inspection (TAC No. MA6787)"

6.5.20. BWR Owners' Group Report GE-NE-523-A71-0594-AY Revision 1, dated May 2000, "Alternate BWR Feedwater Nozzle Inspection Requirements" 6.5.21. Letter Vermont Yankee to USNRC, dated January 22,2001, BVY 01-02, "Alternative Feedwater Nozzle Inspection" 7.0 Guide Rods 7.1. BWRVIP Document Auulicabilitv No B W R W Inspection and Evaluation document addresses the guide rods, which are considered non-safety related components, with the exception that BWRVIP-48, published in February 1998, governs inspection of the reactor vessel internal attachment welds. Vermont Yankee has complied with this document as of its publication. The requirements for the guide rod attachment welds are found in the Miscellaneous Vessel Internal Attachments section.

7.2. ASME Section XI Auulicability Inspection of the guide rod attachment welds is also governed by ASME Section XI, Table IWB-2500-1, Category B-N-2, Item No. B 13.30, "Interior Attachments 3eyond Beltline Region."

The requirements for the guide rod attachment welds are found in the Wscellaneous Vessel Internal Attachments section.

7.3. Other Commitments - None.

Appendix B PP 7027 Rev. 3 Page 30 of 65

APPENDIX B (Continued) 7.4. Inspection for Risk to Generation Pumoses Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and agreed that these components are non-safety related. However, the group agreed that some inspection might be warranted for risk to generation reasons. The guide rods are used to position the shroud head and separator for reinstallation. If the guide rods were bent or broken off of their attachments, it would hamper this process. If the guide rods were damaged in this manner during operation, this damage would probably be detectable during disassembly. Nevertheless, a VT-3 inspection of the guide rods would not take considerable time and could be performed in conjunction with the vessel attachment welds. Therefore, this nonmandatory inspection would be performed at the same time as the ten-year vessel attachment weld IST. Such an inspection was performed during RFO 23 (2002).

7.5. References - None. 1 '

1.. ,

8.0 Incore Flux Monitors (Including Housinm, Guide Tubes, Drv Tubes)

I ' _

• 8.1. BWRVIP Document Applicability I

BWRVIP-47, published in December 1997, governs inspection of the incore flux monitor housing, guide tube, and dry tube assemblies. However, BWRVIP-47 considers the incore flux monitor housing, guide tube, and dry tube assemblies as non-safety related and does not identify any inspection for these components. Therefore, Vermont Yankee has complied with this document as of its publication.

However, the BWRVIP stated in response to NRC SE Issue 3.2.2 (Reference 1.5.13) that when utilities have access to the lower pIenum due to maintenance activities not related to the inspection recommendations of the BWRVIP,they will have the opportunity to perform a visual inspection of a portion of the lower plenum and that results of this inspection will be reported to the BWRVIP. This will be treated as a commitment for those items listed in 8.4 below.

8.2. ASME Section XI Amlicability - None, Appendix B PP 7027 Rev. 3 Page 31 of 65

APPENDIX B (Continued) 8.3. Other Commitments There are ten dry tubes at Vermont Yankee. Nine of the ten were replaced in RFO 12 (1986) and the remaining dry tube was replaced in RFO 18 (1995).

Reference 8.5.4 below consists of an internal commitment to inspect dry tubes following six refueling outages after their installation. The inspection was conducted in RFO 18 (1995) when three dry tubes were inspected. Reference 8.5.11 below consists of an internal commitment to perform inspection of three dry tubes every third outage. Representatives from Reactor Engineering. and Plant Engineering met on January 13,1999, and agreed that these components are non-safety related. However, the group decided to continue these inspections, but to decrease i . the population size. It was decided to perform inspection of two dry tubes every third outage from that date forward. Two dry tubes were inspected in RFO 21 (1999) so two dry tubes will E .1 again be inspected in W O 24 (2004). SIL 409, Revision 2, (Reference 8.5.16) recommended that for dry tubes of the newer design with noncreviced welds and better material, the dry tubes be inspected at an increased frequency after they reach 20 years of age. Reference 8.5.18 t ,I confmed that the dry tubes are of the newer design. Commitment SIL-409R2-02 (Reference 8.5.19)was generated to revise PP 7027 to perform inspection of dry tubes every other refueling f cycle (50% every cycle) after they reach 20 years of service life. Starting in RFO 25 (2005), 50%

L of the dry tubes that are 20 years old will be inspected every refueling outage (five dry tubes one outage, four dry tubes the next, and so on until all dry tubes are 20 years old). These 1

commitments are only internal commitments and could be changed or deleted in the future.

Therefore, the inspections are only mandatory in that sense, although the dry tubes are considered a risk-to-generation component because they form the pressure boundary of the vessel.

1 -

• The method of inspection is determined from GE SIL No. 409 (Reference 8.5.2). The top two feet of the dry tube assembly is inspected with the VT-1 method and the remainder of the dry tube assembly is inspected with the VT-3 method. For the VT-1 method, the dry tube is inspected from all four adjacent fuel bundle locations, because othe 30-degree rule. For the

. I VT-3 method, the dry tube need only be inspected from two fuel bundle locations diagonally opposite from each other.

.3 8.4. InsDection for Risk to Generation Purposes

'1 At the same meeting mentioned above, incore instrumentation housing and guide tube inspection was discussed. It was agreed that these components are also non-safety related. Inspection of these components by themselves would be very costly and time consuming, because they are located below the core plate and core disassembly would be required. The group agreed to only perform inspection of these components if they were made accessible through other vessel activities. The last time this area was accessible and, therefore, inspected was in 1983. Because this occurrence is so rare, any time that there is an opportunity for inspection, it should be used.

This nonmandatory under-core plate inspection would include accessible incore housing-to-vessel welds, incore housing-to-guide tube welds, and incore guide tube stabilizers.

Appendix B PP 7027 Rev. 3 Page 32 of 65

1 APPENDIX B (Continued) 8.5. References 8.5.1. GE SIL No. 406, February 24, 1984, "Incore Instrumentation Protection" 8.5.2. GE SIL No. 409, dated June 19, 1984, "Incore Dry Tube Cracks" 8.5.3. GE SIL No. 406, Revision 1, July 2, 1984, "Incore Instrumentation Protection" 8.5.4. Memorandum J. C. Brooks to B. R. Buteau, dated August 2,1984, "Review of SIL 409 - Incore Dry Tube Cracks" 8.5.5. Memorandum B. R. Buteau to R. J. Wanczyk, dated August 4,1984, "Review of SIL 409" 8.5.6. GE SIL No. 409, Revision 1, dated July 31, 1986, "Incore Dry Tube Cracks" 8.5,7. Memorandum D. E. LaBayer to D. A. Reid, dated August 15,1986, "Incore Instrument Protection - SIL 406" 8.5.8. Memorandum J. C. Brooks to B. R. Buteau, dated September 9, 1986, "Review and Recommendation on SIL 409, Rev. 1" 8.5.9. GE IUCSIL No. 073, dated May 12, 1995, "Cracking in Incore Dry Tube" 8.5.10. Memorandum T. G. Stetson to Outage 18 File, July 25,1995, "Outage 18 Dry Tube Replacement" 8.5.11. Memorandum T. G. Stetson to R. E. McCullough, August 7, 1995, "Response to Commitment RICSIu)73" 8.5.12. Memorandum E. J. Taintor to D. C. Girroir, dated October 20, 1995, "Inservice Inspection of Vessel Internal Items Located Below the Core Support Plate" 8.5.13. BWRVIP-47, dated December 1997, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines" 8.5.14. Letter USNRC to BWRVIP, dated October 13, 1999, "Final Safety Evaluation of

'BWRVIP, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines (BWRVIP-47),' EPRI Report TR-108727, (TAC No. MA1102)"

8.5.15. Letter NRC to B W R W , dated December 7,2000, "Acceptance for Referencing of BWRVIP, BWR Lower Plenum Inspection and Evaluation Guidelines (BWRVIP-47) for Compliance with the License Renewal Rule (10 CFR Part 54)

8.5.16. GE SIL No. 409, Revision 2, dated February 8,2002, "Incore Dry Tube Cracks" 8.5.17. Action Item / Regulatory Commitment SIL-409R2-01, dated February 8,2002, "Incore Dry Tube Cracks" 8.5.18. Telex Warren Phelan (GE Reuter Stokes) to Carl Larsen, dated March 26,2002, 1986 Dry Tube Replacement Design 8.5.19. Action Item / Regulatory Commitment SIL-409R2-02, dated April 1,2002, "Revise PP 7027 to change the inspection frequency" 9.0 Instrument Penetrations 9.1, BWRVlP Document Applicabilitv BWRVIP-49, published in March 1998, governs inspection of the instrument penetrations.

Section 3.2 of BFVRVP-49 states that no additional inspections (beyond the required ASME Section XI inspections) are recommended for any of these locations. Therefore, Vermont Yankee has complied with this document as of its publication.

Appendix B PP 7027 Rev. 3 Page 33 of 65

APPENDIX B (Continued) 9.2. ASME Section XI Applicability ASME Section XI, Code Category B-P, Item B 15.10, requires that a VT-2 be performed of the instrument penetrations each refueling outage. This requirement is addressed in PP 7034,the Inservice Inspection Pressure Test Program procedure. ASME Section XI, Code Category B-F, Items B5.20 and B5.30 require that a surface examination be performed of the nozzle-to-safe-end weld each ten-year interval. This requirement is addressed in PP 7015, the Inservice Inspection-Program procedure. (Relief Request RX-01 does not include this scope.)

9.3. Other Commitments - None 9.4. Inspection for Risk to Generation Purposes - None 9.5. References 9.5.1, BWRVIP-49, dated March 1998, "BWRVIPInstrument Penetration Inspection and Haw Evaluation Guidelines 9.5.2. Letter NRC to B W R W , dated August 4,1998, "Safety Evaluation of 'BWRVIP Instrument Penetration Inspection and Flaw Evaluation Guidelines (BWRVIP-49)'"

9.5.3. BWRVIP-57, dated December 1998, "BWRVIPInstrument Penetration Repair Design Criteria" 9.5.4. Letter NRC to B W R W , dated September 1,1999, "Acceptance for Referencing of BWRVIP, 'BWRVIP Instrument Penetration Inspection and Flaw Evaluation Guidelines (BWRW-49),' for Compliance with the License Renewal Rule (10 CFR Part 54)"

9.5.5. BWRVIP-49-A, dated March 2002, "BWRVIPInstrument Penetration Inspection and Flaw Evaluation Guidelines 9.5.6. Action Item / Regulatory Commitment BWRVIP-049-A-01, dated June 6,2002, "Evaluate BWRVIP-49-A and define solutions as required" 10.0 JetPumDs 10.1. BWRVIP Document ADDlicabilitv BWRVIP-41, published in October 1997, governs inspection of the jet pumps. Vermont Yankee has complied with this document as of its publication, with the exception noted below for the diffusedadapter circumferential welds below the diffuser shell. Those welds were, however, examined within two cycles of the publication of BWRVIP-41 in accordance with guidelines later published in BWRVIP-94. The inspection requirements for all of the jet pump subcomponents listed below are established in BWRVIP-41, Table 3.3-1. The document establishes six-year inspection intervals for specific inspections described below. Vermont Yankee defines the first six-year interval to include RFO 20 (1998), RFO 21 (1999), RFO 22 (2001), and RFO 23 (2002). The second six-year interval will include RFO 24 (2004), RFO 25 (2005), RFO 26 (2007), and RFO 27 (2008). The third six-year interval will begin with RFO 28 (2010) and RFO 29 (201 1).

Appendix B PP 7027 Rev. 3 Page 34 of 65

APPENDIX B (Continued)

BWRW-48, published in February 1998, governs inspection of the jet pump riser brace attachment welds. Vermont Yankee has complied with this document as of its publication.

10.1.1. Beams No inspection is required during the first ten years of service. After ten years of service, inspection of 50% of the beams is required every six years. After 20 years of service, inspection of 100% of the beams is required every six years. The beams were replaced in RFO 9, (NovemberLDecember 1981). In RFO 20 (1998) all 20 beams were ultrasonically inspected for the first time. One beam bolt (no. 7) was replaced as a result of that inspection. It was determined (Reference 10.5.67) that it is unlikely that the UT indication, which instigated replacement of that beam, was from a service-related flaw. In RFO 21 (1999) beams 1 through 10 (50%)were inspected. In RFO 23 (2002) the beams were over 20 years old and 100% will require inspection in each six-year interval. All 20 beams were ultrasonically tested in RFO 23 (2002). In response to GE RICSlL No. 086 (Quad Cities beam failure) the beam transition regions were also inspected in RFO 23 (2002) by VT-1. The inspection frequency is determined from BWRVIP-41, Table 3.3-1.

BWRVIP-41 identifies the method of inspection in Table 3.3-1 to be UT or by other NDE technique. Currently, ultrasonic techniques are the only method of qualifying on the Inspection Committee mockups in accordance with BWRVIP-03.

I Vermont Yankee, through RFO 20 (1998), visually inspected the jet pump beams in accordance with SIL 330, Supplement 2 and RICSIL 065 (References 10.5.26 and i 10.5.28) per commitments in References 10.5.33 and 10.5.35 below in order to address GE RICSIL, No. 065; GE SIL No. 330, Supplement 2; and NUREG/CR-3052.

This required that the beams be visually inspected in one loop every refueling outage p

on an alternating basis. Because the ultrasonic method is much more capable of i

detecting flaws in the relevant areas of the beam bolt than the visual method, the BWRVIP methodology wiIl be adopted. The aforementioned internal commitment is 1..

considered revised accordingly, with the issuance of this document.

During RFO 23 (2002), all beams were also visually inspected in the transition region to address RICSIL 086 and the beam failure at Quad Cities (see References 10.5.75 and 10.5.76).

Appendix B PP 7027 Rev. 3 Page 35 of 65

APPENDIX B (Continued) 10.1.2. Riser Thermal Sleeve Welds These welds are currently inaccessible for inspection, and per BWRVIP-41, Table 3.3-1, "Inspection is recommended when the technique becomes available." Because a technique still does not exist, VY has complied with this document as of its publication. Inspection of 50% of these welds would be required within the first six-year interval and the other 50% within the six.-year interval following that. After those first twelve years, inspection of 25% of these welds within each subsequent six-year interval would be required. This inspection frequency is determined from BWRVIP-41, Table 3.3-1. BWRVIP-41 is not clear when the six or twelve years begins for these hidden welds; additionally, the BWRVIP Assessment Committee is currently evaluating the necessity of performing these examinations.

i i BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the riser thermal sleeve welds as modified VT-1. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MVT-1 method with the EVT-1 method.

1 .I However, visual inspection of these inaccessible welds will probably not be possible, and ultrasonic testing will most likely be required. BWRVIP-41, Paragraph 3.2.4, states that, "In all cases where a (visual) inspection is recommended.. .a suitable NDE examination technique meeting the requirements of BWRVIP-03 may be substituted."

1 A Technical Justification in accordance with PP 7027, Paragraph 4.2.3 and BWRVIP-94is in the course of preparation to defer examination of these welds until I such time that tooling and an NDE technique become available.

10.1.3. Riser Welds An ultrasonic baseline inspection of 26 of these 30 welds (three per riser) was performed in RFO 20 (1998). The remaining four welds received a modified VT-1 (with cleaning performed) inspection. The ultrasonic inspection identified indications on four thermal sleeve-to-elbow welds (N2B-RS-1, N2C-RS-1, N2H-RS-1, and N2K-RS-1). Vermont Yankee received an SER from the NRC (Reference 10.5.61 below) to allow deferral of inspection for these four welds with UT indications until RFO 22 (2001). During RFO 22 these four riser welds were reinspected by UT with the result that two of the previous indications were found to be liftoff of the transducers, and therefore nonrelevant. The indications in the remaining two welds (N2H-RS-1 and N2K-RS-1) had not grown. One of the welds was inspected visually in the area of the UT indications and no cracking was seen. Technical Evaluation No. TE-2003-0021 (Reference 10.5.82) was prepared in order to allow these welds to be inspected by EVT-1 rather than by UT going forward. Per TE-2003-0021, these welds are to be inspected every two cycles. Welds N2H-RS-1 and N2K-RS-1 were inspected by EVT-1 during RFO 24 (2004) with no indications identified. If after three successive inspections with no recorded indications of cracks, TE-2003-0021 states that VY will revert to the six-year inspection interval specified in BWRVIP-41.

Appendix B PP 7027 Rev. 3 Page 36 of 65

APPENDIX B (Continued)

After a baseline inspection has been completed within the first six-year interval, inspection of 50% of the riser welds is required within each subsequent six-year interval, This inspection frequency is determined from BWRVIP-41, Table 3.3-1.

The second 6 year baseline of 50% of the riser welds were completed in RFO 24 (2004).

BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the riser welds as modified VT-1. Per References 5.5.19 and 5.5.22, the BWRVDP committed to the NRC to replace the MVT-1 method with the EVT-1 method. BWRVIP-$1, Paragraph 3.2.4, states that, "In all cases where a (visual) inspection is recommended.. ,a suitable NDE examination technique meeting the requirements of BWRVIP-03 may be substituted." Therefore, for these welds an EVT-1 or a UT technique is acceptable.

The above BWRVIP methodology exceeds the commitment in References 10.5.47 and 9.5.49 below, which was generated in order to address GE SIL No. 605. This would have required that the two elbow riser welds be visually inspected in one loop every refueling outage on an alternating basis. Because the scope has been expanded and the inspection methods have been upgraded, the BT$RVIP methodology will be adopted. The aforementioned internal commitment is considered revised accordingly, with the issuance of this document.

10.1.4. Riser-to-Restrainer and Riser-to-Brace Welds A modified VT-1 baseline inspection of 50% these welds was performed in the first six year interval during RFO 20 (1998). The EVT-1 baseline inspection of the other 50% required within the second six-year interval was performed in RFO 24 (2004).

After those first twelve years ending with RFO 27 (2008), inspection of 25% of these welds within each subsequent six-year interval would be required. This inspection frequency is determined from BWRVIP-41, Table 3.3-1.

BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the riser-to-restrainer welds as modified VT-1. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MYT-1 method with the EVT-1 method. In the future, these welds will be examined with the EVT-1 method.

'0.1.5. Riser Braces A modified VT-1 baseline inspection was performed in the first six year interval on 50% of these welds during RFO 20 (1998). The EVT-1 baseline inspection of the other 50% required within the second six-year interval was performed in RFO 24 (2004). After those first twelve years ending with RFO 27 (2008), inspection of 25%

of these welds within each subsequent six-year interval would be required. This inspection frequency is determined from BWRVP-41, Table 3.3-1 and BWRW-48, Table 3-2.

Appendix B PP 7027 Rev. 3 Page 37 of 65

APPENDIX B (Continued)

BWRVIP-41, in Table 3.3-1 and BWRVIP-48, in Table 3-2 identify the method of inspection for the riser brace and vessel attachment welds as modified VT-1. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MVT-1 method with the EVT-1 method. In the future, these welds will be examined with the EVT-1 method Vermont Yankee, through RFO 20 (1998), visually inspected the jet pump riser brace welds in accordance with References 10.5.19 and 10.5.31 below in order to address GE RICSIL No. 045 and GE SIL No. 551. This requires that the riser brace welds be inspected in one loop every refueling outage on an alternating basis. All jet pump riser brace welds have been inspected and no findings have been reported. This internal commitment is considered revised by the above BWRVIP inspection methodology with the issuance of this document.

I-. d 10.1.6. Inlet Clamr, Bolts 1.I A VT-3 baseline inspection of 50% the inlet clamp bolted connections was performed in RFO 20 (1998). No degradation has ever been identified. A VT-3 50% baseline inspection on the balance of inlet clamp bolted connections was performed in RFO 24 (2004)for the second 6 year inspection interval. After those first twelve years, ending in RFO 27 (2008),inspection of 25% of the bolted connections within each subsequent six-year interval would be required. This inspection frequency is determined from BWRVIP-41, Table 3.3-1.

BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the inlet clamp bolts as VT-3.

10.1.7. Restrainer Assemblies i

I 1 A modified VT-1 baseline inspection of 50% of the restrainer wedges was performed in RFO 20 (1998). No movement or wear of the wedges has ever been identified. Per L . --I BWRVP after a baseline inspection of 50% of the wedges is performed in the first six-year interval - inspection of the other 50% is required within the second six-year interval. After those first twelve years, inspection of 25% of the wedges within each subsequent six-year interval would be required. This inspection frequency is determined from BWRVIP-41, Table 3.3-1.

Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and decided to increase this inspection frequency in order to be conservative and to also address the risk to generation consequences of restrainer failure. Vermont Yankee intends to perform inspection of the restrainer wedges in one loop every other outage. Therefore, only every other inspection performed on the restrainer wedges would be mandatory.

Appendix B PP 7027 Rev. 3 Page 38 of 65

I .

APPENDIX B (Continued)

BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the restrainer wedges as VT-1. If movement or wear of the wedge bearing surface is detected, inspection of the other restrainer components and locations, such as the bracket welds and the adjusting set screws, is required to assess the cause of movement.

Vermont Yankee, through RFO 20 (1998), visually inspected the jet pump adjusting screws (sometimes called the set screw or restrainer stop) in accordance with References 10.5.38, 10.5.43, and 10.5.51below in order to address GE SIL No. 574 and GE RICSL No. 078. This requires that setscrew gaps and the two tack welds on each of the two setscrews per jet pump be inspected. One loop has been performed each refueling outage on an alternating basis. All setscrews have been inspected and no findings were reported.

Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and agreed that even though the set screws were non-safety related, that in order to address the economic consequences of restrainer failure, the setscrew inspections should continue to be performed, but on a reduced frequency. Vermont Yankee will perform inspection of the setscrews in one loop every other outage. These inspections will be VT-3s. The above internal commitment is considered revised by the above B W R W inspection methodology with the issuance of this document. This commitment is only an internal commitment and could be changed or deleted in the future. Therefore, the inspections are considered nonmandatory. BWRVIP 41 -A criteria for inspecting jet pump wedge assembIy set-screw has been revised by letter (Reference 10.5.87) to require set-screw inspection only after wedge assembly surface wear has been identified. Therefore, the above outlined VT-3, non-mandatory, set-screw inspection will not be performed unless wedge assembly surface wear is identified.

BWRWP 41-A has been issued to the Executive Committee, which changed restrainer bracket assembly inspection recommendations. The purpose of inspecting the restrainer bracket assembly is to detect wear. The causes for wedge wear are related, but not limited to, increase in jet pump drive flow andor core flow, set screw gaps and slip joint differential pressure which can increase vibration loads. If wear is detected, inspection of the other restrainer componentsflocation such as bracket weld locations, the adjusting screw, wedge rod, not weld, etc., as applicable, should be performed during the same outage when wedge wear was detected to assess the cause of wear.

The baseline inspection of the wedge and bearing surfaces is required over the next two outages with 50% being inspected in the next refueling outage (Reference 10.5.87). The re-inspection is 25% each inspection cycle. If wedge wear is detected, then no wedge re-inspection shall exceed 6 years.

Appendix B PP 7027 Rev. 3 Page 39 of 65

APPENDIX B (Continued)

Since RFO 20 (1998) VY has visually examined 50% of the jet pump wedges every other outage. During RFO 22 (2001) and RFO 24 (2004) 100% of the jet pump wedge assemblies were examined by VT-1 with no wear indicated. Inspections over the next inspection cycle of six (6) years, RFO 25 (2005), RFO 26 (2007), RFO 27 (2008), and RFO 28 (2010) five (5) jet pump wedge assemblies will be inspected and then 25%more over the next 6 years and so forth.

This inspection strategy satisfies the 100%baseline examination requirement using the prescribed inspection method. The power up-rate has been considered in this inspection strategy. VY has not commenced with up-rated power conditions as of the publication date 11/4/04, but is scheduled to commence during cycle 24 (2005).

However core flow is only increasing a small amount (Reference Email 10.5.88) and remains within the original licensed limit, therefore increased jet pump vibration is not anticipated (Reference 10.5.89). VY complies with the requirements of B W R W 41 as amended by the 2004 letter (Reference 10.5.87). This inspection strategy supercedes the internal commitment outlined above for inspecting 50% of the jet pump wedge assemblies every other outage.

and set screws. This S L has tions at Vermont Yankee, as in Reference 10.5.71.

10.1.8. Mixer Inlet isual inspection of the mixer inlets ce 10.5.44 below provides It recommends that Vermont Yankee continue to monitor jet pump performance via the Reactor Engineering Jet Pump Performance Monitoring Program,which trends various critical parameters important for tracking jet pump efficiency. This reference also recommends making no plans to perform additional jet pump internal visual inspections, unless it is deemed necessary from indications of degraded performance from the trended data. It may, however, be advisable in the future to perform this inspection (and/or to perform mixer inlet cleaning) if jet pump performanc ps below a critical level.

10.1.9. MixerDiffuser Circumferential Welds above Diffuser Shell A baseline inspection of a minimum of 50% of these welds was required within the current six-year interval, which began December 1997 when BWRVIP-41 was first published. Because 100%were examined in RFO 21 (1999), these welds do not require reinspection until the next 12-year interval. After the first twelve-year interval, inspection of 25%of these welds within each subsequent six-year interval would be required. This inspection frequency is determined from BWRVIP-41, Table 3.3-1.

Appendix B PP 7027 Rev. 3 Page 40 of 65

APPENDIX B (Continued)

BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the mixer and diffuser circumferential welds as modified VT-1. Per References 5.5.19 and 5.5.22, the B W R W committed to the NRC to replace the MVT-1 method with the EVT-1 method. BWRVIP-41, Paragraph 3.2.4, states that, "Inall cases where a (visual) inspection is recommended., .a suitable MIE examination technique meeting the requirements of BWRVIP-03 may be substituted." Therefore, for these welds an EVT-1 or a UT technique is acceptable.

10.1.10. DiffuserlAdaDter Circumferential Welds below Diffuser Shell A baseline inspection of 50% of these welds was required at the next refueling outage following publication of BWRVIP-41. For Vermont Yankee this would have been during RFO 20 (1998). Baseline inspection of the other 50% of these welds was required within t h e first six-year interval. Instead of the above guidance, Vermont Yankee elected to perform 100% of these welds in RFO 21 (1999) using a UT technique. Therefore, Vermont Yankee did not comply with BWRVIP-41 as of its publication for these particular welds. However, those welds were examined within two cycles of the publication of BWRVIP-41 in accordance with guidelines later published in BWRVIP-94. After a baseline inspection has been completed within the first six-year interval, inspection of 50% of these welds is required within each subsequent six-year interval. This inspection Erequency is determined from BWRVlP-41, Table 3.3-1.

The FWO 21 (1999) ultrasonic inspection identified indications in four diffuser welds (2-DF-2,3-DF-3, 9-DF-2, and 10-DF-2). Vermont Yankee performed an analysis (Reference 10.5.69below) to allow deferral of inspection for the most limiting of these four welds until RFO 23 (2002). The RFO 23 (2002) UT measured flaw lengths were the same as found in RFO 21 (1999) within the documented NDE accuracy.

These welds were inspected visually from the ID of the jet pump and no cracking was seen (one weld was also inspected on the OD). Technical Evaluation No.

TE-2003-0021 (Reference 10.5.82) was prepared in order to allow these welds to be inspected by EVT-1 rather than by UT going forward. Per TE-2003-0021, these welds are to be inspected every two cycles. If after three successive inspections with no recorded indications of cracks, TE-2003-0021 states that VY will revert to the six-year inspection interval specified in BWRVIP-41.

BWRVIP-41, in Table 3.3-1, identifies the method of inspection for the diffuser and adapter circumferential welds as modified VT-1. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MVT-1 method with the EVT-1 method. BWRVIP-41, Paragraph 3.2.4, states that, "In all cases where a (visual) inspection is recommended.. .a suitable NDE examination technique meeting the requirements of BWRVZP-03 may be substituted." Therefore, for these welds an EVT-1 or a U T technique is acceptable.

Appendix B PP 7027 Rev. 3 Page 41 of 65

APPENDIX B (Continued) 10.1.11. Sensing Lines Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and agreed to inspect jet pump sensing lines and their brackets in order to address the economic consequences of sensing line failure. Vermont Yankee intends to perform these nonmandatory inspections of the sensing lines in one loop every other outage. These inspections will be VT-3s.

10.2. ASME Section XI Applicability Inspection of the jet pump riser braces is also governed by ASME Section XI, Table IWB-2500-1, Category B-N-2, Item No. B 13.20, "Interior Attachments Within Beltline," which requires a VT-1 inspection once each ten-year interval, typically performed at the end of the interval. The inspection method given above by the BWRVIP requirements (EVT-1) exceeds the ASME Section XI requirements (VT-1). However, the inspection frequency would be less conservative - 100% in the first twelve-year BWRVlP interval instead of 100% in the Section XI ten-year interval - and 50% in subsequent twelve-year BWRVP intervals thereafter. VY has submitted a Relief Request (RI-01) for the fourth ten-year Section XI interval that would allow using the BWRVlP guidance rather than the Section XI Categories B-N-1 and B-N-2 requirements. VY will perform inspections accordingly, based on the outcome of the Relief Request.

10.3. Other Commitments This Program supersedes various internal commithents. They are discussed above with regard to the jet pump beams, riser circumferential welds, riser brace welds, and the restrainer setscrews.

10.4. Inspections for Risk to Generation Purposes There are two jet pump components that are intended to be inspected solely for risk to generation purposes. These are the restrainer set screws and the sensing lines. Current B W R W guidance

-1 (Reference 10.5.87) no longer requires set screw inspections, instead wedge surface inspections are performed, resultant wear is a good indication of vibration which would require set screw inspections. Therefore set screw inspection will not be performed unless surface wear is

'1 detected. There is also one case noted above for the mixer inlets where inspections may be indicated, based on operational performance.

10.5. References 10.5.1. NRC IE Bulletin 80-07, dated April 4,1980, "BWR Jet Pump Assembly Failure" 10.5.2. Memorandum L. H. Heider to B. H. Grier, dated May 8, 1980, "Response to IE Bulletin; BWR Jet Pump Assembly Failure" 10.5.3. NRC IE Bulletin 80-07, Supplement 1, dated May 13,1980, "BWR Jet Pump Assembly Failure" 10.5.4. GE SIL No. 330, dated June 9,1980, "Jet Pump Beam Cracks" 10.5.5. GE SIL No. 330, SuppIement 1, dated February 1981, "Jet Pump Beam Cracks" Appendix B PP 7027 Rev. 3 Page 42 of 65

APPENDIX B (Continued) 10.5.6. Memorandum B. R. Buteau to R. E. Kenney, dated May 27,1981, "Vermont Yankee Implementation of SIL No. 330 Regarding Jet Pump Beam Cracking" 10.5.7. Letter R. F. Thibault (GE) to W. P Murphy, dated May 14, 1982, "Jet Pump Beam Test Results" 10.5.8. Memorandum B. R. Buteau to VY PORC, dated September 28, 1982, "Closeout of PORC Follow Item 81-55-01,Evaluation of GE Jet Pump Beam Test Results and Recommended Surveillance Program" 10.5.9. NUREG/CR-3052, dated November 1984, "Closeout of IEBulletin 80-07:BWR Jet Pump Assembly Failure" 10.5.10. GE SIL No. 420, dated March 28, 1985, "Inspection of Jet Pump Sensing Lines" 10.5.11. Memorandum G. A. "Englesson to L. P. Lopriore, dated September 20, 1985, "Inspection of Jet Pump Sensing Lines SIL 420" 10.5.12. Memorandum G. A. "Englesson to D. D. Bauer, dated September 23, 1985, "Response to MD Commitment Item SIL 420" I '

10.5.13. Memorandum B. R. Buteau to R. J. Wanczyk, dated October 18,1985, "Response to I ..*

Commitment Item Regarding Review of GE SIL 420f 10.5.14. GE SILNo. 465, dated May 17, 1988, "Jet Pump Mixer Unusual Surface Observations" 1- 4 10.5.15. Memorandum J. C. Brooks to B. R. Buteau, dated August 16, 1988, "Review of SILO465" 10.5.16. Memorandum J. C. Brooks to B. R. Buteau, dated March 14, 1989, "Inspection of One Loop of Jet Pump Inlet Mixers" 10.5.17. GE MCSIL No. 045, dated October 16, 1989, "Jet Pump Riser Brace Crack" 10.5.18. Memorandum C. B. Cameron to R. E. McCullough, dated October 20,1989, "Preliminary Review to RICSILO45" 10.5.19. Memorandum J. C. Brooks to B. R. Buteau, dated November 2,1989, "Review of RICSlL No. 045, Jet Pump Riser Brace Crack 10.5.20. Memorandum R. A. Current to T. A. Watson, dated September 2, 1992, "Recirc "A" Flow Anomalies" 10.5.21. Memorandum T.G. Stetson to R. E. McCullough, dated February 11,1993, "Response to Commitment RCE9214 On Inspecting Jet Pump Throat Area" 10.5.22. GE SIL No. 551, dated February 26, 1993, "Jet Pump Riser Brace Cracking" 10.5.23. GE SIL No. 465, Supplement 1, dated April 30,1993, "Surface Observations on Jet Pump Mixers" 10.5.24. GE SIL, No. 573, dated October 5,1993, "Jet Pump Nozzle Plug Modification" 10.5.25. GE SIL No. 574, dated October 5, 1993, "Jet Pump Adjusting Screw Tack Weld Failures" 10.5.26. GE SIL No. 330, Supplement 2, dated October 27, 1993, "Jet Pump Beam Cracks

10.5.27. N O Significant Event Notification, dated November 9, 1993, "Unanticipated Reactor Recirculation Jet Pump Failure During Power Operation" 10.5.28. GE RICSIL No. 065, dated December 3,1993, "Jet Pump Beam Cracking" 10.5.29. NRC Information Notice 93-01, dated December 17, 1993, "Jet Pump Hold-down Beam Failure" 10.5.30. Operating Experience Review Report, dated December 27, 1993, "Jet Pump Hold Down Beam Failure" Appendix B PP 7027 Rev. 3 Page 43 of 65

APPENDIX B (Continued) 10.5.31. Memorandum T. G. Stetson to R. E. McCullough, dated January 27,1994, "Response to SE0551, Jet Pump Riser Brace Cracking" 10.5.32. Memorandum T. G. Stetson to D. C. Porter, dated January 27, 1994, "Service Request

- Effect of Increased Recirc Pump Speed on Reactor Internals" 10.5.33. Memorandum T. G. Stetson to R. E. McCullough, dated February 18,1994, "Response to Commitment RICSIL065, Jet mUnp Beam Cracking" 10.5.34. Memorandum T. G. Stetson to R. E. McCullough, dated February 18,1994, "Response to Commitment SEN105 on Jet Pump Failure" 10.5.35. Memorandum T. G. Stetson to R. E. McCullough, dated February 18,1994, "Response to Commitment SILO330S2" 10.5.36. Letter M. 0. Lenz (GE) to M. E. Shepherd (GE), dated March 4,1994, "Vermont Yankee Jet Pump Beam-Bolt Assemblies" 10.5.37. Memorandum J. Cihak to M. P. Benoit, dated March 4,1994, "Commitment SlLo573" 10.5.38. Memorandum T. G. Stets llough, dated April 19, 1994, "Response to Commitment SILO574" 10.5.39. Memorandum T. G. Stetson .E. McCuIlough, dated May 9,1994, "Response to Commitment SILO465S1, Surface Observations on Jet Pump Mixers" 10.5.40. ough, dated May 19,1994, "Response to G/CR'-3052on Jet Pump Beams" 10.5.41. Memorandum T. G. y 22, 1995, "Response to Commitment SE04 10.5.42. GE RICSIL, No. 078, Restrainer Bracket Set Screw Gaps" 10.5.43. Memorandum T.G. Stetson to ough, dated July 11,1996, "Response to Commitment RICSILO78" 10.5.44. Memorandum T. G. Stetson to ullough, dated October 25, 1996, "Response to Commitment SIZx)465SlRE2' 10.5.45. GE SIL No, 605, dated December 6, 1996, "Jet Pump Riser Pipe Cracking" 10.5.46. NRC Information Notice 97-02, dated February 6, 1997, "Cracks Found In Jet Pump Riser Assembly Elbows at Boiling Water Reactors" 10.5.47. Memorandum T. G. Stetson to R. E. McCullough, dated February 7, 1997, "Response to Commitment SIL0605" 10.5.48. GE SIL No. 605, Revision 1, dated February 25, 1997, "Jet Pump Riser Pipe Cracking" 10.5.49. Memorandum T. G. Stetson to R. E. McCullough, dated April 9, 1997, "Response to Commitment SIL0605R1 I' 10.5.50. Memorandum T. G. Stetson to R. E. McCullough, dated April 9, 1997, "Response to Commitment INF97002" 10.5.51. Memorandum D. C. Girroir to P. B. Corbett, dated August 19,1997, "AP0028 CAT A Item ## OE8428" 10.5.52. BWRVIP-41, dated October 1997, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines" 10.5.53. GE Nuclear Energy Final Report No. lHQXE, Rev. 0, dated April 1998, "Vermont Yankee Nuclear Plant Unit 1 Recirculation Inlet Riser Ultrasonic Examination" 10.5.54. BWRVIP-51, dated May 1998, "Jet Pump Repair Design Criteria" Appendix B PP 7027 Rev. 3 Page 44 of 65

APPENDIX B (Continued) 10.5.55. Letter VYNPC to USNRC,dated May 4, 1998, BVY 98-67, "Jet Pump Riser Circumferential Weld Inspections" 10.5.56. Letter USNRC to VYNPC,dated June 3, 1998, NVY 98-77, "Request for Additional Information Regarding Jet Pump Riser Circumferential Weld Inspections at Vermont Yankee NuclearPower Station (TAC No. MA 1681)"

10.5.57. GE-NE-B 13-0 1935-02, Revision 1, dated July 1998, "Jet Pump Assembly Welds Flaw Evaluation Handbook for Vermont Yankee" 10.5.58. Letter VYNPC to USNRC, dated July 30, 1998, BVY 98-1 12, "Response To Request for Additional Information Regarding Jet Pump Riser Circumferential Weld Inspections" 10.5.59. Letter USNRC to VYNPC,dated October 26, 1998, NVY 98-153, "Jet Pump Riser CircumferentialWeld Inspections at Vermont Yankee Nuclear Power Station (TAC No. MA 168 1)" (includes original one-cycle SER) 10.5.60. Letter VYNPC to USNRC, dated March 29, 1999, BVY 99-43, "Jet Pump Riser CircumferentialWeld Inspections and Flaw Evaluation" 10.5.61. Letter USNRC to VYNPC, dated April 29, 1999, NVY 99-46, "Jet Pump Riser Circumferential Weld Inspections at Vermont Yankee Nuclear Power Station (TAC I No. MA5109)"(includes two-cycle SER) 10.5.62. Letter Vermont Yankee to USNRC, dated May 27, 1999, BVY 99-73, "Reactor r Vessel Internal Plans for the 1999 and 2001 Refueling Outages" I 1c J 3 . GE Nuclear Energy Report No. GE-NELB13-01935, Revision 2, dated July 1999, "Jet Pump Assembly Welds Flaw Evaluation Handbook for Vermont Yankee" 10.5.64. V m d u m John Hoffman to Tom Silko, dated July 30, 1999, "Jet Pump Riser ir Cycle 21 Operation" SNRC to BWRVIP,dated September 29, 1999, "Final Safety Evaluation of v zssei ID Attachment Weld Inspection and Flaw Evaluation GuideIines (BWRVIP-48)"'

10.5.6fi;. hL -2orandumJ. M. Abdelghany to John Hoffman, dated October 22,1999, "Vermont V;l 2 Allowable Jet Pump Weld Leakage Rates for LOCA and Recirculation Pump k.

~

iance" E Yankee Report by David B. King, dated October 12, 1999, "Study to I

Oett- i e Cause for Rejection of Jet Pump Beams at Vermont Yankee and Monticello" 10.5.68. MemorandumC. B. Larsen to John Hoffman, dated November 15,1999, "Application of Uncertainty to Jet Pump Diffuser UT Indications" 10.5.69. Memorandum John Hoffman to D. C. Girroir, dated November 26,1999, "Jet Pump Assembly Inspection Discrepancy Report Evaluation" 10.5.70. GE SIL No. 629, dated July 1 1,2000, "Inlet-mixer Wedge Damage In BWR Jet Pump Assemblies" 10.5.71. Action Item / Regulatory Commitment SIL-0629-00, initiated August 16,2000, "Inlet-mixer Wedge Damage In BWR Jet Pump Assemblies" 10.5-72. Letter USNRC to BWRVIP,dated February 4,2001, "Final Safety Evaluation of the BWRVIP,BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines (BWRVIP-41)

10.5.73. GE Report JXOAL,Revision 0, dated May 2001, "Vermont Yankee Recirculation Inlet Riser Ultrasonic Examination" Appendix B PP 7027 Rev. 3 Page 45 of 65

APPENDIX B (Continued) 10.5.74. Memorandum C. B. Larsen to John Hoffman, dated May 9,2001, Jet Pump NDE Uncertainty" 10.5.75. Technical Evaluation No. 2001-030, dated May 14,2001, "Evaluation of Jet Pump Riser Flaws" 10.5.76. GE RICSIL, No. 086, dated January 28,2002, "Cracking in the Transition Region of a Jet Pump Beam" 10.5.77. Action Item / Regulatory Commitment RICSIL-086-01, dated January 29,2002, "Cracking in the transition region of a jet pump beam" 10.5.78. Action Item / Regulatory Commitment BWRVP-028-A-01, dated June 6,2002, "Evaluate BWRVIP-28-A and define solutions as required" 10.5.79. Action Item / Regulatory Commitment BWRVIP-028-A-02, dated July 8,2002, "Generate ERFTS Point IDS for JP M Ratio" 10.5.80. Action Item / Regulatory Commitment BWRVIP-028-A-03, dated July 8,2002, "Revise DP 0455 Jet Pump M Ratio Startup Checklist" 10.5.81. Action Item / Regulatory Commitment BWRVIP-028-A-04, dated July 8,2002, "Revise OP 41 10 - Jet Pump M Ratio Required Action" 10.5.82. FRA-ANP Final UT Report, dated December 9,2002, %-Vessel Ultrasonic Examination Final Report" 10.5.83.

ds with UT Indications" 10.5.84. GE RICSIL No. 088, dated April 4,2003, "Jet Pump Beam Records" 10.5.85. Letter Carl Terry (BWRVIP Executive Chairman) to all BWRVIP Committee members, dated May 2,2003, "Recommended Actions for GENE RISE 088" 10.5.86. Technical Justification 2004-02, dated 03/26/04, "Justification for Deferral of Inspection of Inaccessible Welds" 10.5.87. BWRVIP Letter 2004-047, R. Dyle/T. Mulford to the Assessment and Integration bers, Re: Request for Review & Approval to Transmit Revised Jet pection Guidance for BWKVIP 41-A to the Executive Committee, dated February 2,2004.

10.5.88. Email from Robert Vita to J. Lafferty, Re: Flow Induced Vibration, dated October 14, 2004.

10.5.89. General Electric "Safety Analysis Report for VY Nuclear Power Station Constant Pressure Power Uprate," NEDC-33090P, Revision 0, dated September 2003.

Appendix B PP 7027 Rev. 3 Page 46 of 65

APPENDIX B (Continued) 11.0 Lower Plenum 11.1. Components in the lower plenum (areas below the core plate) are discussed in other Paragraphs of this Appendix, as referenced below:

a CRD housings, CRD housing caps, CRD stub tubes - Paragraph 1.0 0 Core plate beam fillet welds, core plate rim hold-down bolts, core plate alignment hardware -Paragraph 2.0 I 0 Core shroud support legs, core shroud support baffle plate underside - Paragraph 4.0 0 Incore flux monitor housings, incore flux monitor guide tubes, incore flux monitor guide tube stabilizers - Paragraph 8.0 e SLC and core plate AP lines - Paragraph 15.0 11.2. In addition, for risk to generation purposes, if access is gained to the lower plenum, the vessel bottom head and the bottom head drain should be inspected for debris or crud buildup. Debris and crud are foreign material concerns for the fuel cladding and the bottom head drain line.

12.0 Miscellaneous Vessel Internal Attachments flncluding Steam Dryer, Specimen Holder, Guide Rod) 12.1. BWRVIP Document Applicability Inspection requirements for the core spray, feedwater sparger, and jet pump vessel attachments are found in other sections of this document. This section will address inspection requirements for all other vessel internal bracket attachments. BWRVIP-48, published in February 1998, governs inspection of the reactor vessel internal attachment welds. Vermont Yankee has complied with this document as of its publication.

However, BWRVIP-48, Table 3-2, states that, No additional inspections (for the steam dryer support and hold-down, guide rod, and surveillance specimen holder attachment welds) are required above those specified in a plants ASME Section ICT program. The inspection frequency is per ASME?Section XI, Table TWB-2500-1, Category B-N-2 (once in each ten-year interval). One exception is listed in BWRVIP-48, Table 3-2, which requires that steam dryer support attachment welds that use furnace-sensitized stainless steel or Alloy 182 material be examined by the modified VT-1 method. The reactor vessel was heat treated subsequent to welding of these attachment pads. There is no evidence at this time that the steam dryer support attachment welds were not furnace-sensitized. Per References 5.5.19 and 5.5.22, the BWRVIP committed to the NRC to replace the MVT-1 method with the EVT-1 method. Therefore the steam dryer support attachment welds were +vi-&be inspected with the EVT-1 method in RFO 23 (2002).

Appendix B PP 7027 Rev. 3 Page 47 of 65

APPENDIX B (Continued) 12.2. ASME Section M Atmlicability The vessel internal attachment welds are examined in accordance with ASME Section XI, Table IWB-2500-1, Category 5-N-2,Item Nos. B13.20 and B13.30. Table TWB-25004, Item No.

B 13.20, "Interior Attachments within Beltline Region" requires accessible welds to be visually inspected by the VT-1 method once per ten-year interval. The only interior attachment welds within the beltline region are the jet pump riser brace attachment welds and the lower surveillance specimen bracket attachment welds. (Inspection of jet pump riser brace attachment welds is specified in Appendix J, "Jet Pumps".) Table IWB-2500-1, Item No. B13.20, "Interior Attachments within Beltline Region" requires accessible welds to be visually inspected by the VT-1 method once per ten-year interval. Table IWB-2500-1, Item No. B13.30, "Interior Attachments Beyond Beltline Region", requires accessible welds to be visually inspected by the VT-3 method once per ten-year interval. Therefore, the surveillance specimen holder bracket attachment welds will be inspected with the VT-1 method (the upper specimen holder bracket will be upgraded from a VT-3 method to a VT-1 method), and the steam dryer hold-down brackets and guide rod brackets will be inspected with the VT-3 method. The steam dryer support brackets will be upgraded to EVT-1 as per the above BWRVIP direction. (Inspection of core spray piping br hment welds are specified in the "Core Spray Internal Piping and Spargers" Section. of feedwater sparger bracket attachment welds is specified in the "Feedwater Spargers" Section.) AI1 bracket attachment w XI ten-year interval w conducted during RFO 23 (2 (RI-01) for the fourth year Section X I interval that rather than the Section XI Categories B-N-1 and B inspections accordingly, based on the outcome oft BWRVIP references ASME Section XI for the brackets, these inspections would be performed exactly as stated above.

12.3. Other Commitments In RFO 16 (1992), cracking in cladding in the vessel head and shell interior was discovered at Vermont Yankee. The inspection was initiated in response to GE FUCSIL No. 050 and GE SIL No. 539. One of these cracks was adjacent to the dryer support bracket at 215 degrees. It was determined through u sonic manual sizing from the outside of the reactor vessel at this location that the crack did not propagate into the vessel base-material pressure boundary.

BWRVIP-48, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines," requires in Table 3-2, Note (l), that for indications that are detected visually, ultrasonic inspections should be performed to determine if the indication has propagated into the reactor vessel base material. Paragraph 3.2.1 states, "For any flaws which are found to have propagated into the base material, an evaluation should be performed in accordance with the requirements of ASME Section XI, Paragraph IWB-3600." Vermont Yankee's commitment to the NRC in References 12.5.2 and 12.5.9 below follows this logic.

Appendix B PP 7027 Rev. 3 Page 48 of 65

APPENDIX B (Continued)

Even though the flaw did not propagate into the reactor pressure vessel boundary, Vermont Yankee committed to the NRC (References 12.5.2and 12.5.9 below) to perform successive examinations similar to ASME Section XI, IWB-Z420(b), of this clad crack. In this way, this clad crack would be treated as if it were indeed a defect that exceeded the ASME Section XI acceptance criteria, even though it did not. Paragraph IWB-2420(b) requires that areas containing flaw indications that have been accepted analytically be reexamined during the next three inspection periods.

RFO 16 (1992) fell in the third period of the second interval. The dryer support bracket flaw was visually and ultrasonically reexamined in RFO 17 (1993), which fell in the first period of the third interval. In RFO 20 (1998), this examination was repeated, which satisfied the second successive reexamination (second period, third interval) for this flaw. During RFO 22 (2001),

the third successive re-examination was completed (third period of the third interval).

12.4. Inspections for Risk to Generation Purposes - None.

12.5. References 12.5.1. Letter Arthur Shepard to J. J. Cihi (GE), dated September 22, 1970, "Overlay of RPV Intemals Bracket and Pad Areas in Accordance with GE'FDI #78" 12.5.2. Letter Vermont Yankee to USNRC,BVY 92-055, dated April 5, 1992, "Proposed Alternative for Compliance with 10CFR50.55a Regarding RPV Cladding Indications" 12.5.3. Letter Vermont Yankee to USNRC,dated April 10,1992, "Supplemental Information Regarding Proposed Alternative for Compliance with 10CFR50.55a Regarding RPV Cladding Indications" 12.5.4. Letter USNRC to Vermont Yankee, dated April 17,1992, "Meeting Summary of April 8,1992 Meeting To Discuss Vermont Yankee Reactor Vessel Haws" 12.5.5. Letter USNRC to Vermont Yankee, dated April 17,1992, "Disposition of Reactor Vessel Cladding Indications Discovered During the March 1992 Refueling Outage At Vermont Yankee Nuclear Power Station" 12.5.6. Memorandum F. J. Helin to PORC, dated April 17,1992, "Clad Indications Found During 1992 Refueling Outage" 12.5.7. EPRI TR-101971, dated February 1993, "Evaluation of Reactor Pressure Vessel Head Cracking in Two Domestic BWRs" 12.5.8. Letter Vermont Yankee to USNRC, dated July 1, 1993, "1993Refueling Outage Vessel Clad Inspection Plans" 12.5.9. Letter Vermont Yankee to USNRC, dated October 6, 1993, "Reactor Vessel Clad Inspection during the 1993 Refueling Outage" 12.5.10. BWRVIP-48, dated February 1998, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines" 12.5.11. BWRVIP-52, dated June 1998, "Shroud Support and Vessel Bracket Repair Design Criteria" 12.5.12. Letter Vermont Yankee to USNRC, dated May 27,1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" Appendix B PP 7027 Rev. 3 Page 49 of 65

APPENDIX B (Continued) 12.5.13. Letter USNRC to BWVIP, dated September 29, 1999, "Final Safety Evaluation of

'Vessel ID Attachment Weld Inspection and Flaw EvaIuation Guidelines, (BWRVIP-48)"'

12.5.14. Action Item / Regulatory Commitment BWRVIP-048-A-01, dated August 5,2002, "Evaluate BWRW-48-A: Vessel ID Attachment Weld Inspection and FIaw Evaluation Guidelines" 13.0 Orificed Fuel Support Castings 13.1. BWRVIP Document ARpkabili ty BWRVIP-47, published in December 1997, governs inspection of the orificed fuel support castings. However, BWRVZP-47 does not establish any inspection requirements for the orificed fuel support. Therefore, Vermont Yankee has complied with this document as of its publication.

13.2. ASME Section XI Apdicability The orificed fuel support castings are part of the core support structure; however, they are not integrally welded as stated in the title of ASME Section XI, Table IWB-2500-1, Category B-N-2.

Therefore the orificed fuel support castings are not subject to ASME Section XI. See Reference 13.5.2 below.

13.3. Other Commitments - None.

13.4. Inspections for Risk to Generation E'urposes - None.

13.5. References 13.5.1. BWRVIP-47, dated December 1997, "BWR Lower Plenum Inspection and Haw Evaluation Guidelines" 13.5.2. Memorandum C. B. Larsen to D. C. Girroir, dated May 13, 1999, "Definition of Core Support Structures (ASME Section XI, Category B-N-2)"

13.5.3. Letter USNRC to BWRVIP,dated October 13, 1999, "Final Safety Evaluation of

'BWRVIP,BWR Lower Plenum Inspection and Flaw Evaluation Guidelines (BWRVIP-47),' EPRI Report TR-108727, (TAC No. MA1102)"

13.5.4. Letter NRC to BWRVIP,dated December 7,2000, "Acceptance for Referencing of BWRVIP,BWR Lower Plenum Inspection and Evaluation Guidelines (BWRVIP-47) for Compliance with the License Renewal Rule (10 CFR Part 54)"

Appendix B PP 7027 Rev. 3 Page 50 of 65

L .

APPENDIX B (Continued) 14.0 Specimen Holders 14.1. B W R W Document Apulicability No BWRVlP Inspection and Evaluation document addresses the specimen holders, which are considered non-safety related components, with the exception that BWRVP-48, published in February 1998, which governs inspection of the reactor vessel internal attachment welds.

Vermont Yankee has complied with this document as of its publication. The requirements for the specimen holder attachment welds are found in the Miscellaneous Vessel Internal Attachments section. Per BWRVIP-102, Vermont Yankee is obligated to inform the BWRVIP if it intends to withdraw any of the surveillance specimen coupons twelve months prior to their planned withdrawal.

14.2. ASME Section XI Aoplicability Inspection of the specimen holder attachment welds is also governed by ASME Section XI, Table TWB-2500-1,Category B-N-2, Item No. B 13.20, "Interior Attachments within Beltline Regon."

These requirements are also found in the Miscellaneous Vessel Internal Attachments section.

14.3. Other Commitments -None.

14.4. Inspections for Risk to Generation Purposes - Vermont Yankee has determined that inspection of the surveillance specimen holders should be performed for loose part issues and to assure that i these assets are preserved. This nonmandatory inspection would coincide with the ten-year interval bracket inspection. Such an inspection was performed in RFO 23 (2003).

14.5. References 14.5.1. BWRVIP-86,dated December 2000, "BWR Integrated Surveillance Program Implementation Plan 14.5.2. BWRVIP-102, dated June 2002, "BWR Integrated Surveillance Program Implementation Guidelines Appendix B PP 7027 Rev. 3 Page 51 of 65

APPENDIX B (Continued) 15.0 Standby Liquid ControVCore Plate Delta Pressure 15.1. BWRVIP Document ADplicabilitv BWRVIP-27, published in October 1997, governs inspection of the SLC and core plate AP system. BWRVIP-27-A was issued August 2003. Vermont Yankee has complied with this document as of its publication.

BWRVIP-27-A asserts that the only safety critical welds in the SLC/Core Plate AP system within the scope of the BWRVIP are the welds outside the reactor vessel which connect the SLC system piping to the vessel. BWRVDP-27-A, Paragraph 2.1.5 and Figure 2-5 describe the Vermont 1

Yankee configuration, which is a stainless steel safe-end welded to a carbon steel forged nozzle and fabricated by CB&I. VY Drawing 5920-358 shows this configuration and Drawing 5920-5266 shows the replacement safe-end of improved material installed shortly before initial start-up. The safe-end thickness on both drawings is 7/8". BWRVIP-27-AYParagraphs 3.3.1 and 3.4.1 state the requirements for the Vermont Yankee configuration; it requires that the I .:I nozzle-to-safe end weld and the safe-end extension be examined volumetrically.

.r' BWRW-03 through Revision 5 (December 2002), in Sections 11.4.2 and 11.4.3, contained two i

qualifications of UT techniques performed by EPRI that are applicable to the SLC safe-end.

However, those two qualifications were performed on safe-ends that were E" thick, and neither qualification applied to a safe-end that is 7/8" thick. Therefore, a volumetric examination technique had not been demonstrated for this configuration to that date.

BWRVIP-27, Paragraphs 3.3.1 and 3.4.1 also stated that, "until such time as a qualified volumetric examination is available, enhanced leakage inspection during each Category B-P pressure boundary leak test should be performed." An enhanced leakage test is defined as requiring a view of this joint specifically, rather than as would normally be required by ASME Section XI, which would be an examination for leakage in the general area. Per BWRVP-27-A, insulation removal is required. This was not clarified until BWRVIP-27-A was issued as a draft in July 2002. Until that time the need for insulation removal was not explicitly stated (in BWRVIP-27) and VY did not do such in RFO 20 (1998), RFO 21 (1999), and RFO 22 (2001).

Per BWRVIP-27-A, Paragraphs 3.3.1 and 3.4.1, a surface examination performed every other

' i refueling outage may be substituted for the enhanced leakage inspection. VY followed this option for the SLC nozzle-to-safe end weld and the safe end extension in RFO 23 (2002).

BWRVIP-03, Revision 6, Standard 2.6, Section 3.3, states that personnel performing analysis of dissimilar-metal weld UT data for the SLC system shall be qualified per ASME Section XI, Appendix VIII, Supplement 10. Personnel have qualified under the detection requirements.

Technical Justification TJ-2004-05 (Reference 15.5.13) was prepared to allow continuation of surface examinations every other refueling outage because qualifications for sizing have not yet been determined.

Appendix B PP 7027 Rev. 3 Page 52 of 65

APPENDIX B (Continued)

BWRW-03, Standard 2.6, Section 3.3 states, "Personnel performing final analysis and review of examinations of dissimilar metal welds in the standby liquid control system shall have current qualification for crack detection, length sizing, andor depth sizing, as appropriate, in accordance with ASME Code,Section XI, Appendix Vm, Supplement 10. During late 2002 and 2003 personnel began qualifying for examination of dissimilar metal welds in accordance with Appendix Vm, Supplement 10. Qualifications of those personnel covered the range of thicknesses and diameters of the SLC nozzle welds. Therefore, UT of these welds became mandatory for RFO 24. The only exception to this requirement is that the welds must be ground flush in accordance with the PDI dissimilar weld UT procedure. The BWRVIP Assessment Committee has provided an interpretation that if the SLC welds are not ground flush, then the plant is not obligated to either grind the welds or perform a U T - and may continue doing either EVT-2 or a PT. However, the recollection is that Vermont Yankee SLC nozzle welds are ground flush (this will be verified during RFO 24 (2004) and therefore, UT is mandatory. During RFO 24 (2004) the nozzle to safe-end weld was visually observed and determined inconclusive if UT could be performed. The weld was not profiled, instead a PT of the weld was performed with no relevant indications detected, A work tracking LO-VTYLO-2004-00541 has been issued to profile the weld and ultrasonically examine it during RFO 25.

Per BWRVIP-27-A, Paragraphs 3.3.1 and 3.4.1, the desired frequency for ultrasonic examination is once every 10 years. For scheduling purposes, the ultrasonic examinations performed per BWRVIP guidance should coincide with the surface examinations required by ASME Section XI below.

The BWRVIP stated in response to NRC SE Issue 3.2.2 (Reference 1.5.13) that when utilities have access to the lower plenum due to maintenance activities not related to the inspection recommendations of the BWRVIP, they will have the opportunity to perform a visual inspection of a portion of the lower plenum and that results of this inspection will be reported to the B W R W . This will be treated as a commitment for those items listed in 15.4 below. F 15.2. ASME Section XI Amlicability Inspection of the SLC nozzle-to-safe-end weld is also governed by ASME Section XI, Table TWB-2500-1, Category 3-F,Item No. 35.20, "Reactor Vessel Nozzle-To-Safe End Butt Welds Less than NPS 4." A surface examination is required once per ten-year interval. This weld and the requirements for its inspection are also included in the Vermont Yankee Inservice Inspection Program, PP 7015. (Relief Request RI-01 does not include this scope.)

15.3. Other Commitments - None.

Appendix B PP 7027 Rev. 3 Page 53 of 65

APPENDIX B (Continued) 15.4. Inspection for Risk to Generation Purposes Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and agreed that the SLC and core plate AP lines are non-safety related. In addition, inspection of these lines by themselves would be very costly and time consuming, because they are located below the core plate and core disassembly would be required. However, in order to address the economic consequences of failure, the group agreed to perform inspection of these components, but only if they were made accessible through other vessel activities. These are recommended inspections and are considered nonmandatory.

15.5. References 15.5.1. BWRVIP-27, dated April 1997, "BWRStandby Liquid Control SystemKOre Plate Delta P Inspection Criteria and Flaw Evaluation Guidelines" 15.5.2. BWRVIP-53, dated July 1998, "Standby Liquid Control Line Repair Design Criteria" 15.5.3. Letter USNRC to BWRVIP, dated April 27,1999, "Safety Evaluation of the BWRVIP,'BWR Standby Liquid Control System / Core Plate Inspection and Flaw Evaluation Guidelines (BWRVIP-27),' EPRI Report TR-107236 (TAC No. M.98708)"

15.5.4. Letter Vermont Yankee to US+FC,dated May 27, 1999, BVY 99-73, "Reactor Vessel Internal Plans 1999 and 2001 Refueling Outages" 15.5.5. Memorandum M. P. Dugan to D. C. Girroir, dated June 29,1999, "SLC Weld zzle to Safe-end Examination" 15.5.6. to BWRVIP, dated December 20,1999, "Acceptance for Referencing of Report, 'BWRVIP,BWR Standby ntrol System / Core Plate Inspection and Flaw Evaluation Guidelines (BWR ),' for Compliance with the License Renewal Rule" 15.5.7. Memorandum C. B. Larsen to D. C.Girroir, dated June 29, 1999, "Status Of SLC Safe-End Examination Technique and Prognosis for Examination In RFO 23 (Rev. 1)"

15.5.8. Action Item / Regulatory Commitment 4-07, dated March 21,2002, "Standby liquid control nozzle-to-safe-end weld should be inspected in accordance with current industry guidance" 15.5.9. Action Item / Regulatory Commitment BWRVk-027-01, dated June 12,2002, d Inspection Recommendations for SLC Penetrations" 15.5.10. uly 2002, "Bm Standby Liquid Control SystemKOre a and Flaw Evaluation Guidelines" 15.5.11. Action Item / Regulatory Commitment BWRVIP-027-A-01, dated August 5,2002, "Evaluate BWRVIP-27-A 'BWR SLCICore Plate Delta P Inspection 8z Flaw Evaluations Guidelines" 15.5.12. BWRW-27-A, dated August 2003, "BWRSt Plate Delta P Inspection Criteria and Flaw E 15.5.13. Technical Justification TJ-2004-05, dated cation for Deferral for U T of SLC Safe-end

Appendix B PP 7027 Rev. 3 Page 54 of 65

APPENDIX B (Continued) 16.0 Steam Drver 16.1. BWRVIP Document Atmlicability No B W R W Inspection and Evaluation dc ument addresses the steam dryer, which is considered a non-safety related component with the exception that BWRVIP-48, pubIished in February 1998, governs inspection of the r::zctor vessel internal attachment welds. Vermont Yankee has complied with this document L . of its publication. The requirements for the steam dryer support and hold-down attachment Ids are found in the Miscellaneous Vessel hternal 11 Attachments section of this Program.

16.2. ASME Section XI Applicability Inspection of the steam dryer support ant Ad-down attachment welds is also governed by ASME Section XI, Table IWB-2500-1, C gory B-N-2, Item No. B13.30, "Interior Attachments Beyond Beltline Region." These require its are found in the Miscellaneous Vessel Internal Attachments section of this Program.

16.3. Other Commitments - GE SIL 644 @eft -Ice 16.5.7)was issued in August 2002 to address the I Quad Cities steam dryer cover plate faih following power uprate. VY inspected the dryer cover plate welds during W O 23 (2002) accordance with the SIL's recommendations because of the planned uprate following W O 24. 1 addition, GE recommended looking at the steam dryer sta. ~ .z -rvtation penetration rld this examination was also performed in RFO 23 I i pplement 1 (Ref m e 16.5.15)was issued in September 2003 to 3ties steam dryer ailure following power uprate - this time in the outer 3 vertical hood pl; 'd. Extended Power Uprate Task TO305 I ,L.IVLIA d - - w ~ ib. I , A , , ,ihich addresses floz induced vibration of the vessel internals, in Section 4.4.1 r>.i.or-r,lendedmodification of the st m dryer hood vertical plates and the outer cover

c" '

'3 inspections perfox :d in accordance with SIL 644, Supplement 1.

xed these modif. itions and inspections in RFO 24 (2004) in accordance 2ference 6.5.18).

The mo&,lmmw, and repairs consisted ( ; 1) cutting out the existing W' vertical and horizontal plates on each of the two Outer Hoods ar ' replacing them with 1" thick places; 2) removing the

.r diagonal braces inside the Outer Ho ?s; 3) replacing the W' thick horizontal cover plates tmt are adjacent to the steam outlet nozz' s; 4)installing three gussets on the lower section of each Outer Hood; 5 ) removing the old T -Bars and installing eight mitigation Tie-Bars with support gussets on the outer Tie-Bars; 6 ,epairing crack indications at weld location V-02-90 and V-02-270; 7) installing reinforceme, hardware in the areas behind the lifting lugs near the outer plenum vertical welds; and 8) add- g new tack welds to the f o leveling ~ screws. Vermont Yankee committed to performing a detai' :d inspection of the steam dryer during the next refueling outage RFO 25 (2005)and dur lg the two subsequent refueling outages RFO 26 (2007) and RFO 27 (2008) in accordance with c' E-SIL-644 Revision 1 as part of the EPU (Reference 16.5.19).

Appendix B PP 7027 Rev. 3 Page 55 of 65

APPENDIX B (Continued)

In parallel with the steam dryer modification activities GE began In Vessel Visual Inspection of the steam dryer in accordance with the recommendations of SIL 644 Supplement 1. The inspection included a VT-1 and VT-3 on the interior and exterior of the steam dryer according to GE Procedure GE-VT-203 Version 9. The results of these inspections are documented in Steam Dryer IWI Final Report VYR24-04-MJ525 (Reference 16.5.20). One crack indication was found in welds OP-V19-180 and VO2-270. These welds are located at the 215 azimuth behind lifting lug "C."

16.4. Inspection for Risk to Generation Purposes Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and agreed that the steam dryer (other than the support and hold-down attachment welds) is non-safety related. However, the group agreed that some inspection may be warranted for risk to generation reasons. The inspection may be performed off of critical path in the equipment pool.

Therefore, this nonmandatory inspection of the lifting lugs and associated hardware is intended to be performed every fourth refueling outage.

During RFO 20 (1998) several cracked tack welds on the steam dryer jacking bolts for the lifting eyes were discovered. These particular tack welds were reexamined in RFO 21 (1999). No changes from the previous examination were noted, so it was determined per Reference 16.5.6 that no further inspections of these tack welds are recommended until its next regularly scheduled inspection.

16.5. References 1 -

16.5.1. GE SIL No. 474, dated October 26, 1988, "Steam Dryer Drain Channel Cracking" 16.5.2. Memorandurn C. B. Cameron to R. E. McCulIough, dated December 8,1988, "Preliminary Review to SIL-474 16.5.3. Memorandum R. P. Lopriore to W. L. Wittmer, dated 19,1989, "Commitment Item S 16.5.4. GE SIL No. 558, dated April 22, 1993, "SteamDryer Damage Prevention" 16.5.5. Memorandum D. J. RollinsM. Selling to M. P. Dugan, Revision 1, dated April 17, 1998, "Inservice Discrepancy Report 98-004,98-005,98-006 - Inservice Inspection of Tack Welds on Steam Dryer Lifting Lug Assemblies" 16.5.6. Memorandum D. J. RollinsM. Selling to S. D. Goodwin, dated November 23, 1999, "Inservice Discrepancy Report 99-019 - Inservice Inspection of Steam Dryer" 16.5.7. GE SIL 644,dated August 21,2002, " B W 3 Steam Dryer Failure" 16.5.8. Action Item / Regulatory Commitment SLO644-01 , dated August 26,2002, "Evaluate GE SIL 644: BWW3 Steam Dryer Failure" 16.5.9. NRC Information Notice 2002-26, dated September 11,2002, "Failure of Steam Dryer Cover Plate after a Recent Power Uprate" 16.5.10. Action Item / Regulatory Commitment INF-2002-026-0 1, dated September 16,2002, "Failure of Steam Dryer Cover Plate after a Recent Power Uprate" 16.5.11. OE16492 - PEZIMINARY REPORT, dated June 30,2003, "Reactor Vessel Steam Dryer Structural Steel Bracing Degraded" Appendix B PP 7027 Rev. 3 Page 56 of 65

APPENDIX B (Continued) 16.5.12. Action Item / Regulatory Commitment OE-16492-01, initiated July 8,2003, "Reactor Vessel Steam Dryer Structural S tee1 Bracing Degraded" 16.5.13. NRC Information Notice 2002-26, Supplement 1, dated July 21,2003, "Additional Failure of Steam Dryer After a Recent Power Uprate" 16.5.14. Action Item / Regulatory Commitment INF-2002-026 SI-01, dated August 6,2003, "Additional Failure of Steam Dryer After a Recent Power Uprate" 16.5.15. GE SIL-644, Supplement 1, dated September 5,2003, "BWR Steam Dryer Integrity" 16.5.16. Action Item / Regulatory Commitment S&06&lS 1-01, initiated September 8,2003, "BWR Steam Dryer Integnty" 16.5.17. Extended Power Uprate Task T0305,GE-NE-0000-0016-4161-01, dated December 2003, "RPV Flow Induced Vibration" 16.5.18. VYDC 2003-12, dated January 2004, "Steam Dryer Strengthening" 16.5.19. Attachment 4,Vermont Yankee Nuclear Power Station Proposed Technical Specification Change No. 263 - Supplement No. 13 "Extended Power Uprate Response to Steam Dryer Action Items Commitments," BVY 04-097.

16.5.20. Vermont Yankee Nuclear Power Station Steam Dryer Modifications and Repairs, VY-RFO 24 Refueling Outage, April 2004, Report Number VYR24-04-MJ525.

16.5.21. GE-SIL-644 Revision 1, dated 11/04 "BWR Steam Dryer Failure" 17.0 Steam Seaarator/ShroudHead gncluding Hold-down Bolts) 17.1.J B No B W R W Inspection and Evaluation document addresses the steam separator, shroud head, or shroud head hold-down bolts. These are considered non-safety-related components.

17.2. ASME Section M ADplicability There are no ASME Section XI inspection requirements that apply to the steam separator, shroud head, or shroud head hold-down bolts.

17.3. Other Commitments - None.

17.4. Inspection for Risk to Generation Pumoses Representatives from Reactor Engineering and Plant Engineering met on January 13, 1999, and agreed that the steam separator/shroud head is non-safety related. However, the group also agreed that some inspection may be warranted for risk to generation reasons. This inspection may be performed off of critical path in the equipment pool. Therefore, this nonmandatory inspection of the lifting lugs and associated hardware is intended to be performed every fourth refueling outage.

Appendix B PP 7027 Rev. 3 Page 57 of 65

APPENDIX B (Continued)

The shroud head hold-down bolts are considered non-safety related. These bolts were replaced as part of the shroud tie-rod repair in RFO 19 (1996). The replacement bolts were of a new design. There have been no materials problems associated with the new design of shroud head hold-down bolts and no inspections are recommended at this point.

17-5. References 17.5.1. GE Report MDE #293-1285, Revision 1, DRF #B11-00337, dated January, 1986, "Shroud, Shroud Head Sealing Surfaces, Alignment Pins and Guide Rod Evaluation" 17.5.2. GE SIL No. 433, dated February 7, 1986, "Shroud Head Bolt Cracks" 17.5.3. Memorandum R. P. hpriore to R. E. McCullough, dated March 22,1986, Response to MD Commitment Item SIL 433" 17.5.4. GE SIL No. 433, Supplement 1, dated September 15, 1993, "Shroud Head Bolt Failures" 17.5.5. Memorandum S. K Naeck to T. A. Watson, dated October 5, 1993, "GESIL No. 433 Supplement 1 Shroud Head Bolt Failures" 17.5.6. Event Report ER#95-0267, dated April 1 17.5.7. Letter D. B. Drendel (GE) to B. R. B dA ad Bolt Recommended Options" 17.5.10. Memoran Ely to R. E. McCullo 5,1995, "AP0028 cornmi 17.5.11. Letter D. B. Drendel (GE) to B. R. Bu dated April 18,1995, "Operation with Less Than the Full Complement of Shroud Head Bolts" 17.5.12. Memorandum T. A. Watson to R. E. McCullough, April 25, 1995, "Re: Shroud Head Bolt Failures, Perform Ultrasonic Testing of Shroud Head Bolts During 1995 Refueling Outage" 17.5.13. Memorandum T. R. Osterhoudt to PORC,dated April 26, "Operation with Degraded Shroud Head Bolts" 17.5.14. Memorandum 3. T. Meyer to D. A. Reid, dated August 16, 1995, "Review of LERs, ERs" 17.5.15. Memorandum T. A. Watson to R. E. McCullough, dated September 25,1995,'

"Shroud Head Bolts, UND95019-01" 17.5.16. Memorandum T. A. Watson to R. E. McCullough, dated May 10, 1996, "Shroud Head Bolts Unlatching, ER950267-02" 17.5.17. ER 20022538, dated October 10,2002, "Two shroud head bolts had spring loaded keeper retainer nuts that would not spring up into place around the tensioning nut" Appendix B PP 7027 Rev. 3 Page 58 of 65

APPENDIX B (Continued) 18.0 Top Guide 18.1. BWRVIl? Document Applicability BWRVIP-26, published in December 1996, governs inspection of the top guide. Vermont Yankee was not able to immediately comply with the inspection method as specified in BWRVIP-26 as of its publication. However, Vermont Yankee began examination in accordance with this document (with the exception of access, as described below) as of RFO 21 (1999) -

within two cycles of the publication of BWRVIP-26 in accordance with guidelines later published in BWRVIP-94.

BWRVIP-26, Table 3-2, requires inspection of three components for BWFU4 plants without installed wedges: aligner pin assemblies, hold-down assemblies, and the top guide rim weld. The top guide rim weld does not exist at Vermont Yankee and is therefore exempt.

According to BWRVIP-26, Table 3-2, welds in two adjacent aligner pin assemblies are to be inspected every other refueling outage with the VT-1 method, unless a plant-specific analysis is I,.:

1' performed to show that less than 20%of the weld is required. Prior to RFO 23 (2002), this analysis was performed and documented in VYC-2218 (Reference 18.5.39). Therefore, no inspection of the top guide aligner pin assemblies is required. Prior to RFO 23 (2002), a best i.

effort VT-1 of the aligners was performed every other refueling outage. Such an examination was performed during RFO 19 (1996) on the aligner assemblies at 162 and 252 degrees, and again during RFO 21 (1999) on the aligner assemblies at 72 and 162 degrees. (I inspection of i the top guide aligner assemblies ever becomes necessary again, there is sufficient weld length accessible for a VT-1 inspection in the aligner socket that is welded to the shroud ledge. On the I other hand, the welds in the aligner socket that is welded into the top guide are not easily accessible for inspection; however, it could be argued that the two abutting aligner "Lego" blocks perform the same function as the aligner socket that is welded into the top guide. The aligner "Lego" blocks were verified to be in position with the VT-3 inspection method. Also, see Reference 18.5.32.) iI According to BWRVIP-26, Table 3-2, a VT-1 inspection of two hold-down assemblies 180 degrees apart, where the hold-down latches to the shroud, are to be inspected every other refueling outage. Such an examination was performed in RFO 21 (1999) on the hold-down i

assemblies at 18" and 198" and in RFO 23 (2002) on the hold-down assemblies at 108"and 288".

I Appendix B PP 7027 Rev. 3 Page 59 of 65

APPENDIX B (Continued)

Vermont Yankee is not now planning to install top guide wedges. (There are no inspection requirements identified in Table 3-2 of BWRVIP-25 for B W 4 plants with installed wedges.) If Vermont Yankee ever does install wedges they may require some periodic inspection.

BWRVIP-50, Paragraph 10.2, states, "Inspections required for the entire repaired top guidekore plate structures for the remaining life of the unit, shall be specified commensurate with design considerations and code requirements applicable to the specific design. This shall include inspections of the repair hardware and inspection of the reactor internal components utilized for repair anchorage." These inspection requirements would be delivered as a piece of the wedge design scope. Barring any guidance, the new wedges would d l be reinspected after one cycle of operation. Thereafter, two wedges would be alternately inspected every third outage. This would ensure that all four top guide in ve years.

i Internal commitments in Refere and 18.5.19 below to address GE SIL No. 588 will no longer be applicable with the inspection strategy adopted herein. These commitments are considered revised accordingly, with the issuance of this document.

I,..J Cracking in grid beams has been discovered at Oyster Creek. BWRVIP-26, Paragraph 3.2.2, states that, for now, no inspection is required for the grid beams, but that this recommendation will be reevaluated after the Oyster Creek inspection and sample results have been evaluated by report (Reference 18.5.37) that characterizes these cracked that the cause of the cracking in the top guide beam was IASCC, but lude otherwise given the reported data.

Consequently, the BWRVIP will have to revisit B 6 for top guide beam cracking ind inspection recommendations. The subject E E E

iE iE iE iE iE iE iE iE iE iE iE iE iE iE iE iE iE iiireport does not contain any recommendations or guidance, so no action is necessary at this time. (Seecommitment to GE SXL No. 554 below for further discussion of top guide grid beam inspection.)

U 18.2. ASME Section XI Amlicability The top guide is part of the core support structure; however, the top guide is not integrally welded as stated in the title of ASME Section XI, Table IWB-2500-1, Category B-N-2.

Therefore the top guide is not subject to ASME Section XI. See Reference 18.5.28 below.

Appendix B PP 7027 Rev. 3 Page 60 of 65

APPENDIX B (Continued) 18.3. Other Commitments In References 18.5.6 and 18.5.22below, Vermont Yankee committed to perform examinations as recommended by GE SIL No. 554. This GE SIL recommends inspection of top guide grid beams, as they become accessible during the normal course of refueling outages. In Reference 18.5.25below, Vermont Yankee stated that following RFO 21 (1999), inspection of the top guide grid beams will revert to that recommended by the BWRVIP. However, Reference 18.5.30 stated that top guide grid beams in four cells will be inspected until further notice. A change to that commitment was forwarded to the NRC in Reference 18.5.34. BWRVIP guidance governed inspection of the top guide grid beams until January 2004. As part of the power uprate approval process, VY committed in BVY 04-008 (Reference 18.5.40) to perform inspections of the top guide grid beams in accordance with S E 554 requirements. VY committed to perform inspection of top guide components in the refueling outage following power uprate. Enhanced visual testing (EVT-1) of top guide grid beams will be performed in accordance with STL 554 following sample selection and inspection frequency of BWRVIP-47for the CRD guide tubes.

In other words, VY will perform inspection of 10%of the total population of cells within twelve years, vi" -half (5%) to be completed within six years. The six-year intervals at Vermont Yaii;-;d %iiL Sefined to be the same as those for the CRD guide tubes. The first top guide grid beam 6 :rvd aligns with the CRD second six-year interval and is defined as -0 24

'?or (2005),RFO 26 (2007), and RFO 27 (2008). The second top guide grid beam .

I will coincide with the CRD third 6-year interval which begins with RFO 28 (20101 and includ- ?;FO29 (2011). The sample is chosen from the cell locations where control blades will be , Selection of the cells will also be biased to the highest fluence areas 2

in the ton Fir' w c r , Vermont Yankee reserves the right to modify the above inspection WRVIP-26 be revised in the future.

.- ~ - .,

r < . -d ~ I-

~

i L*

rir 3ubcomponents that are to be inspected solely for risk to generation cI one quadrant of the top guide rim bolts and the cover sheet bolts is 11- 'very fourth refueling outage on a rotating basis. These components are nu. :se nonmandatory inspections would only be performed for loose Darts contd:lri, 18.5. -

18.5.1. JL . 'SILNo.059, Revision 0,dated May 31, 1991, "Top Guide Crackhdication" 18.5.2. Letter C. B. Cameron to A. D. H i d e , dated July 22, 1991, regarding SIL 462, RICSILO54, RICSTLO59 and GE support for possible inspection findings 18.5.3. Memorandum C. B. Cameron to R. E. McCullough, dated August 5, 1991 18.5.4. GE SIL No.554, dated April 6,1993, "Top Guide Cracking" 18.5.5. Memorandum R. A. WoehlkeK. B. Spinney to T. G. Stetson, dated May 24, 1993, "Application of SIL No. 554 to VY' 18.5.6. MemorandumT. G. Stetson to R. E. McCullough, dated June 14,1993, "Top Guide Craclung" Appendix B PP 7027 Rev. 3 Page 61 of 65

APPENDIX B (Continued) 18.5.7. Memorandum T. G. Stetson to C. B. Cameron, dated July 19, 1993, "Delaying 18.5.8. Service Request T. G. Stetson to D. C. Porter, dated February 15, 1994, "Service Request to Determine Radial Flux Profile On Vermont Yankee Top Guide" (Later Canceled) 18.5.9. Letter R. C. Hooper (GE) to F. J. Helin, dated May 4, 1994, "Follow-up Questions Asked During Our April 11,1994, Meeting" 18.5.10. Memorandum F. J. Helin to D. C. Porter, dated May 10, 1994, "Cancel Service I

t Request (94-18); Radial Flux Profile On Top Guide Evaluation" 18.5.11. GE RICSIL No. 071, Revision 0, dated November 22, 1994, "Top Guide and Core

! Plate Cracking"

! 18.5.12. Letter from BWRW to USN'RC,dated January 3,1995, "Request for Information Regarding the Impact of BWR Core Plate and Top Guide Ring Cracking" 17,1995, "Top Guide and Core Plate Cracking" I ._.

18.5.13.

18.5.14. dated March 10,1995, "Reactor Vessel Top Guide I.,1 18.5.15.

Cracking" 1, dated May 18; 1995, "Top Guide and Core Plate 18.5.16. ugh, dated February 5,1996, "Response Core Plate Cracking" 18.5.17. . McCullough, dated February 5, 1996, "Response re Plate Cracking" 18.5.18. Memorandum T. G. Stetson to R. E. McCullough, dated February 5,1996, "Response to Commitment INF95017 on Top Guide and Core Plate Cracking

I. 18.5.19. Memorandum T. G. Stetson to R. E. McCullough, dated July 11, 1996, "Response to Commitment SM)588-01" 18.5.20. Memorandum T. G. Stetson to F. J. Helin, dated September 18, 1996, "Recommendations for Remaining Top Guide Beam Inspections" 18.5.21. BWRW-26, dated December 1996, "BWR Top Guide Inspection and Flaw i,. &/ .i Evaluation Guidelines" 18.5.22. Letter Vermont Yankee to NRC dated September 30,1997, "Vermont Yankee's Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals" "3

18.5.23. Letter NRC to Vermont Yankee dated March 25,1998, "Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals - Vermont Yankee Nuclear Power Station" 18.5.24. BWRVIP-50,dated May 1998, "Top GuideKOre Plate Repair Design Criteria" 18.5.25. Memorandum T. G. Stetson to F. J. Helin, dated September 18, 1998, "Recommendation for Remaining Top Guide Beam Inspections" 1 8.5.26. Memorandum T. G. Stetson to R. E. McCullough, dated December 23, 1998, "Response to Commitment UND96055" 18.5.27. Memorandum E. J. Taintor to D. C. Girroir, dated April 23, 1999, "Accessibility Following Installation of Proposed Top Guide and Core Support Assemblies" 18.5.28. Memorandum C. B. Larsen to D. C. Girroir, dated May 13, 1999, "Definition of Core Support Structures (ASME Section XI, Category B-N-2)"

18.5.29. Memorandum C. B. Larsen to D. C. Girroir, dated May 13,1999, "1999Top Guide Grid Inspection Plans" Appendix B PP 7027 Rev. 3 Page 62 of 65

APPENDIX B (Continued) 18.5.30. Letter Vermont Yankee to USNRC, dated May 27, 1999, BVY 99-73, "Reactor Vessel Internal Plans for the 1999 and 2001 Refueling Outages" 18.5.31. Letter USNRC to BWRVIP, dated September 29, 1999, "Final Safety Evaluation of

'BWR Top Guide Inspection and Flaw Evaluation Guidelines (BWRVTP-26)'"

18.5.32. Letter Vermont Yankee to USNRC, dated October 29,1999, BVY 99-137, "Deferral of Top Guide and Core Plate Wedge hstallation" 18.5.33. Memorandum D. C. Girroir to P. B. Corbett, dated May 9,2000, "Cost of Top Guide Inspections" 18.5.34. Letter Vermont Yankee to USNRC, dated June 6,2000, BVY 00-56, "Change in Inspection Plans for the Top Guide Grid Beams" 18.5.35. Letter Vermont Yankee to USNRC, dated September 26,2000, BVY 00-89, "Cancellationof Top Guide and Core Plate Wedge Installation" 18.5.36. Letter NRC to BWRVIP, dated December 7,2000, "Acceptance for Referencing of BWRVIP, BWR Top Guide Inspection and Evaluation Guidelines (BWRVIP-26) I Report for Compliance with the License Renewal Rule (10 CFR Part 54)" 1 .1 18.5.37. EPRI Report 1003422, dated May 2002, "Analytical Transmission Electron Microscopy (ATEM) Characterization of Stress Corrosion Cracks in LWR-Irradiated f Austenitic Stainless Steel Core Components" I-2 18.5.38. Action Item / Regulatory Commitment BWRVTP-26-A-01, dated August 5, 2002, I "Evaluate BWRVIP-26-A: BWR Top Guide Inspection and Flaw Evaluation  !

Guidelines" 18.5.39. VY Calculation VYC-2218, Revision 0, dated November 25,2002, "Structural Evaluation of RPV Top Guide Aligner" I 18.5.40. BVY 04-008 Attachment 1-CPPU Submitted RAT Response, dated January 31,2004.

I 19.0 Vessel Cladding 19.1. BWRVIP Document Amlicability &.

BWRVIP documents do not contain any specific inspection requirements for vessel cladding. \

I 19.2. ASME Section XI Applicability The cladding is outside the scope of ASME Section XI. The examination volumes shown in t '

Figures NVB-2500-1 specifically exclude the cladding. I Appendix B PP 7027 Rev. 3 Page 63 of 65

APPENDIX B (Continued) 19.3. Other Commitments In RFO 16 (1992), cracking in cladding in the vessel head and shell interior was discovered at Vermont Yankee. The inspection was initiated in response to GE RICSIL No. 050 and GE SLT, No. 539. A large sample of these clad cracks was ultrasonically sized. It was determined through this ultrasonic manual sizing, in conjunction with a statistical analysis, that none of the cracks propagated into the vessel base-material pressure boundary. Even so, Vermont Yankee committed to the NRC in References 19.5.6and 19.5.14below to perform successive examinations similar to A S m Section XI, IWB-2420(b), of a sample of clad cracks. In this way, the clad cracking would be treated as if these were indeed defects that exceeded the ASME Section XI acceptance criteria, even though they do not. Paragraph TWB-2420(b) requires that areas containing flaw indications that have been accepted analytically be reexamined during the next three inspection periods.

If RFO 16 (1992) fell in the third period of the second interval. The vessel cladding was visually and ultrasonically reexamined in RFO 17 (1993), which fell in the first period of the third t"1 interval. Reference 19.5.14 below contains a commitment to the NRC to perform a similar clad inspection to the RFO 17 (1993) reexamination once each period for the next two periods. In I 2 RFO 19 (1996), the reactor vessel shell welds were examined using an automated ultrasonic t technique (Reference 19.5.20). This constituted a very large sample of the vessel interior surface and was used to also serve as the second successive reexamination (second period, third interval) of the cladding flaws. During RFO 23 (2002), the thrd successive re-examination was completed (third period of the third interval). Reference 19.5.21 documented closure of the Reference 19.5.14commitment; summarized the four inspections of the vessel clad cracking; and concluded that there was no evidence that clad cracks have penetrated into the base material.

Clad cracking will continue to be monitored through the following mechanism. Approximately every ten years, the vessel shell welds will be examined in accordance with ASME Section XI and BWRVIP-05. This is next scheduled to occur in RFO 24 (2004). Most of the vessel dad cracking was found to be located in areas of manually applied cladding. The manually applied cladding coincides with the vessel weld locations because of the original vessel fabrication sequence. Therefore, a large sample of clad cracked areas will be examined every ten years.

This will give a very good indication of whether the clad cracks are likely to become a problem.

19.4. Inspections for Risk to Generation Purposes - None 19.5. References 19.5.1. GE RICSE No. 050, dated April 23,1990, "Reactor Vessel Head Clad Cracking" 19.5.2. Memorandum C. 3. Cameron to R. E. McCullough, dated April 24, 1990, "Preliminary Review to RICSIL-050" 19.5.3. NRC Information Notice No. 90-29, dated April 30,1990, "Cracking of Cladding and Its Heat-Affected Zone In the Base Metal of a Reactor Vessel Head" 19.5.4. Memorandum J, R. Hoffman to D. C. Girroir, dated June 8, 1990, "Input for AP0028 Close-out of NRC I. N. 90-29 and 90-32" 19.5.5. GE SIL No. 539, dated November 5, 1991, "RPV Head Clad Cracking" Appendix B PP 7027 Rev. 3 Page 64 of 65

APPENDIX B (Continued) 19.5.6. Letter Vermont Yankee to USNRC, BVY 92-055, dated April 5 , 1992, "Proposed Alternative for Compliance with 10CFR50.55a Regarding RPV Cladding Indications" 19.5.7. Letter Vermont Yankee to USNRC, BVY 92-056, dated April 10,1992, "Supplemental Information Regarding Proposed Alternative for Compliance with 10CFR50.55aRegarding RPV Cladding Indications" 19.5.8. Memorandum F. J. Helin to PORC, dated April 17,1992, "Clad Indications Found During 1992 Refueling Outage" 19.5.9. Letter USNRC to Vermont Yankee, dated April 17,1992, "Meeting Summary of April 8,1992 Meeting To Discuss Vermont Yankee Reactor Vessel Flaws" 19.5.10. Letter USNRC to Vermont Yankee, dated April 17, 1992, "Disposition of Reactor Vessel Cladding Indications Discovered During the March 1992 Refueling Outage At Vermont Yankee Nuclear Power Station" 19.5.11. EPRI TR-101971, dated February 1993, "Evaluation of Reactor Pressure Vessel Head Cracking in Two Domestic BWRs" 19.5.12. Letter Vermont Yankee to USNRC, dated July 1, 1993, "1993 RefueIing Outage Vessel Clad Inspection Plans" 19.5.13. Memorandum C. B. Larsen to J. R. Hoffman, dated September 9, 1993, "RPV Clad Crack Investigation" 19.5.14. Letter Vermont Yankee to USNRC, BVY 93-112, dated October 6 , 1993, "Reactor Vessel Clad Inspection during the 1993 Refueling Outage CAR92016MEC3" 19.5.15. Memorandum T. G. Stetson to R. E. McCullough, dated October 12, 1993, "Response to Commitment CAR9201BREI" 19.5.16. D. C. Girroir to G. Cappuccio, dated May 26, 1994, "CAT A Item: Dryer Support Bracket Inspections" 19.5.17. Memorandum G. A. Wallin to R. E. McCullough, dated April 18, 1995, "Response to Commitment CAR92016RE2" 19.5.18. Memorandum T. G. Stetson to R. E. McCullough, dated July 20, 1995, "Canceling Commitments CAR92016RE3 and CAR92016RE4" 19.5.19. Letter VYNPC to USNRC, BVY 96-105, dated September 10, 1996, "Augmented Examination of the Vermont Yankee Reactor Pressure Vessel Shell Welds" 19.5.20. SwRI Final Report, dated December 1996, Reactor Vessel Shell Weld Inspection Report 19.5.21. Memorandum C. B. Larsen to D. C. Girroir, dated October 21,2002, "Evaluation of Clad Crack Indications under the Reactor Head and in the Vessel" Appendix B PP 7027 Rev. 3 Page 65 of 65

i *:

d u e - L u L  ; L APPENDIX C Technical Justifications Table 1 - TechnicalJustification Index No. ID Approved Title BWRVIP Reference 1 TE-2003-0021 04/09/03 Justification to Revert to EVT-1 Inspection of Jet Pump BWRVTP-41, Section 3.2.4, Circumferential Welds with UT Indications Table 3.3-1 2 TE-2003-0023 07/07/03 Technical Assessment For Delaying Hydrogen Injection Into BWRVTP-79, Table 4-5a The Reactor Core 3 TJ 2003-03 08/18/03 Justification to Perform Less Than 5%of CRD Guide Tube BWRW-47-A, Table 3.2-1 Weld Exams within the First Six-Year Interval 4 TJ 2003-04 08/18/03 Continued Operation without a Feedwater Zinc Injection BWRW-79, Section 3.2.3.3, 5 1 TJ 2003-05 1 12/17/03 1 f;-lw..r System ~~~~ -

Copper ConcentrationsAbove Recommended I

BWRVP-107, Section 5.1 BWRVIP-79, Table 4-6, Note c 6 I TJ-2004-01 I 03/26/04 I Justification for Alternative Inspection of Core Plate Rim Hold-down Bolts BWRVP-25, Section 3.2.2.2, Table 3-2 7

8 I TJ-2004-02 I 03/26/04 TE-2084-0018 In review I Justification for Deferral of Inspection of Inaccessible Welds Justification to Inspect Portions of Shroud Horizontal Welds 1 BWRVIP-18, Section 3.2.4, BWRVIP-41, Table 3.3-1 BWkVIP-76, Section 3.2, H1, H2,and H3 On the OD In Lieu of the Top Guide Spacer Section 2.2.1, Section 2.2.2, Block Welds, the Shroud Flange Ring Segment Welds, and Figure 2-3 the Top Guide Ring Segment Welds 9 TJ-2004-04 03/26/04 Justification to Defer Inspection for Detection of Transverse BWRVIP-104, Section 9.2 Flaws In Shroud S U D DWeld O ~ ~H9 10 I TJ-2004-05 I 03/26/04 Justification for Deferral for UT of SLC Safe-end BWRVIP-27-A, Sections 3.3.1 and 3.4.1 Appendix C PP 7027 Rev. 3 Page 1 of 61

Appendix C (Continued) 1

' OYh3b3 Tecbnfcal Evaluation No. ZOO34021 Vermont Yankee elected to perform inspection of the RS-1 welds (among others) using UT in RFO 20 (1998). The alttasonic inspection identified indications on four RS-I welds: weld numbers N2B-RS-I, N2C-RS-1, N2H-RS-I, and N2K-RS-1 (Rd'nce 3A). BVY-98-67 (Refcrenca 4A) was prepand and'submittcd to the NRC FolIowiag an RAI 98-77.

an SER fmm

• Refcfence AB) and subsopomt reply, @VY 9 8 - ~ ~ , - - R ~ ~ ~ ; V e r m h ~ ~ a n k c e r r c c e i v e d NRC @VI?9&153,- I?&+acc4D>4E))-.#, allow d e $ d eirq%&cm f a these .

foux welds until- 22 (2001), Ltttn BVY 9943 to the NRC (Rofmnce 4B)sought to extend tbe iaspection interval fiom one to two cydes. VY received an SERfor &'in letter NVY 99-46 I.

CRtfennOe4p). During RFO 22 these four riser welds W u e leiaspectad mfixezlce 333) with the result that two of the previous indications (in welds N2B-RS-I and N2C--1) were found to be liioff of the transducers,and the.r&orc nonrclwant. The indications in the nmainrngtwo welds W2H-RS-L and N2K--1) were tho same as found in RFO 20 (1998) withia the documented NDE accuracy (Refetence 41 and BpvRvIp-03. Sections 10.4.3 and 10.6-1,Reference 2B). An Appendix C PP 7027 Rev. 3 Page 2 of 61

Appendix C (Continued)

TeclmiqalEvaluationNo. u10390n

. . . . ........ . . . . . . . . .. v . . . . . . . . . ._: ... w--,

AP60650dghral Page2of10 Appendix C PP 7027 Rev. 3 Page 3 of 61

Appendix C (Continued)

. Evaluation No. 20034021 Ted~nical Appendix C PP 7027 Rev. 3 Page 4 of 61

Appendix C (Continued)

. . . .. .. .. . .. ..". -- ... vxAP?ML85-(yL. ..-..

AP6cM!joriginat PagePoflO Appendix C PP 7027 Rev. 3 Page 5 of 61

~-

~ ~-

Appendix C (Continued)

Tecbaid Evahailon No. 2003-0021

. -.. . . - . ... . .-. . - wA.PF6obs-M.

AP6065Orfginaz Page5 of 10 Appendix C PP 7027 Rev. 3 Page 6 of 61

Appendix C (Continued)

Technical Evalaatlon N+ 2oo3-o(n1 i

I t ,:1

. . . - .WA.Ep6045.02 a...

AP6095CMgid Page 6 d 10 Appendix C PP 7027Rev. 3 Page 7 of 61

Appendix C (Continued)

Techm;llcal Evaluation No. 2U034021

.-.. ... i

........ .._..e ... '-

bate)

I I.

t .

. . . . . , . . .. .. . .. . . . . . .. . . . 1 t.

. ?

i .

... ,: I . '. :

. . . . . . . .-... .. .._ . w A p p 6(385 .

M .

--original Page 7 of 10 Appendix C PP 7027 Rev. 3 Page 8 of 61

Appendix C (Continued) i TechnicalEvaluatioxa No. 20030021 i

TBN022oo%mf . _ .~ . - .. ..... . . . . . . . . .. . .

. . .~ . . . . .. . .

f i . . . ... . . .. . . . . .  : . .

f t

t I

r 1 9

I air

-1 Appendix C PP 7027 Rev. 3 Page 9 of 61

Appendix C (Continued) 4J ITecbdcal Bvatuation No.2Qo1-030,dated May 14. Ulol. '33vahWion of Jet PumpRiser Raws" 5 RFOs 21 and23 NDE Reports for Set Pump Dffhser Weld @F-2 and DF-3) Indicatlw 5A FramatonasTffihndogiesReport for Job 1220685,Revision 0, dated December 9,1999.

. . - -. v y A p p ~ @ 2 .. ,

AP60450Eiginal Page 9 of 10 Appendix C PP 7027 Rev. 3 Page 10 of 61

Appendix C (Continued)

Technical Evaluation No. 2003-00W L None I

...... - - . . . . . . . . . . *W~6045M..

-6045-Page 10of 10 Appendix C PP 7027 Rev. 3 Page 11 of 61

~. ~ Ap-- I Appenchx C (Continued) 4 Technical EvaIuation No. 2oo3-023 I

1..

W A P F 6045.02 AP6045Original Page 1 of 5 Appendix C PP 7027 Rev. 3 Page 12 of 61

Appendix C (Continued)

Technical Evduation No. 2003-023 WAPF 6045.02 AP6085Original Page 2 of 5 Appendix C PP 7027 Rev. 3 Page 13 of 61

Appendix C (Continued)

TeddcaI Evaluation No. 2003423 I.

2 3.

I VYAPF 60QS.M AP 6045Orighal Page 3 of 5 Appendix C PP 7027 Rev. 3 Page 14 of 61

Appendix C (Continued) i I .

Appendix C PP 7027 Rev. 3 Page 15 of 61

Appendix C (Continued)

Technical EvaIuatim No. 2003423 t

Appendix C PP 7027 Rev. 3 Page 16 of 61

Appendix C (Continued)

Tekhnical Evaluation No. 2003623 I

t 6 ,

Appendix C PP 7027 Rev. 3 Page 17 of 61

Appendix C (Continued) 0 Technical Evaluation No. 2003-023

..I 4c 4D 5

6 Browns Fary TVA 7

8 9

10 I1 12 13 l4A 14B 1s

__1 16 17 18 19 20 21 22 2 3 .

24 Appendix C PP 7027 Rev. 3 Page 18 of 61

I .

I . ..

, m m ..

b . ..

+.

Appendix C (Continued)

Title:

Justification to Perform Less Than 5% of CRD Guide Tube Welds Within the First Six-Year Interval Technical justification is required when utility procedures, inspections, methodology, or guidelines are inconsistent with the intent of the supportingBWRW guidelines.

BUTRVIP Rwuirement (Give BWRVIP document and Section reference with a restatement of rhe requifement)

BWRV3P-47-A, Table 3.2-1,requires 10%of the CRD guide tube population (specifically welds CRGT-2 and CRGT-3)to be inspected within a twelve year period and 5% within the fmt six years. The fmt six years is defined in the Reactor Intemals Inspection Bases Docusnenr as the first six years following issuance of BWRVIP-47, which was published in December 1997.7'hat first six ye= included RFO 20 (1998),RFO 21 (1999), RFO 22 (2001), and RFO 23 (2.002). There are 89 CRD guide tube assemblies at Vermont Yankee. A sample of 10% would be nine guide tubes and a sample of 5% would be five guide tubes (rounded up to the next integer). CRGT-2is the guide tube body-to-sleeve weld and CRGT-3 is the guide tube base-to-body weld. 1 Vermont Yankee Deviation {Record how Vermont Yankpe deviarcs or &viutedj?otn the B WRVIP requirement.)

Only four CRD guide tu& assemblies were inspected during the first Six-year period. The inspections were not begun until RFO 22 (2001)when four guide tube assemblies were inspected. No guide tubes were accessible during RFO 23 (2002)because no control bIades were changed during that outage.

BWRW-47-A also requires a VT-3 inspection of two other locations in the guide tube assembly. These are CRGT-I,the guide tube sleeve-to-alignment Iug weld and FSlGT--IN-1, the guide tube and fuel I

'support alignment pin-to-core plate weld and the pin itself. The minimum sample of these locations was completed during the fust six-year period [get history ftom Tom Stetson]. The VT-3 inspections were I completed during the course of the orificed fuel support reinstallatiodrealignmentprocedure, OP I I 11.

J d c a t i o n {Ptvvkfe the basis for determhhs that the projwsed deviation meets the same objective and inrent, or level of conservarism uhibited by rhi B W W P gufdelines The jut$catwn shall be supported by crrlculationr when W Q ~ L Z I Clearly identijgl aN rrvailable information and resources. whkh allow the deviiation to be acceptable. Clearly idenrify the impact that the deviation will h e on meeting the htent of the guideline.)

Z ~ ~

P L

The 5% sample inspection of CRD guide tubes would normally be completed during the course of t control blade change-outs over a six-year period. Blade change-out requires orificed fuel support reinstallation and realignment, thus allowing access to the interior of the CRD guide tube. Typically, there are between three and ten blade change-outs each outage, so it is reasonable to expect that would be at least nine blqde change-outs during any webe-yes- period.and at -least five blade change-

.sere z outs during any six-year pen&. However, for the two outages within the first six-year period after inspections were commenced, only four guide tubes became available. 1 The only reason why exams of these components were not performed during either W O 20 (1998) when -

four blades were changed out or during RFO 21 (1999) when nine blades were changed out - was that t I

it was fully expected that there would be at least five blades changed out during the following two outages.

It should be noted that Vermont Yankee was one of the first plants to perform examination of these welds.

-d VYPPF 7027.O 1 PP 7027 Rev. 2 Page 1 of 4 Appendix C PP 7027 Rev. 3 Page 20 of 61

! Appendix C (Continued)

BWRVlP47-A, Section 32.5 states, 'The BWRVIP has determined that removing or dismantling of internal components for the purpose of performing inspections is not warranted to assure safe operation:

The requirements of BWRVIP47 were originally designed to allow inspections to be performed during the n a d course of plant maintenance. In that way, the mGT-2 and CRGT-3welds could be inspected when control blades are changed out.

i Inspecting one additionat guide tube during RFO 23 (2002)to aitain the 5% threshold would have required

.vacating,an additional fuel cell (more fhel moves) and an added three hours for disassembly and

, reassembly (not counfing the inspection time). This hardship is not j u s a e d in terms of safety in ordkr to 1

raise the inspection sample from 4.5% to 5%.

Inspections of the eight welds in the four guide tubes inspected during RFO 22 (2001) did not reveal any flaws. .. . . .. . .. .. .. .. . -.

The significance of a sample inspection nduction from 5.0% to 45% will be evaluated.. If it is desired to fmd one flaw within a sample of welds, then a larger finite number of flaws must exist in the population to have a certain probability (akin to a level of confidence) of finding at least one flaw. This is implicit from the fact that the BWRW allows a sample inspection pIan. For the sake of argument, assume that a level of confidence of 90% is required. -3is assumed forsimplicity that the probability of detecting (POD) any one flaw is 100%. I 1' For a sample of 9 welds within 178 welds (5.0%). the= must be 40 flaws in the total population in order to assure that there is about a 90% chance of detecting at least one of the flaws within the sample.

! 134/174 x 133 32/172 x 131/171x 130/170= 0.095 (4058confiden~level) . -. .

j .. .

The actual probability of detectingat least one of the 40 in thisexampk is 90.5%.

For a sample of 8 welds within 178welds (4.5% the actual sample examined), the probability 6f detecting 1 at least one of the 40 flaws only drops to 875% (from 905%).

138/178x 137/177x 13W176x 139175x 134/174x 133173 x 1324172 x 131/171=0.125 (87.5% confidence level)

. . j .

1 Clearly, this s m a l l incremental decrease & the confidence level is statistically insignificant and within acceptable limits given that the probability of detecting at least one flaw drops by only 3 percent.

I _' - .( . , . . . ,. . ...

-. &&ixriexit

. . , I..,. . . .

fiii i p s

~ - t' i n p ~

i & ~ d f

. t h. g~ide,+t;es e  : C ~

6vef:the.fit

,w+e, yeaiis..@i~

&.?e t... . . . ... .:

Duration of Technical Justiflcaiion(Starehow hng the dcviatton will be in effect.)

This deviation will expire following FWO 24 (2004). because by that time the minimum 5% sample inspection will be completed.

VYPPF 7027.01 PP 7027 Rev. 2 Page 2 of 4 Appendix C PP 7027 Rev. 3 Page 21 of 61

Appendix C (Continued)

AssumDtions/own I t e q (LLFt my assumptiom wed in the 7E and provide a basis for each. List any open items requiring adiitionai action prior to closrrre of the TE)

It is assumed that at least one blade will need to be changed out in RFO 24 (2004) and that at least f o u blades wiU be changed out between RF026 (20079 and RFO 27 (2008).

The industry implicitlyaccepts a certain number of flaws in a population of welds by endorsing the use ofa sample inspectionprogram.

R&~mendatio~q cifir dctclild recommcndOtl0RT. as required to resolve the evaluated conditwn Lkr afl documents requiring changes and attach marked up pagu Clear4 sate recommendafia

• 11sfor p h nwd@&m or changes to o p e r d g prac?ices,inchding recommended changes to p h t pr0ceaures.J Based OD the above analysis, this Technical Justification recommends the following action:

1. Examine welds CRGT-2 and CRGT-3 in one guide tube during RFO 24 (2004)to complete h e original 5% sample..

Responsible Department- Code Programs I .1 Due Date - May 31,2004 ., .

Approvak {Printname rmdpr4vides i g m t u d d e . A thorough review shall include and consider inputfmrn u wide vmety of I --,

T$$b3Re~tor IntemalsManagement Program Coordinator Mech~caUStructurdDesign (if applicable) . . . . . . . . .. . ..

ae&stry(ga~liC&ie). . . ,.. .. . . ... . . . . . . . .

i Other Cross-Disciplineor TndependentReview (ii applicable)

Code Programs Manager Closeout (AU actions that were recommwdcd by rhe Technical Jwt$cafwn and acceptrd by management have been hiriated and any identijied open ifemhave beeti &positioned)

... I Reactor Inteds Management Program Coordinator . . . .

(&nature).

..(e&).:, .li

1. Document StIe (miuding Rev. No. and Date,ifapplicable) 1 BWRW-47, December 1997, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines 2 BWRVTP-47-A,June 2002,BWR Lower Plenum Inspection and Flaw Evaluation Guidelines 3 1 PP 7027, Revision 1, Reiktor Vessel Yntemds ManagementProgram 4 I Reactor Vessel Intemals ComponentsBasis For Inspection And Other Management -

L 1 Requirements, dated February 13,2003 I WPPF 7027.01 PP 7027 Rev. 2 Page 3 of 4 Appendix C PP 7027 Rev. 3 Page 22 of 61

Appendix C (Continued)

Design Output Documents - The following documents are impacted by this TE.

' R I Document Title i N/A I None A .

I f -1

.I  :.

I

. , 7.

VYPPF 7027.0 1 PP 7027 Rev. 2 Page 4 of 4 Appendix C PP 7027 Rev. 3 Page 23 of 61

Appendix C (Continued)

Technical Justiffcation No.2003-04

Title:

Continued Operation without a Feedwater Ziac Injection System Technical justification is required when utility procedures, inspections. methodology, or guidelines are inconsistent with the intent of the supporting BWRVIP guidelines.

B7KRVIP Reauiremea (Give BWRVIP donunent and Section reference with a restatement ofthe requirement.)

BWRVIP-79, Section 3.2.3.3 discusses the benefit of zinc order to reduce cobalt 60 isotope buiidup for dose considerations. It states, White it is believed that a reasonably optimized value is 5-10 ppb zinc in the reactor water so that the benefits can be maximized while still remaining comfortably within the historical experience band, each utility must perform their own costmenefit evaluation to discern what concentration is optimum for them.

BWRW-107, Section 5.1 also states, Adjust feedwater zinc injection rate to result in a steady reactor water level of 5 to IO ppb...and maintain this level during post NMCA operation. (Note: This recommendation may not be consistent with fuel vendor recommendations.

1 Vermont Yankee Deviadoq (Record how Vermont Yankee deviates or dcviatedfrorn the BWRVIP requirement.)

Vermont Yankee - not bossessing a zinc injection system - does not have a way to adjust zinc levels, although VY has maintained a reactor coolant zinc concentration around that general range as a result of having an admiralty condenser.

Justification(Provide the basis for determining that the proposed deviation meets the swne objective and inte&, or Ievel of consenatism ecxfribited by the BWRViP guidelines. The justifcation sMI be supported by calculations when warranted.

Cleurb identi& all available information a d resources, which a b w the deviation to be acceptable. Clearly iCienrifr the impact thus the deviation will have on meeting the inrent of the guideline.)

i The presence of zinc in the reactor coolant will minimize the incorporation of Co-60 into oxide fims on reactor vessel internals and associated piping. Zinc also stabilizes the existing fuel depasits, which reduces the release rate of corrosion products such as Co-60 into the reactor coolant. The original information came from comparing dose rates at plants that had admiralty condensers with filter demineralizers to those with stainless steel ones. Admiralty condensers have tubes that are approximately 21% zinc and 78% copper. Many utilities replaced their admiralty condensers or i installed deep bed demineralizers based on copper concerns associated with Crud Induced Localized - I i

Corrosion. ms factor prompted them to initiate zinc injection utilizing depleted zinc ta reduce dose rates. Initially, this was done based on the substantial increase in reactor internal dose rates following initiation of Hydrogen Water Chemistry (NWC). i Three GE BWRs located in the US reportzd unexpectedly high release rates of activated corrosion products to the reactor coolant during cool-down prior to their refueling outages. Two of these plants received mid-cycle Noble Metal Coating (NMC)applications. One of these plants had no $nc injection while the others were maintaining zinc concentration in the range of 2-3 ppb, which is slightly lower than Vermont Yankee. Those plants that maintained zinc concentrations in the 5-10 ppb range saw a modest increase in one case and a reduction in dose rates in the others. In addition, these three plants did not experience inordinate releases of corrosion products during the refueling outage shutdowns.

From tbis information, GE infers that the higher reactor water zinc concentrations more effectively stabilized the fuel deposits and minimized the release of activated corrosion products to the coolaat.

3 W P P F 7027.01 PP 7027 Rev. 2 Page 1 of4 Appendix C PP 7027 Rev. 3 Page 24 of 61

Appendix C (Continued)

In GE SIL No. 631. the following statement is made: "Maintain the reactor water zinc concentration in the 5-10 ppb range. This is applicable except where it has been clearly demonstrated that there have been no significant drywell dose rate issues for a complete cycle following the application while

. maintaining a Iower zinc concenttation in the reactor water." "At both plants that experienced higher than expected dose rates, the nominal zinc concentration in the reactor water was 2-3 ppb for the majority of the cycle following the NMCA."

BWRW-107 makes several 'Commendations relating to the Ljection of depleted zinc (DZO). It states, Maintain'reactor water zinc at 5-10 ppb and the 2x10-5 micro-cilppb Co-6O(s)/Zn(s) ratio. 'Rds recommendation is solely for the purpose of reducing out of core dose rates. It requires that a utility have a zinc injection system that utilizes depleted zinc.

The installation of a zinc injection system would cost approximately 1,OOO.OOO dollars and require an expenditure of 150,OOO dollars annually for depleted zinc. There are currently no plans to install such a system as long as we have an admiralty condenser. Engineering is currently evaluating the replacement of the condenser with a titanium condenser. They are now aware that such a change would require the implementation of zinc injection. The earliest probability of installing a new condenser is in 2007 based on current priorities.

Vermont Yank- has maintained a reactor coolant zinc concentration in the range of 2.5 -10 ppb over its entire operating history as a result of having an admiralty condenser. Since the replacement of our recirculation piping in 1986 with Hitachi 316 stainless, electro-polished pipe, we have maintained very low recirc pipe dose rates of approximately 75 -120 mWhr. In the early 1980s we began a cobalt reduction program that included such activities as replacing the stellite in the feedwater regulation

- valves. For 2002, reactor coolant zinc concentration ranged frdm 3.7 to 11.7 ppb with a mean of 6.4 ppb I and an average of 7.0 ppb. Thus, we generally met th&requirement to keep RV zinc concentration in the

- range of 5-10 ppb.

However, we have minimal control over the concentration of zinc in the feedwater, as it is a function of condensate temperature condensate demineralizer efficiency.

Natural zinc frdm the y condenser ultimately becomes activated in the reactor coolant to Zn-65.

VY has the highest reactor coolant 211-65 concentr the industry. However, this does not have a significant impact on recirc pipe dose rates. Those that inject depleted zinc to not have to worry ---

about the zinc activation problem.

Vermont Yank- is unique among BWRs. This means that industry data relative to out-of-core dose rates and RV zinc concentration may not ap&. The following set of con'ditions does not exist at any 0theIi BYLR: *. .. . .. ..

1. Filter Demineralizer plant without supporting deep beds

2. Admiralty Condenser

3. Low fpedwater iron

4. NMCA without hydrogen addition

5. Recirc Pipe that is Kitachi 3 16 electro-polished stainless steel

6. 15 years of BRAC point dose rates in the 80-125 mwhr range

7. No chemical decontaminations during the past 15 ye-VYPPF 7027.01 PP 7027 Rev. 2 Page 2 of 4 Appendix C PP 7027 Rev. 3 Page 25 of 61

Appendix C (Continued)

8. Very low ManRem outage exposure (last outage was a record for a B W R at -76 ManRem

9. Highest feedwater copper levels in the industry

10. Highest reactor vessel Zn-65 levels in the industry-Given our recent history, it appears that the current plant chemistry is adequate in keeping out of core dose rates within acceptable limits. The current plant chemistry does not support the expense required to initiate DZO. In addition, recent industry fuel problems have raised the question, HOW much is too much zinc in the reactor coolant? Some utilities are already reducing the amount of zinc that is injected to alleviate the crud buildup on the fuel. ,

Duration of Technical Justificatioq(State how long the deviatwn will be in e e c t . )

This deviation will remain in effect until the main condenser tubing is replaced with an alternate material.

AssumDtionsthen Xtemg ( L i s any assumptions used in the TE and provide a basis for each. List any open item requiring additionnl action prior to closure of the TE.)

i ,.i

~econunenda~oxq (List detaifed recommendatiom, (LP required to resolve the evaluated condi&ioa List all documents requiring changes and attach marked up pages.. Clearly state recommendOfiORSfor p h t t l l o d i j i c a t i o f l s or changes to operating practices, including recommended changes to pkurt procedures.)

Based on the above analysis,this Technical Justification recommends the following actions: I

1. Continue plant operations as in the past relying on the natural zinc from the condenser to help control out-of-mre dose rates. Plan on installing and initiating zinc injection in conjunction with a condenser replacement.

. Responsible Department - Systems Engineering Due Date - Not Applicable Approvals (Print name andprovidc signuture/date. A thorough review shall include und consider inputfrom a wide variely of Intemals Management Progtam Coordinator MechanicaVSmxctural Design (if applicable)

VYPPF 7027.01 PP 7027 Rev. 2 Page 3 of 4 Appendix C PP 7027 Rev. 3 Page 26 of 61

Appendix C (Continued)

Closeout (All actions that were recommended by the Technical Just~cation and accepted by management have been initirrted and m y idetu@ed open items have been dispositioned)

N/A 1 N f A Reactor Internals Management Program Coordinatcjr (signature) - (date)

Design Output Documents - The following documents are impa;cted by this "E.

I Document Title I

I, -Nnne i

1 I

......... .. ~I I .

..:, ~.

. . . . .. . . .I

. I WPPF 7027.0 1 PP 7027 Rev. 2 Page 4 of 4 Appendix C PP 7027 Rev. 3 Page 27 of 61

Appendix C (Continued)

Technical J d c a t i o n No. 2003-05 ld-q!Q

Title:

Feedwater Copper Concentrations above Recommended Limits Technical justification is required when utility procedures, inspections, methodology, or guidelbes are inconsistent with the intent of the supporting B W R W guidelines.

BWRVIP Reauirement (Give BUlRVIP document and Section reference with a restatement of the requirement.)

BWRVlP-79, Table 4-6, No& c states, h engineering evaluation should be performed before application of this value [>0.20 ppb feedwater total copper] at plants with copper alloy condenser tubes and powdered since it may not be achievable without costly plant modifcations. In these filteddemi.neralizerser/demineralizers, circumstances, a limit above 0.2 ppb may be justifiable based on previous performance and core design considerations.

Vermont Yaukee Deviation(Record how Vermont Yankee deviates or h i a t e d f r o m the BWRVIP requirement.)

Feedwater Copper has been consistently above the current (2000revision) EPRI guideline value of > 9 0.2 ppb.

JustifkatrOg (Provide the ba+ for detenninlirg that the proposed dntiation the same objcctivc and intent, or level crf comentrrtism dibitted &y the BWRWP guidklines. The jmj7cation shall be supported by calculatiorrr when warranted 1

Clearly icient~a all availnble @formation and resources, which albw the deviation to be acceptable. Clearfy identifu the iinpac!

that the d e v W n will have on meeting the inrent of the guideline..) i 1

BACKGROUND:

Elevated feedwater capper levels for plants with admiralty condensers and filter demineralizers have been an industry issue for over a decade. Most BV?Fts have resolved the issue by replacing their condensers or adding deep bed d e r n i n d i r s down stream of their condensate polishers. There are currently only two BWRs that have not taken the previously stated corrective actions. These zye Columbia and Vermont Yankee. Columbia Station has deveIoped a technical justification for maintaining a feedwater copper limit higher that recornmended in the EPRI Guidelines but in accordance with their fuel warranty of 0.5 ppb.

Filter demineralizers are at approximately 90% efficient for removal of soluble species due to the very -

short residence time on the thin ion exchange resin layer on the precoat. The challenge is to maintain I I

the current efficiency under all phases ofplant operation. When tighter precoats are utilized they take out more of the insoluble species and seem to increase the ion exchange efficiency. The age of the elements is also a factor in the removal of insolubles. When lowcross-Wed resins are used for crud I control, they shed some sulfa&. Their use is therefore Limited based on the increase in reactor coolant I sulfates. In the effort to maintain orincreasethe 90% efficiency we are &o removing iron and zinc.

Therefore, there is a balance between the achievable feedwater copper and the desired feedwater iron 1 and reactor coolant Zinc and sulfate concentrations. I The 2000 revision of the EPRI Guidelines indicates that the desired feedwater iron range is lppb +I- 0.5 ppb and that the desired reactor coolant range for zinc is 5-10 ppb. However, it further states that experience has demonstrated that benefits are being achieved with RV zinc concentrations as Iow as 3 ppb. With regard to feedwater iron it states, Rm between 0.3 and 0.5 ppb long term experience across multiple units is lacking; adverse consequences have been reported from long term operation near 0.1 ppb in the U.S., Sweden and Japan.

Ti 2003-05 Page 1 of7 Appendix C PP 7027 Rev. 3 Page 28 of 61

Appendix C (Continued)

When the EPRI Water Chemistry Guidelines were issued in 1986, the recommended feedwater copper limit was 0.5 ppb. This limit was also in the 1996 revision to the Guidelines with a note that stated that this is a common value listed in fuel warranties. Vermont Yankee adopted the Guidelines and created a water chemistry policy, VYP-13 1. Plant management took an exception to the guideline's copper limit recommendation. Based on discussions with GE,the 1.0 ppb limit was maintained in accordance with

! the GE Fuel Contract, Vexmont Yankee may not be able to meet the current Guideliine value of 0.2 ppb copper under most operating conditions without making expensive plant modifications. 'However, given that copper has been implicated as a potential contributor to-de Cycle 22 fuel failures, iis prudent so 1 take actions to reduce feedwater copper to as low as reasonably achievable without compromising other parameters such as reactor coohnt zinc. sulfate and feedwateriron.

I Vermont Yankee has had recurrent feedwater copper excursions greater than 1.0ppb for more than a I

decade. The most significant events occurzed during 1988 and 1995 when the Fuel Contract Continuous limit of 1.0 ppb was exceded for more than 14 days. During 1988 feedwater copper was ~ 2 . 0 ppb for 6

!, 4 weeks. "here were some feedwater copper values >1.0 ppb in 1999 and in 2001, all of which occurred during the summer months. Feedwater copper is most difficult to control during summer months when condensate temperanves may reach 138 degrees F as a result of Close/Hybridcycle operation I.i Vermont Yankee has maintainedfeedwater copper at approximately 0.27ppb (average) for the first 6 months of Cycle 23. There were approximately 30 days during the period when feedwater copper was at

!' or below 0.2 ppb. During the summer months, feedwater copper is much more difficultto control.

Achieving vatues below 02 ppb m a y not be possible during the warmest months between July and September without installing deep bed demineralizers or changing out the admiralty condenser- The current data indicates that tbe achievable range for feedwater copper is 4 . 2 ppb to 0.5 ppb witb the f yearly average being (0.3 ppb, . .

High feedwa'ter copper ultimately results in high reactor coolant copper in the range of 5-10 ppb on I average. Approximately 90% of the metals that are in the coolant plate out on core surfaces ipcluding the fuel. The increased crud loading on the fuel can create a problem known as CfLc (Crud Induced Localized Corrosion)that may resuIt in a fuel failure. Vermont Yankee did not have any clearly identified CILC related fuel failures during the 80s or 90s.

Aamiralty condensers provide several benefits. Besides being resistant to corrosion, they provide a i . natural source of zinc. Zinc has been shown to be an important factor in reducing out of core dose rates.

Plants without admiralty condensers have to inject zinc, whereas Vermont Yank- can maintain a reactor coolant zinc concentration of 3-6 ppb without needing to perform zinc injection. Having had

'-9 natuql zinc for its eatire operating histdry has helped YY to maintain dose ptedpersonal exposure very

.- J low compiuea to the rest of the industry.

1 CORRECTIVEACTIONS; were put in place to A s a result of the feedwater copper excursions of 1988,1995 and 1999, a series of corrective actions d prevent feedwater copper excursions. These corrective actions sipifkantly reduced the number of excursions >LO ppb. In fact, there were none in ZOO0 and only one in 2001, The following are some of the corrective actions taken over the years:

TJ 200345 Pase 2 of7 Appendix C PP 7027 Rev. 3 Page 29 of 61

Appendix C (Continued) 1, Reduction in the source term. The turbine casing, a source ofcopper was replaced in 1994.

Siticon brass nuts in the feedwater heaters were replaced by stainless steel ones. All of the condensate pumps' first three stages were changed from bmss to stainless steel.

2. Placed the Body Feed system back into service in order to increase copper ion removal efficiency of the demineralizers by filling in gaps in the precoats.

3. Purchased high eficiency crud reduction resins for use during the warmer months

4. Feedwater metals analyzed more frequently during summer months.

5. A senior Graver Engineer (CharlieMosser) was contracted to review VY's condensate polishing process and make appropriate recommendations for process improvement.

Recornmendations from his final report were implemented in 2001 and 2002 for improvements to the backwash and precoating process.

6. Following participation in an INPO assist visit to Quad Cities, an action plan was developed and implemented to change all of the elements in the condensate &mineralizers from 2 inch diameter to 2.25 inch diameter. This increased the element surface area of each vessel by 11s sq ft. All.vessels currently have these new elements.

CORRECTIVE ACTIONS IN "ECOURSE OF DEVELOPMENT; A revised action plan for feedwater copper control has been developed and will be implemented beginning in M a y of 2003. Chemistry will be optimizing mer demineralization processes and evaluating the data for process improvement. An assessment of the 2003 feedwater copper control strategy will be performed at the end of 2003 and the plan w i l l be revised accordingly. Level 1 LOCA UND-2003-326,02 was created to review the action plan hnplementation status. Excerpts from the plan are as follows:

1. Starting Aprit 2003,all condemins were p r e c o w with a sandwich of P-202Hfollowed by Metidian 2000. Once the vessel is placed in service it will be Body Fed with an additional three bags of Ecodex P-202H.Precoats of this type Wiu continue until October ISa or such time that analytical data indicates that a change in precoat formulation is warranted. NOTE:%oats of this type may increase RV sulfate to 2.0 ppb for a short duration and therefore more than one vessel should not be done within a three-day interval. Other copper removal resins may be used such as puolite CG-125-3. Starting in June, fetdwater copper control evduation was begun with ail 5 vessels having the same type of precoat

2. Began Metals analysis or individual demineraZizers in April 2003 and will continue on a weekly basis until November of 2003,at which time this process will be evaluated for continuation through the winter.

3. In May 2003,revised the existing technical justification for feedwater copper to indicate a formal approach to copper control that is ALARA providiog administrative goals for summer and winter conditions.

4. Reviewed the approach to copper control at Col&b& station and their technical jusrification for maintaining feedwater below 0.5 ppb, which is the current GE Fuel Warranty value.

5. Avoided condensate denheraker system operation with 4 vessels in service as much as possible (other than for backwashes and precoats) during the period of M a y 15th until October 15*. This means that element replacement should not be done during this time. No condemin element change outs were scheduled during this interval.

6. Carefully review the copper data from the individual demineralkers and take appropriate actions to reduce effluent copper concentration,(Body Feeds or new Precoats). Establish an action Xevel for demineralizer effluent copper based on plant operating conditions.

TJ 2003-05 Page 3 of7 Appendix C PP 7027 Rev. 3 Page 30 of 6 1

Appendix C (Continued)

7. In order to determine the optimum runtime for a precoat and an achievable feedwater copper limit, the fouowing data wu need to be evaluated:

a. Precoat formulation and number of Body Feeds

b. Condensate temperature (see item #8)

c. Reactor Vessel &c, copper and sulfate concentrations

d. Feedwater zinc, iron and copper concentrations e, Individual demineralizer effluent copper and precoat p n time f.' Condensate deniine-r influent copper Data Trending was started in April 2003.

8. Monitor the condensate'deminedizer influent temperature, (ERms computer point FO-76 .

(steam packing exhauster effluent). This is to be done from M a y 15* until October 15* and more often if the plant is on closed cycle for longer than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (chlorination). This point should be trended along with the upstream river temperature. Temperatures above 130 degrees F negatively impact copper control and need to be brought to the attention of Cherrtistry/Plant Management. This is ongoing.

9. Project the increased costs for ion exchange resins and waste disposal.

10. Collected feedwater metals on a daily (24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) basis during the period from A p d 21st to October 15*. During &e cooler months three 48-hour samples and one 24-hour sample are Utilized.

11. Monitor the depo of cop& in the reactor coolant in micrograms/second based on the weekly reactor coolant metals analysis. This is ongoing.

12. Benchmark other utilities to see who uses online IC or XRF for metals analysis. How accurate is the process and the cost of equipment, installation and cost of maintenance. Consider long-term modific8tion for copper monitoring. This is ongoing.

13. Performed individual condedn metals analysis .twiceper week during the period of 7-15 to 9-15

.14. korporate the critical elements of copper control into-aplant procedure or other technical . - .

docuplent.

> 1 ._ .. . .

r .

~ ,- . .. .. . . .

Items 7.8; 12 and 14 were ncommendati -.

a consultant for senior plant management quarterly assessment visits to the plant site.

TE-c ALJUSTIFICATZON BASIS; Table 4-6 in the EPRI 2000 Guide te: neeiing evaluati uld-be performed before application of this value w i e copper alloy condenser tubes and powdered fikrldemineralizers, &ice it r%y not be achievable &@out costly blant modifications. In tliese . .

circumstahces, a limit above 0.2 ppb &y be justifies based on previous pkformance and c o k design considerations." The GuideGes further state in section 3-38; "This peculiar phenomenon called CLLC resulted in several cases of fuel failure from late 1978 up to tbe late 198Os, but since has been mitigated by using higher nodular corrosion resistant cladding ..."

General Electric expressed a &ncem in 1996 that high reactor coolant copper levels would interfere '

with Hydrogen Water Chemistry (HWC)but at the same time indicated that the corrosion resistance of their fuel had been improved to resist the CILC phenonienon. Since that time they issued a report entitled "The C u Club, Laboratory Test Results", that supports H W C as well as Noble Metal Coating TJ 2003-05 Page 4 of7 Appendix C PP 7027 Rev. 3 Page 31 of 61

Appendix C (Continued)

Application (NMCA) under reactor coolant levels as high as 15 ppb. Copper levels in the reactor coolant at Vermont Yankee currently rauge from approximately 5-8 ppb.

The River Bend fuel failure incident of 1 9 b was thoroughly evaluated and discussed at several EPRI meetings attended by the V Y Plant Chemist. River Bend experienced fuel failures in 7 fuel assemblies that appeared to be related to copper. Although there was an elevated amount of copper in the fuel crud, the f- ilure mechanism was more a result of heavy deposition of iron oxide-based crud. Two con< -tivityexcursicxis during the October 2 9 9 7 refieling outage and the subsequent startup are the sus- causes for a large "Mlux of corrosion products early in the opemhg cycle. Their feedwater 3- evels were around 3.7 ppb. This did not account for all iron deposits on the fuel inside the core and it ;is not clear where this extra iron came from..At Vermont Yankee,feedwater iron is always maintained I-,.* +heFnnI Guideline value of 5.0 ppb and is infrequently above 2.0 ppb. As a result, the m P at River Bend are not expected hem, even with a feedwater copper 2sed on a review of the EPRI Guidelines (section 3-40), this incident was

'deline value for feedwater copper being reduced from 0.5ppb to 0.2 ppb. Io dib. - - e u __ . L a A...

. Electric, they have indicated that the justification for this lower limit is not L1

~ - 9 a feedwater copper limit of 0.5 ppb. Their feedwater copper runs in the range re perform& a technical justification for this Limit that basically states that the .+ . pact fuel performance. While Vermont Yankee can maintain feedwater copper 4.5 p p d y average, it may not be able to achieve this Limit on a day to day basis in the hottest months 01&I ear.

The General Electric BFUVY Root Cause Investigation Report dated 03/17/2003did not determine a root cause %rthe 5 failures idenflied during Cycle 22: The report indicated that the extraordinary high levels of ccpper likely contributed to accelerating the corrosion process along with some unknown initiating event. Fuel examinations indicated relatively high copper deposits on Cycle 19,20 and 2 1 fuel. All 5 of the failures were from the same tubing lot and failed in VY reload number 20. +Thedata indicate that other reIoads residing in the core are not exhibiting the accelerated cornsion. It was noted that V Y leads the fleet in feedwater copper, but that it does not represent a change - V Y has always had high feedwater copper, and has not had related fuel failure problems since the late 1970s. The root cause evaluation did not provide any rkcommendationsfor copper control or indications that the current fuel warranty value of0.5 ppb for feedwater copper would be changed.

i, Following the V Y fuel faiIures, the Reactor Engineering department contacted Aquarius Services Corp.

(AIStrasser) and requested that he evaluate afl of the data associated with the fuel failures. This included GE e\raIuatioasand material, two cycles of Chemistry Data and plant operating history- Fuel manufacturing data was also reviewed, Some concIusions and notes from his report are as folIows:

1 ..

a. NoduIar corrosion should not occur on an in-process heat-treated cladding. Of the two causes, corrosion by high copper chemistry water is unlikely, since GE work in the past showed that this I

does not occur either in or ex-reactor. High Cu chemistry with N M C might induce nodular corrosion by the change in redox conditions at the cladding surface. The previously proposed i poor in-process heat-treating control could be a second cause.

b. The continued evaluation of the fuel examination tapes confirm previous conclusions that there is a correlation between the level of corrosion observed, some of the cladding lot numbers and i some of the local peaking factor histories of the rods. i

c. The author concurs with GNF's conclusion that three cladding lot numbers behaved poorly.

TJ 2003-05 Page 5 of 7 Appendix C PP 7027 Rev. 3 Page 32 of 61

Appendix C (Continued)

' d. A cursory comparison of fuel rod local peaking factor histories of rods from the same cladding lot indicates a reeonable correlation of power with corrosion control.

e. Based on GE information, there does not appear to be a correlation between Cu content and liftoffmeasurements, and there does not appear to be a correlation between linear power generation and liftoff either. This indicates a lack of correlation between copper content and corrosion.

f. The rnaximum concentration of copper at a discreet axial location was 1885 uglcm2 that

, . occurred at the 31" elevation of Rod D*Bundle YJF493. One should note that this was a rod withour a fuel defect. . -

CONCLUSILONS; Based on this review of hidustry documents and operating experience, the guidance in the GE Fuel Warranty and the justification prepared by Columbia Station, it is concluded that copper m a y play a role in the fuel corrosion process but that further evaluations are required, especially as they relate to fuel duty. Feedwater copper levels M.2 ppb but d . 5 ppb will not interfere with NMCA. HWC or our IGSCC mitigation program. However, it is the plant goal to maintain feedwater copper levels as low as reasonably achievable and to comply with the EPRI ZOO0Waiter Chemistry Guideline value of 0.2 ppb.

Doration of Technical Justrncaiiog (State how tong the devintionwill be in &ea)

This deviation will remain in effect h d e f ~ t e l y .

A s n r m D t 3 O ~ tems X ( L i s any assurnptkms used in the ?E MdprovIdc u M f i r each List any open items requiring aakWona4 action prior to ctosure . .ofthe Z?L) .. . . ..

None. . . .. .,

Recommendations (Lirt detor documrnrs requiring changes md attuch d up pa8e.f. clcrrdy m e reconunenaWonsfor pkmt m0difiation.s or changes io opercrting pracrices, including recommurded changes r0plant procedures.)

B d on the above analysis, this Technical Justification recommends the following actions:

1. Continue impIemcntation of the copperreduction plan.

Responsiile Department - Chemistry

. r i . . . . . '. . . . '. .\ .. _

TJ 2003-05 Page 6 of 7 Appendix C PP 7027 Rev. 3 Page 33 of 61

Appendix C (Continued)

ApprovaLs (Print m e und providc sfgnature/date. A thorough review shall include and consider inputfrom a wide variety of Reactor Internals Management Program Coordinator I Mu/& MechanicdStructural Design (if applicable) emistry (if applicable)

M A I #/A Other Cross-Discipline or Independent Review (if applicable)

I b?/$id&Code Programs Manager 3efl-7 /*.s 6 t-prco*r (signature) (ate)

Qoseont (All actions that were recommerUed by rhe TechnicalJustification and accepted by mMagernent have been initiated and any ident@ed open items h e been dis;posiiioned) kql- I i&hh.I Reactor Internals Management Program Coordinator (date)

Services Corp.,June 7,2002 14 Bill Russell quarterly chemistry/fuel failure evaluations, 2002-2003 TJ 2003-05 Page 7 of 7 Appendix C PP 7027 Rev. 3 Page 34 of 61

~~

Appendix C (Continued)

TechnicalJustXcation No. 2004-01

Title:

Justification for Alternative Inspection of Core Plate Rim Hold-down Bolts Technical justification is required when utility procedures, inspections, methodology, or guidelines are inconsistent with the intent of the supporting BWRVIP guidelines.

BWRVIP Reauiremnent ( G e e BWRVIP document and Section reference with a restatement of the requiremenr)

BWRVIP-25 (Reference 11,Table 3-2states that or rim hold-down bolts without repair wedges, Perform enhanced VT-1 fkom below the core plate (or U T from above core plate once the technique is developed) of 50% of the hold-down bolts. If cracking is detected, inspect the remahhg 50% of bolts:

Reinspection strategy to be based on plant-specific analyses to assure that critical numbers of hlts are

... intact to prevent lateral displacement of core plate.

ii In the April 28, 1999 NRC Safety Evaluation (Reference 3), the NRC states, The staff believes that an initial baseline inspection should be comprehensive, apd include all components that are practicable to inspect, based on tooling availability. However in t.@&%malSafety Evaluation of December 19,1999 (Ref. 4), the NRC consents with the BWRYIP previous response (October 6,1999) that the inspection should be limited to components required for plant safe shutdown. The BWRVIP response (Reference

2) had stated, If not, no inspection is reqbired. This strategy is adequate to ensure plant safety.

Performing a baseline inspection of locations which, if failed, have no affect on plant safety, would require an unnecessary increase in outage time in addition to the cost associated with developing and qualifying additional inspection tooling. Consequently, the BWRVIP does not agree with the NRC suggestion that all locations on the core plate be inspected in a comprehensive baseline inspection.

BWRVIP-25report states that, ..as long as the critical number of bolts &main intact, lateral support for the core plate assembly is assured.. .Therefore, there is no safety consequences of failure at Location

8. (Location 8 in BWRVIP-25 discusses failure Iocation for Aligner Pin and Socket to Rim Welds).

BWRVIP-25 also discusses acceptable alternatives to inspection, specifically involving plant-s$&ific analysis or repairs and/or modifications.

q - (Record how Vermont Yankee deviates or akviutedfiom the BWRVIP requirement.)

i i.. i In view of the fact that no vendors have yet developed a delivery system for top-of-bolt UT techniques, and that EVT-1inspection from below the core plate has accessibility limitations, V Y will perform VT-3 inspection of 50% (15) of the top of the bolted connections every other refueling outage. Should access to the lower plenum become available, VY plans to augment core bolt inspections by performing a VT-3 inspection of accessible rimhold-down bolt bottom locking engagement and accessible aligner pin assemblies.

JustiriCati04 (Provide the basisfor &termining that the proposed deviation meets the s a m e objective and intent, or level of conservatism exhibited b y the BWRVIP guidelines- The justification shall be supported by calculations when warranted CIearfyirienffi all availabZP it&nnution and resources, which a h w the deviation ro be acceptable. Clearly identify the impact that the deviation will have on meeting the intent of the guideline.)

The core plate assembly provides lateral support for the fuel bundles, control rod guide tubes, and in-core instrumentation during seismic events, and provides vertical support for the peripheral fuel assemblies. The core plate assembly consists of a perforated plate reinforced by stiffener beams and supported on the perimeter by a circular rim. There are stabilizer beams (or cross ties) between the TJ 2004-01 Page 1 of 4 Appendix C PP 7027 Rev. 3 Page 35 of 61

Appendix C (Continued) stiffener beams, which also provide support for in-core housing monitors. The V Y core plate rim is bolted to a ledge on the core shroud with 30 preloaded, 2.0 diameter, 304 stainless steel rim hold-down bolts, which prevent horizontal and .verticalmovement. The core plate is positioned on the shroud ledge by four 2.5 diameter vertical aligner pins. The pin assembly engages sockets, which are welded to both the core plate and the core shroud.

The core plate structure is prevented from horizontal translation during the design basis event by friction from the clamping force from the core plate rim hold-down bolts. V Y has not yet calculated the minimum number of bolts required to resist sliding against seismic shear loads. However, the existence of the aligner pins in effect reduces the clamping preload required or the core plate bolts and would reduce the number of intact bolted connections required.

Alternate Insuection Acceptance Basis VY verified the structural integrity of the top locking engagement of all bolts as installed per drawing requirements through Vf-3 inspections. A baseline VT-3 examination of the tops of all 30 bolted I .I connections was performed in RFO 19 (1996) (Fteference 5). Then, during the last three refueling outages RFO 21 (1999), RFO 22 (2001), and RFO 23 (22002)- a VT-3examination of the tops of 50% 1;: :

(1 5 ) of the bolted connections was conducted (References 6,7,and 8). The exams performed showed -

no signs of cracking or bolting disassemtily.

i V Y plans to re-inspect by VT-3 a minimum 50% sampling of these bolteh connections every other i refueling outage (on a rotating basis) to assess the structural integrity of the bolts top locking engagement.

Should access to the lower plenum become available, V Y plans to augment core bolt inspections by performing a VI-3 inspection of accessible rim hold-down bolt bottom locking engagement and accessible aligder pin assemblies.

VY considers this inspection plan adequate, with a high confidence level, for ensuring the structural integrity of its core plate configuration to resist sliding against shear loads.

The performed top-of-the-bolt inspections confirmed that all of the 30 bolts are in place; there is no sign c $

1 of deformation nor cracking; and the upper nut, nut lock and fdlet weld is in place in all of the examined lo<ations. 1.

The lower bolt connection (see Drawing 5920-1933, Reference 12) is similar to the top in that the nut is welded by a fillet weld to the bolt (side) to keep the nut in place. It is unl+ly that where there are no failed connections in the sample that has been inspected (30) that a siflicant number of failed I

connections could exist in the remainder of the population (the uninspected lower end of the bolted connections). i Additionally, VY has very good water chemistry, which meets the requirements of BWRVIP-79 (Reference 14). AII components below the top of the core shroud are protected by Noble Metal Chemistry Application (NMCA) with sufficient hydrogen injection to mitigate IGSCC of vessel internals.

This alternate inspection plan offers a practical solution to the inspection criteria required by BWRVIP-25,because:

TJ 2004-01 Page 2 of 4 Appendix C PP 7027 Rev. 3 Page 36 of 61

Appendix C (Continued)

(I) No vendors have yet developed a delivery system far top-of-bolt UT techniques.

(II) The EVT-1 inspection frombelow the core plate has accessibility limitations. The ASME Code

.Section XI defines accessible surfaces as those areas made accessible for examination by removal of components during normal refueling outages, during a typical refueling outage.

Neither the shuffling of fuel bundles nor the replacement of control bladesallowsaccess to the core plate. Therefore, this requirement would add unnecessary increase in outage time,with no compensating benefits because a representative inspection can be performed of the upper side of the bolted corinection.

Conclusion V Y considers this altemate ins for examination of its core plate against seismic shear loads.

t UT technique is developed.

When this occurs, adquat&time for site deployment will be also be factored, as allowed by PP 7027, Paragraph 4.2.1.

Item (Usr any assumptio& used in rhe TJ diitional action prior to closure of the TJ.)

None.

ReoOmmendati- (Lisf detaiZed uired to resolve requiring changes and attach mrrnked up pages Clear&state recommendationsfor p h n t nwd$cutions or changes to operaring practices, including reconanudtd changes to pIant procedures.)

None.

Approvals (Print mame and provide signa2urddattz A thorough review shau include and consider inputfroma wide variety of

/ Reactor Internals Management Program Coordinator

/ b/h MechanicaVSt~ctwalDesign (if applicable)

/ P/h Chemistry (if applicable)

/ d&$kJther Cross-Disciphe or Independent Review (if applicable)

/ d ?Code ProgramsManager (signature) (date)

TI 2004-01 Page 3 of 4 Appendix C PP 7027 Rev. 3 Page 37 of 61

---

II L-Appendix C (Continued)

C l d u t (All actions thar were recommended by the Technical Justification and accepted by management have been initiated and any identifed open items have been &positioned. )

f 3 h / d Reactor Intemals Management Program Coordinator (signature) (date)

1. Document Title (including Rev. No. and Date, if applicable) 1 BWRVIP-25, December 1996, B W R Core Plate Inspection and Raw Evaluation Guidelines (EpRITR-1072845 2 BWRVIP Response to NRC M I on BWRW-25 and BWRVIP-26, December 19,1997 3 NRC Safety Evaluation of BWRVIP-25, April 28,1999 4 NRC Final Safety Evaluation of BWRVIP-25, December 19,1999 5 GENE Report dated October 6,1996, In-Vessel Visual Examination Report for the Vermont Yankee Nuclear Power Plant RFO 19 September/October 1996 6 . Framatome Technologies R eport dated November 17, 1999, 1999 RFO 21 Outage - Reactor, In-Vessel Services Report fo; Vermont Yankee Nuclear Power Corporation 7 FramatomeTechnologies Rep09 dated May 13,2001, 2001 TWO 22 Outage Reactor, In-Vessel Services Report for Vermont Yankee Nuclear Power Station

- i

- Vessel Services Rep03 for V&mont Yankee Nuclear Power Station 9 PP 7027, Reactor Vessel Intemals Management Program 10 NE 8067, Reactor Vessel Intemds Inspection Details 11 V Y Drawing 5920-1 5920-1101 101 12 _ _ J 1 1 2 - Y Drawin; 5920-1097 1 BWRVIP-79, February 2000,BWR Water Chemistry Guidelines (EPRI TR-1035 15R2)

, 15 I BWRVIP-94, August 2001, BWRVIP Program Implementation Guide (1006288)

TJ 2004-01 Page 4 of 4 Appendix C PP 7027 Rev. 3 Page 38 of 61

Appendix C (Continued)

Technical JustificationNo. 2004-02 I

Title:

Justification for Deferral of Inspection ofInaccessible Welds Technical justification is required when utility procedures, inspections, methodology, or guidelines am inconsistent with the intent of the supporting BWRVIP guidelines.

BWRVIP Resuirement (Give BWRVIP document Md Section rgerence wirh a restatement of the requirement)

The BWRVlP requires inspection of certain hidden or inaccessible welds. There are three hidden welds inside each of the two core spray n o d e s and two hidden welds inside each of the ten jet pump recirc inlet nozzles. The B W R W also requires that the integrity of the 9welds +side the core spray shroud collars be considered when the associated P8b weld integrity is diminished.

Core Surav The core spray thermal sleeve provides the flow path for core cooling water from the vessel nozzle external piping to the core spray piping tee-box. The core spray hidden welds are described in VY procedure NE 8067 (Reference 8), Appendix A, Paragraph 5.2. There are three welds on each thermal sleeve. CSTS-1is the safe-end tuning fork-to-10-inch schedule40 pup piece. CSTS-2is the pup piece-to- 10-inch by 8-inch concentric stahdard weight reducer. CSTS-3is the reducer-to-S-inch schedule 40 pipe piece.

BWRVIP-18 (Reference l), Paragraph 3.2.4,states, There is currently no inspection technique to inspect the thermal sleeve welds. This development need is being addressed by the B W R W Inspection Committee as a high priority item. Inspection of thermal sleeve welds should be done when the capability exists, following Figure 3-1 as appropriate for creviced or noncreviced welds. Figure 3- I also references the reinspection flowchart (Figure 3-3). Those flowcharts would require EVT-1 every refueling outage or UT inspection every other refueling outage of a full target weld set. Since EVT-1 is impossible, that leaves UT. The full target weld set is defined in Table 3-5 as ?4of the welds that are non-creviced. Therefore, if the thermal sleeve welds are non-creviced, they can be grouped the target weld set where ?4are required to be examined every other refueling outage.

Subsequent to publication of BWRW-18, the BWRVIP Inspection Committee produced a study (Reference 6) showing that inspection of the core spray and jet pump hidden welds could be possible, but it would be difficult and extremely costly. No vendor has undertaken the work to develop tooling in order to examine the hidden welds.

Further, indications have been recorded during ultrasonic examination of welds 1P8b and 3P8b (collar-to-shroud welds) at Vermont Yankee. A B W R W response, dated January 11, 1999, to the NRC Safety Evaluation of BWRVIP-18 contains guidance for the redundant core spray p9 welds inside the collar at the piping-to-shroud connection. This guidance is considered mandatory per B W - 9 4 , Section 1.3, because the BWRVIP Executives approved the response letter to the MRC. The guidance states in response to Issue 3.6(2) that, Weld F 9 is redundant to the PSa and P8b weIds in BWEU3-5 plants.

Therefore, consideration of the integrity of P9 only needs to be considered if the integrity of the P8a and P8b welds is insufficient.

TJ 2004-02 Page 1 of6 Appendix C PP 7027 Rev. 3 Page 39 of 61

Appendix C (Continued)

Jet h m u s .

The jet pump hidden welds are described in V Y procedure NE 8067 (Reference S), Appendix A, Paragraph 10.3. The thermal sleeve attaches the N2 nozzle safe-end to the jet pump riser elbow. It provides a flow path and reduces temperature variations, and thus thermal loading, on the N2 nozzle.

There are two full penetration circumferential welds in each of the ten jet pump thermal sleeves. TS-1 is the safe-end-to-thermal sleeve concentric reducer. TS-2is the reducer-to- 10-inch special pipe.

BWRVIP-41 (Reference 4), Table 3.3-1 requires for the baseline inspection of welds TS-1 and TS-2, Modified VT-1of 100% of weld HAZs over next two inspection cycles. 50% to be inspected in next inspection cycle. The required reinspection is, 25% per inspection cycle. A note states: [These]

welds may not be accessible for visual inspection. The B W R W Inspection Committee is currently addressing the need for developing an inspection technique for this weld. Inspection recommended when the technique becomes available.

Subsequent to publication of BWRVIP-41, the B W R W Inspection Committee produced a study (Reference 6)showing that inspection of the core spray and jet pump hidden welds could be possible, but it would be difficult and extremely costly. No vendor has undertaken the work to develop tooling in order to examine the hidden welds.

Inspection cycle is defined in BWRW-41, Section 3.2.1 as 6 years. Per PP 7027 (Reference 7), the I.

fust six-year inspection cycle is defined as starting as of the publication of BWRVIP-41, and thus covers the time frame of October 1997 through October 2003.

Vermont Yankee DeviatioQ(Record how Vermont Yankee deviates or deviatedjiorn the BWRVIP requirement.)

In view of the fact that no vendors have yet developed a delivery system to examine any of the hidden welds in the thermal sleeves inside the either the core spray n o d e s or the jet pump nozzles, no inspection of these welds has taken place. Further, even though examinations of the P9 welds at Vermont Yankee were attempted, the NDE technique qualifications for examination of the P9 weld were withdrawn by the BWRVIP. Therefore, no qualified examinations of the P9 welds redundant to the lP8b and 3P8b welds have ever been performed.

Justification (Provide the busis for &remining thnt the proposed deviation meets the same objective ami intent, or level of P

conservatism exhibited by the BWRVIP guidelines, m e justfiation shall be supported by calcukz?iom when warranted. i Clearly Sent@ all availnbk infirmation and resources, which allow the deviation to be acceptable. Clearly identzfi the impact L that the deviarwn will have on meeting tke intent of the g U i r i e h - )

AcceDtance Basis t

The hidden welds are not accessible for visual examination and would be a challenge for mechanized UT examination. There is currently no inspection technique developed to inspect the thermal sleeve k welds either with some degree of component disassembly or through deveIopment of specialized techniques.

I Core S D ~ThemalV SIeeve Welds Until such time as an inspection technique is available, BWRVIP-18 (Reference I), Section 3.2.4 Hidden Welds, states, ...a qualitative assessment of thermal sleeve integrity can be based on a plant-specific evaluation of similar core spray piping welds. If a plant has uncreviced thermal sleeve welds, TJ 2004-02 Page 2 of 6 Appendix C PP 7027 Rev. 3 Page 40 of 61

Appendix C (Continued) the evaluation welds should be the junction box-to-pipe welds and the upper elbow welds. If the thermal 1 sleeve welds are creviced, the evaluation welds should be the junction box cover plate weld, where i

applicable, the P1 weld in B W 3 - 5 plants where accessible for inspection, and the downcomer sleeve welds. Regardless of whether VYs thermal sleeve welds are creviced, none of the above evaluation welds at V Y (28 welds in all) show any indications of cracking. Therefore, the qualitative assessment I of the core spray thermal sleeve welds is satidactory.

I BWRVP-18, Section 2.2.1, states that most thermal sleeve welds are full penetration welds, but that some are creviced f d e t welds, and at bast one is a creviced partial penetration weld Then from the way that is worded, full penetration thermal sleeve welds would be considered to be non-cieviced. The 1

three core spray thermal sleeve welds in each of two nozzles are full penetration butt welds. So

. therefore, the likelihood that cracking could initiate in these welds is diminished.

BWRVIP-18, Section 3.2.4 further states that, E a thermal sleeve weld were to crack to the point of separation, the thermal sleeve and attached core spray piping might undergo some displacement, but the brackets holding the piping andlor the tight clearance between the thermal sleeve and nozzle wall would prevent gross separation. In such an extreme scenario, core spray would still be provided, but with some leakage.

I Core S ~ m P9v Welds I Because indications have been recorded during uIb.asonic examination of welds lP8b and 3P8b (collar-to-shroud welds) at Vermont Y d e e , integrity of the P9 welds must be considered. The BWRVIP I response, dated January 11,1999, to the NRC Safety Evaluation of BWRVTP-18 states that, Until such I . time that inspection of P9 is practical and demonstrated for all plant configurations, other tecMcally founded approaches are needed.. .In the interim if the integrity of PSa or P8b is diminished, the I condition of P9 would be considered in the overall integrity evaluation of the connection. The evaluation would consider the low likelihood of cracking to an extent that would jeopardize structural

. integrity considering sus w Vermont Yankee provided an ev conneCtion (Reference IO). That evaluation assumed in one of three cases that the collar-to-shroud weld I failed completely, in which case the core spray annulus piping is capable of displacing up to /4 inch L -9 axially and up to 0.028 inches vertically and horizontally. This evaluation assumed an intact F 9 weld, however.

The same Iogic that was used for the core spray thermal sleeve bidden welds can be applied to the P9 welds. A qualitative assessment ofthermal sleeve integrity can be based on a plant-specific evaluation of similar core spray piping welds. The E 9 welds are creviced. All other creviced core spray welds at Vermont Yankee - the junction box cover plate welds, the P1 welds, and the downcomer sleeve welds (16welds in all) - show no indications of cracking. Therefore, the qualitative assessment of the core spray t h e d sleeve welds Vermont Yankee has an internal commitment to perform examination of the P9 welds when an NDE technique becomes qualified.

TJ 2004-02 Page 3 of 6 Appendix C PP 7027 Rev. 3 Page 41 of 61

Appendix C (Continued)

Jet Furnus BWRVIP-41 (Reference 41, Section 2.3.3.7 states, The thermal sleeve welds are categorized as medium priority locations for plants that inject LPCI flow through the recirculation system. Also, . ..the BWRVIP is pursuing analyses which may reduce or alleviate inspection of TS-1 through TS-4welds. In the meantime, the same section further states, If a thermal sleeve weld were to crack to the point of separation, the thermal sleeve and attached riser pipe may experience some displacement, but the displacement would be small as discussed in Section 2.3.3.5.Section 2.3.3.5 states, Failure of welds TS-1 through T S 4 will not result in large vertical displacement of the jet pump assembly due to interference between the portion of the thermal sleeve which remains attached to the riser elbow and the ,

interior surface of the nozzle. Therefore, jet pump disassembly is not predicted for this type of failure.

Further, .horizontal displacement of the riser pipe is limited by interference with the shroud. Welds I..

1 TS-1, TS-2,and TS-3are far enough into the nozzle such that failure at these welds would not result in the thermal sleeve disengaging from the nozzle before the riser contacted the shroud. This has been confirmed to be true at VY,as follows: Weld TS-2 may be as close as 5% to the inside of the nozzle blend radius (Drawings 5920-656and 5920-6625 - References 11 and 15). The extrados of the jet pump I riser elbow is nominally 16% from the vessel ID (Drawings 5920-656 and 5920-1 127 - References 11 and 12). The OD shroud radius at the core elevation is 83 98 and the vessel ID radius is 102Y2 (Drawing 5920-3773,Sheet 2 - Reference 13). The shroud to vessel annulus dimension is therefore l 18 7/8.Consequently, the jet pump could deflect approximately 2% in the radial direction.which is much less than the 5% before weld TS-2exited the confines of the nozzle.

If the thermal sleeve or riser piping severed it would be detected through jet pump M-ratio monitoring.

OP 4110 (Reference 9)states, M-ratio is a calculated vdue which is used to detect the severance and displacement of the jet pump riser pipe. ERFIS points C286 (recirc loop A M-ratio) and C287 (recirc Ioop B M-ratio) have a 210% alarm setpoint while at or above a core flow of 42.0 M#kr. Additionally, Technical Specification 4 . 6 3 contains jet pump operability criteria.

V Y has very good water chemistry, which meets the requirements of BWRVIP-79 (Reference 16). All components below the top of the core shroud are protected by Noble Metal Chemistry Application (NMCA)with sufficient hydrogen injection to mitigate IGSCC of vessel internals. This includes the jet +

pump thermal sleeve welds.

Conclusion Vermont Yankee considers t h i s technical justification to provide an acceptable level of quality to demonstrate the structural integrity of the core spray and jet pump thermal sleeves to perform their intended function.

Duration olTechnicalJ ~ s t B c a t(State i ~ ~ how long rhe deviationwillbe in &ct)

This deviation will remain in effect until a delivery system for UT of the hidden welds is developed.

When this occurs, adequate time for site deployment will be also be factored, as allowed by PP 7027 (Reference 7) Paragraph 4.2.1.

AssumptiodOwn Itemq (List any assumptions used in the TJ andprovide a basis for each. List m y open items requiring addirional action prior to closure of the TJ.)

None.

TJ 2004-02 Page 4 of 6 Appendix C PP 7027 Rev. 3 Page 42 of 61

Appendix C (Continued)

I Reeommendationg (List detailed reconunendutions, as required to resolve the evaluated conditwm List all documents requiring changes and atdach marked up pages. Clearly state recommendationsfor p h n t modifications or changes to operating practices, including recommended changes to plant procedures.)

None.

Approvals (Print name andprovide sig&ure/date. A thorough review shall include a d consider inputfrom a wide variety of sources.)

Reactor Internats Management Program Coordinator N/A I @/A MechanicaVStructural Design (if appiicable)

- AI/& / hJ/h Chemistry (ifapplicable) 1f .I<

/!h./.%th,, CrOss-Disciplineor bhpenhnt Review (if applicable)

&"Code Programs Manager (signature) (date) .

ckseout (All actions that were recommended by the Techrrical Justification a.nd m y ident$ed open item have been &positioned)

Reactor htemals M I--

t >..1 TJ 2004-02 Page 5 of 6 Appendix C PP 7027 Rev. 3 Page 43 of 61

- . j _ _ L Appendix C (Continued)

1. Document Title (including Rev. No. and Date, if applicable) 1 BWRW-18, dated July 1996, B W R Core Spray Intemals Inspection and Flaw Evaluation Guidelines @PRx TR-106740) 2 Letter USNRC to BWRVIP,dated December 2, 1999, Final Safety Evaluation of Core Spray Internals Inspection and Flaw Evaluation GuideIines (BWRVIP-18) 3 Letter BWRVIP to USNRC,dated January 12, 1999, BWRVIP Response to NRC Safety Evaluation of BWRVIP-18 4 BWRVlf-4 1, dated October 1997. BWR Jet Pump Assembly Inspection and Haw Evaluation I Guidelines (EPRI TR-108728) 5 I Letter USNRC to BWRW, dated February 4,2001, Final Safety Evaluation of the Jet Pump Assembly Insp&tion and Flaw Evaluation Guidelines i

Appendix C PP 7027 Rev. 3 Page 44 of 61

Appendix C (Continued)

Technical Evaluation No. 2004-0018 Techdcai Evaluation No. TE-m-0018

- 2

Title:

Justification to Inspect Portions of Shroud Horizontal Welds H1, 32, and H3 on the OD In Lieu of the Top Guide Spacer Block Welds, the Shroud Range Ring Segment Welds, and the Top Guide Ring Segment Welds IQA (Safety Class, OQA, or Vital p i ) 0 Non QA (Non-Safety) (checkOne)

Backsround (Enter a concise mmmary of the condition or reasonfor the requested TE stating the existing condition and the desired results. State the J . .

in FWO 19 (1996),Vermont Yankee installed four tie-rods to repair the core shroud horizontal welds. Per UFSAR,Appendix K,the shroud welds repaired a m considered to be H3, H4,H5, H6, and H7. An inspection by INPO identifled a discrepant condition between what the repair designer (MPR) considers to be design-reliant welds and what was in fact inspected at V Y as being design-reliant, this is documented in EIp20012481. The designer of the shroud repair, MPR Associates, reiied on the following welds as design-reliant:

0 The twelve support blocks welded to the inside of the shroud at the top guide elevation 0 Three ring segment welds at the shroud flange elevati

. 0 Three ring segment welds at the top guide elevation 0 Threeringse ds at the core plate elevation 0 Allvertical those between H1 and H2 BWRVIP-76, Sectiwn 3.2, states, At some plants, a shroud repair m a y not include d1 relevant horizontal welds. The inspection for un-repaired horizontal welds in a repaired core shroud is identical to that for horizontal welds in aired Category C shrouds (see Section 2). Section 2.2.1 s r Category C shroud nt of the accessible regions of welds HX through H7 incl to be inspected. Se .2 states, ...the preferred inspection techniques are volumetric inspection 0 andlor a two-sided surface exam (i.e., EVT-1)...

Because of the difficuI welds, and the relative flaw-free condition of weIds H1,H2, and H3. Vermont Yankee IS1 Group requested the MechanicaVStructural Design Engineering Group (MSD) to evaluate and re-designate the welds that are design-reliant for the shroud repair.

Mxussion (Record the iied spe& attention du&g the The MSD Group had th air designer MPR Associates evaluate changing the design reliant welds. The calculations used are defined in References 1,2,3and 4 in the Design Input Section of this E. The calculations attempted to show that when the support blocks and VYAPF 6045.02 AP 6045 original Page 1 of 10 Appendix C PP 7027 Rev. 3 Page 45 of 61

Appendix C (Continued)

Technical Evaluation No. 2004-0018 associated welds were included in the model, (the blocks fit between the shroud wall between H1 and H2,and the horizontal section of the shroud between H3 and H2) the resultant weld stresses would be below 20% of allowable stress consistent with BWRW-26 (Ref. 5.) If these resultant stresses were below 20% of allowable stresses this would have made inspections the support block welds redundant. The stresses in the vertical shroud between 31 and H2 and in the horizontal shroud between H2 and H 3 included both primary and secondary stresses from plate bending that resulted in stresses being greater than the 20% of dowable stresses. The model was then run with only the lateral support blocks included in the model and included all fhe loads from the Top Guide. The results showed that with the blocks removed the stresses in both the horizontal shroud (H3 to H2) and the vertical shroud (32to H1)all stresses were below allowable stresses. The required length of weld in H1, H2 and H3 is 3.13 inches in each of the four quadrants spaced approximately equally. The actual length to be inspected would be 18 inches in each quadrant to allow for crack growth over the next six years. The radial welds from H3 to H2 do not need to be inspected and similarly the vertical welds between H2 and H1 do not I,.,, .

need to be inspected.

Through-wall cracks were assumed fdr the un-inspected length. Per 3WRVIP-76, (Reference

13) Appendix D, if less than 50% of the length is inspected, then a statistical argument for the un-inspected region is not allowed. Statistical arguments were not used.

If cracks are found in the inspected regions of HI, I2and H3 then an increase in the sample length of 18 inches should be done. The lengths of weld should be consistent with the requirement that the sample length be increased in that quadrant to ensure there is adequate length of good weld available.

Vermont Yankee is bound by certain commitments to follow the guidance of the BWRVIP (References 6 through 12). BWRVIP-94(Reference 1 l), Appendix A states that a technical justification shall be required when utility methodology is inconsistent with the intent of the supporting BWRVIP guidelines. Additionally, at VY,the inside of the shroud is not accessible $i' at HI, H2,and H3 to perform an EVT- 1. The core spray spargers cover H 1 and H2, and because of the grating that covers the periphery of the top guide, access to the sbroud ID would be through vacated fuel cells,and this would result m the camera being too distant from the 1

inspection surfaces to perform an adequate EVT-1of 31, H2,or H3. Therefore, V Y will not meet the BWRVIP requirement to inspect both the OD and ID of the welds and will not meet the B'WRVIP requirement to inspect 100% of the length of the welds. This document justifies t h i s variance from the BWRVlP requirements.

f Although no BWRVIP guidance is given for one-sided visual examinations of horizontal welds, the six-year inspection frequency follows the guidance for a one-sided EVT-1 of verticaZ welds per BWRW-76, Figure 3-3. The excellent results obtained in the 1995 ultrasonic examination of the H1, N2 and H3 welds (very limited indications) and the 1996 ultrasonic examination of the vertical and ring segment welds (no indications found) provide additional assurance that a one sided EVT-1is acceptable.

VYAPF 6045.02 AP 6045 Original Page 2 of 10 Appendix C PP 7027 Rev. 3 Page 46 of 61

i Appendix C (Continued)

Technical Evaluation No. 2004-0018 Also, Appendix K of the FSAR will need to be revised. This section of the U F S A R states that H1 and 32 are design-reliant welds (but does not include H3) and it states that the ring segment welds between E2 and H3 are design-reliant welds and all the welds connecting the twelve support blocks to both the horizontal section of the shroud (H3 to H2) and the vertical section of the shroud (32to Hl.) The ring segment welds and the support block welds are no longer design reliant.

ASSUllll3tiOas/O?De n X t e m s ( U t any assumptions used in the 223 andprovide a basis for euch. .List any o p a items requiring additional action prior to closure of the 7E)

None Material ReuuirementsAmDklIlellration Instructiong (List any i&ntifieri specfficationsfor equipment, muterials, or services needed to implement the recommendations of the TE SpecifL m y special implementation instructions or cautions, such asfield testing requirements or system interface requirements during implementatiolr)

The required inspections are as follows:

1. For the shroud horizontal welds H1, H2 and H3, inspect 18 inches in length in each of the four quadrants from the outside diameter (OD) using EVT-1 methods in accordance with NE 8048. If cracks are found in a quadrant, expand the length inspected in that quadrant to detect 18 inches of unflawed weId. Due date 05/15/04.

2. Inspect 100% of the accessible length of the shroud vertical weldsS4V1, S4V2, SWI, SW2, S7V1 and S7V2 from the OD using EVT-1 methods in accordance with NE 8048. Inspect shroud ring segment welds S6R!, S6R2 and S6R3 (at the core plate elevation) from the OD using EVT-1methods in accordance with NE 8048. Due date 11/15/05.

Recommendationq (List detailed recommendationr, as required, to resotve the evaluated condition. fist all documents requiring changes and anach marked up pages. C l e a e state recommendationsfor planz modifications or changes to operatingpractices, including recommended changes to p h t procedures.)

Based on the above analysis, this TE recommends the following actions:

I LLI 1. Inspect the welds as follows:

1: 1A. For the shroud horizontal welds H1. H2and H3,inspect 18 inches in length in each A. . 9 of the four quadrants from the outside diameter (OD) using EVT-1 methods in accordance with NE 8048. If cracks are found in a quadrant, expand the length

' 9 inspected in that quadrant to detect 18 inches of unflawed weId. Due date 05/15/04.

1B. Inspect 100% of the accessible length of the shroud vertical weldsS4V1, S4V2, S5V1, S5V2, S7V1 and S7V2 from the OD using EVT-1 methods in accordance with NE 8048. Inspect shroud ring segment welds S6R!,S6R2 and S6R3 (at the core plate elevation) from the OD using EVT-1 methods in accordance with NE 8048. Due date 11/15/05.

Responsible Department - System Engineering, Code Programs,dates as specified.

WAR?6045.02 AP 6045 Original Page 3 of 10 Appendix C PP 7027 Rev. 3 Page 47 of 6 1

Appendix C (Continued)

Technical Evaluation No. 2004-0018 Revise Appendix IS of the UFSAR.

Responsible Department - Design Engineering D u e Date - Later I

VYAPF 6045-02 AI? 6045 Original Page 4 of10 Appendix C PP 7027 Rev. 3 Page 48 of 61

Appendix C (Continued)

Technical Evaluation No. 2004-0018 ApprovaWCloseout (Print name and provide signatu I Independent Reviewer (qq)

I Zndepen&nt Reviewer (Code 'programs Supervisor)

/ Mech9nicdStNctural Design Supervisor I Design Engineering Manager (signature) (date)

Closeout (AZZ actwm that we mnnagement h b e bee and any ictentified open items have been dispositianed)

/ CE' (signature) <date)

Attachments (Pmvia'e a the Technical Evdu attached.

VYAPF 6045.02 AP60450riginal Page 5 of 10 Appendix C PP 7027 Rev. 3 Page 49 of 61

Appendix C (Continued)

Technical Evaluation NO. 2004-0018 TECHNICAL EVALUATION DATABASE INPUT TENo.: 2004-0018 TE

Title:

Justificationto InsDect Portions of Shroud Horizontal Welds H1,H2,and H3 on the OD In PIace of the Top Guide Spacer Block Welds. the Shroud Flanye Ring Segment Welds, and the TODGuide Ring Segment Welds Keywords: Shroud, Reactor Inkmals. Examination, BWRVTP

1. Document Title (including Rev. No.and Date,if applicable) 1 MPR Calculation 069-013-EBB-1, %ads in the H2A3 Support Ring Pads.

2 MPR Calculation 069-013-EBB-2, Shroud Stresses.

3  : MPR CaIculatbn 069-013-JLH-I, Support Pad @!ocks) and Aligner Pad Weld

• Evaluation.

4 MPR CaIculation 069-01fCBS-1, Required Intact Length for Shroud Welds H1,32 and H3.

5 PWO27, Rev.1, Reactor Vessel lnternals Management Program.

6 3WRVTP-26, CSWR Top Guide Inspection and Evaluation Guidelines.

7 Letter Carl Terry CsWRvlpExecutive Chairman) to Brian Sheron (USNRC) dated May 30,1997, CBWR UWty Commitments to the BWRVIF 8 BVY 97-l23,dated September 30,1997, Vermont Yankees Plans for the 1998 and 1999 Refueling Outages Regarding Reactor Vessel Internals 9 Letter Brian Sheron (USNRC)to Carl Terry (BWRVIP Executive Chairman), dated July 29,1997, 9 W R Utility Commitments to the BWRVIP 10 Letter Cad Terry (BWRVIP Executive Chairman) to Brian Sheron (USNRC) dated October 30,1997, 6cBWUtility Commitments to the BWRVIP7 11 BWRVIP-94,dated August 2001,CBWRIPProgram Implementation Guide EPRI TR 1.006288 1 April 16,2002, G j e c t No. 704 - Utility Implementation of B W R e Products 13 f BWRVIP-76. dated November 1999. BWR Core Shroud InsDection and Flaw Evaluation Guidelines EPRI TR-114232 14 BWRVIP-03, Revision 5, dated December 2002, tReactor Pressure Vessel and Internals Exandnation Guidelines 15 Letter Carl Terry (BWRVIP Executive Chairman) to Brian Sheron (USNRC) dated May 30,1997, %WR Utility Commitments to the BWRVIP 16 BWRVIP-14. dated March 1996. %valuation of Crack Growth in BWR Stainless SteeI RPV Internals EPRI TR-105873 17 Letter Jack Strosnider (USNRC) to Carl Terry (BWRVIP Executive Chairman), dated I I December 3,1999, 3inaI Safety Evaluation of Proprietary Report TR 105873 BWR Vessel and Internals Project, Evaluation of Crack Growth in B W R Stainless Steel RPV WAPF 6045.02 AP 6045 Original Page 6 of 10 Appendix C PP 7027 Rev. 3 Page 50 of 61

Appendix C (Continued)

Technical Evaluation No. 2004-0018 Internals (BWRVIP-14) WAC No. M94975) 18 GE Nuclear Energy Report No. GE-qq,Revision q, dated qq, 6ShroudWelds Fl Evaluation Handbook for Vermont Yankee 19 UFSAR Appendix K Design Output Documents - The fbllowing documents are impacted by this TI%.

1. I Document Title 1

UFSAR Revise Appendix K to define the new design reliant welds Generai References

1. I Reference Title (including Rev. No. and Date, if applicable)

None Data Entered into Database / Entry Verified /

Signature Date Signature Date L.:. t VYAPF 6045.02 AP6045origina.l Page 7 of 10 Appendix C PP 7027 Rev. 3 Page 51 of 61

Appendix C (Continued)

Technical Evaluation No. 2004-0018 TECHNICAL EVALUATION Rl%VJEw TE# @04-0019 ReqWDate: Reviewer Assigned:

Tide. Justification to Inspect Portions of S h u d Horizontal Welds H1. H2,and H3 on the OD InPlw.of the.ToDGuide Suacer Block Welds, the Shroud Flange Ring Seement Welds. and the Tor,Guide Rinp Segment Welds Comments:

Resolution:

I Reviewer Signature Date Notes and Requirements:

1.

2 3.

4.

5.

6.

7.

8.

VYAPP 6045.04 AP 6045 Original Page 5 of 17 Appendix C PP 7027 Rev. 3 Page 52 of 61

-_ -- -.- )pee^ I-

"i9"

Appendix C (Continued)

Technical JustificationNo. TJ 2004-04

Title:

Inspection Technique for Weld H9 Technical justification is required when utility procedures, inspections. methodology, or guidelines are inconsistent with the intent of the supporting BWRVIP guidelines.

4 BWRVlP Reauhment (Give BWRViP document and Section reference with a restatement of the requirement)

BWICWP-38 (Reference l), Figure 3-5,requires an EVT-1 of the top surface of weld H9 - or as an alternative - a UT of weld zF9. BWRVI-104 [Reference 5), Section 9.2, states, Perform an EVT-1 visual examination, or ultrasoNc examination, of both the top and bottom surfaces of the shroud support plate-to-RPV weld (H9) in accordance with BFVRVIP-38 ...The ultrasonic examination should be demons@atedin accordanGe with 3WRVIp-03 for the detecdou of both axial and circumferential flaws in the weld material. The technique shall be capable of determining if any flaws have propagated into the RPV low alloy steel.

WRVIP re EVT-1 of the underside of ire cells or jet pumps. In-view of the fact that manipulation for c se visual examination would not be possible with current visual inspection technology, Vermont Yankee will not visually inspect the underside of weld H9.

Further, no vendors are now qualified to detect axial flaws using UT, so Vermont Yankees UT inspection of weld H9 will not be capable of detecting axid flaws.

Justiffcation (Provide the basis osed n meets the same obje intent, or level of conservatism exhibited by the BWRVIP guidelines. The justification shalt be supported by calcuIotionr when warranted Clearly identi& all available informatian and resomes, which albw the devianbn to be acceptable. Clearly idenr@ the impact that the devilrtion will have on Acceutance Basis Vermont Yankee performed a UT inspection of 22% of H9 in RFO 19 (1996)and no flaws were found (Reference 8). This met the required extent of examination for BWRW-38 (Reference l), as explained in PP 7027, Appendix B, Section 4.1. However, the UT technique was not capable of detecting transverse flaws.

Cracking has been identified in the Tsuruga 1 and Nine Mile Point 1 (both BWW2 plants) shroud support-to-RPV welds, which indicates that stmss corrosion cracking is present in the alloy 182 welds of those two shroud s u p r t structures. The idenwied cracking at both plants was primarily on the bottom surf*e of the H9 weld. See References 6 and 7. The Tsuruga operating experience was the instigator for the BWRW-104 (Reference 5) inspection recommendations. Vermont Yankee would be required to examine at least 10% of the weld by either EVT-1from both the top and bottom sides or by UT.

Either exam would be required to detect transverse cracking. For the H9 weld, transverse would be vertical in the radial direction.

Most industry inspections of the shroud support plate to RPV weld H9 have been performed using EVT-1 from the top surface of the weld, with some examinations by UT from the RPV OD surface-Visual examination of the bottom surface of the H9 weld typically has not been performed due to limited accessibiIity to that surface, which is only accessible through the JP diffuser or through a TJ 2004-04 Page 1 of4 Appendix C PP 7027 Rev. 3 Page 53 of 61

Appendix C (Continued) disassembled fuel cell. At Vermont Yankee,there is no access from the outside of the reactor vessel at the elevation of the H9 weld.

There are two reasons for inspection of H9 in accordance with BWRVIP-38 and BWRVIP-104. One is to assure that the integrity of the shroud support structure is maintained. The other is to assure that any flaws found in H9 do not propagate into the RPV pressure boundary governed by ASME Section XI.

The integrity of the shroud support structure is assured by: I) a UT inspection in accordance with BWRVIP-38; 2) acceptable U T inspection results; and 3) good water chemistry.

3WRVIP-38 was written to assure that the integrity of BFVR shroud supports is maintained. The U T inspection for circumferential flaws achieves this goal by meeting the guidance of BWRVIP-38. Per BWRVIP-38, Table 5-1, Vermont Yankee has the fourth lowest load multiplier in the fleet and therefore, one of the greatest flaw tolerances. Since Vermont Yankee has inspected 22% of the H9 weld, there is good assurance that the integrity of the shroud support has been maintained.

It is important to note that the core shroud support codiguration of the B W 2 plants, such as Tsuruga and Nine Mile Point 1 is different than the CBI B W 3 . 4 and 5 plants, in that the support at BWR-2 plants consists of a conical-shaped support ring, while the newer configuration has a horizontal I supporting ring plate w i d legs. The new design appears to have better loadirig distribution. Vermont Yankee has the newer design with 14 legs. Other than some minor cracking in a leg weld at Monticello, I .

there have been no adverse operating experience reports on the newer design.

Regarding the second issue concerning possible transverse flaw propagation into the RPV pressure boundary, the following arguments can be given. In both the Tsumga and Nine Mile Point 1 shroud support H9 welds, the predominant flaws were transverse; however, there were also associated circumferential flaws in both cases. Because the Vermont Yankee H9 weld examination did not reveal any circumferential cracking, there is a lowered probability that associated transverse cracking would exist. Transverse cracking did not exist in the absence of circumferential cracking in the two known cases.

Also,Vermont Yankee does not know of any cases in any B W R where internal attachment weld flaws have propagated into low-alloy base material. BWRVlP48 (Reference 2). Section 3. I. 1 states, No propagation of indications into the vessel base material has been found in the inspections [of attachment welds] performed to date. It is also important to note that of the many transverse cracks found in the H9 weld at Tsuruga, all were excavated and none of the flaws were found to have propagated into the 1..

RPV low alloy steel material (Reference 7). This is statistically a very iarge sample, and therefore, it can be concluded that a contrary result would occur with very low probability.

The shroud support examinations p e r f o d at Vermont Yankee have shown no signs of cracking.

Vermont Yankee has very good water chemistry with HWC and NMCA, meeting the requirements of BWRVP-79 (Reference 3).

ConcIusion Vermont Yankee considers this technical justification to provide an acceptable level of quality to demonstrate the structural integrity of shroud support weld H9 to perform its intended function.

TJ 2004-04 Page 2 of 4 Appendix C PP 7027 Rev. 3 Page 54 of 61

Appendix C (Continued)

Duration of Technical Justificatioq (State how long the deviation will be in t$ect.)

This deviation will remain in effect until a UT technique is qualified for detection and sizing of transverse cracks in the H9 weld. When this occurs, Vermont Yankee wiU use such a technique at the subsequent examinationof weld H9,per the scheduling requirements of BWRVIP-38.

Assumntiodotma items (List m y assumptions used in the TJ and provide a basis f i r each. List any open items requiring additwnalacrionprior to closure of the TJ.)

None.

Recommendations (List detoiled recommmddwns, os required to resolve the evaluated c o d t i o a tist all documents requiring changes and attach mankcd up pages. Clearly state r e c o m a o n s f o r plant mod@cations or changes to operating practices, including recommended changes to pkmtprocedures.)

None.

Approvals (Prinr numi? and provide signaturddate. A thorough review shall include Md consider inputfrom a wide variery of

/ 3/2G& Reactor hternals Management Program Coordinator U/k / lo/A. MechdciUStructuralDesign (if applicable)

/ u/h Chemistry (if applicable)

/ 3 b 0 t h e r Cross-Disciplineor Independent Review (ifapplicable) m/dN Code Programs Manager Closeout (All actions that were recommended by the Technical Jus@c&n Md accepted by management have been ini:iated and any ident$ed open items have been dispositioned)

/ J/I../../ Reactor hternals Management Program Coordinator (Signature) c-1 TJ 2004-04 Page 3 of 4 Appendix C PP 7027 Rev. 3 Page 55 of 61

8 - J 4 -1 -

Appendix C (Continued)

Input Documents and other References - Tbe following documents provide input to this Technical Justification.

1. I 1

Document Title (including Rev. No.and Date, if applicable) 1 BWRVIP-38, September 1997, B W R Shroud Support Guidelines ( E P e TR-108823)

- - Inspection

- and Flaw Evaluation I 2 BWRVJP-48, February 1998,BWRVIP Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines-(33PR.I TR- 108724) 3 BWRVIP-79, March 2000, B W R W a t e r Chemistry Guidelines-2OOORevision

- 4 BWFtVlP-94, August 2001,BWRVIP Program Implementation Guide (1006288) 5 BWRVIP-104,September 2002,BWR Evaluation and Recommendations to Address Shroud J Support Cracking & BWRs (1oO3555) 6 GE SJL 624, March 24,2000, Stress Corrosion Cracking in Alloy 182 Welds in Shroud I Suppqrt Structure 7 1 BWRVlP Report, July 14,2000, Summary of June 13,2000 Meeting with JAPC on Tsuruga Unit 1 Shroud Support Cracking 8 Framatome Technologies Report dated December 18.1996, 1996 Vermont Yankee Nuclear Power Corporation Project File Report for Core Shroud Examinations of the Vertical, Ring Segment, Ad H8M9 Baffle Plate Welds 9 NOPDlA1, Reactor Vessel Internals Inspection Program 10

~ NE21.01.E g&or VesseI Internals Inspection Implementing Procedure

[ 11 I V Y Drawir-1 P

t I

i I

TJ 2004-04 Page 4 of 4 Appendix C PP 7027 Rev. 3 Page 56 of 61

Appendix C (Continued)

Technical JustificationNo. TJ-2 Ti spection Deferral for U T of Technical justification is required when utility procedures, inspections, methodology, or guidelines are inconsistent with the intent of the supporting BWRViP guidelines.

B W R W Reauire-t (Give BWRVlP documentand Section reference with a restate+wnt of the requirement.)

BWRVIP- 27;A (Reference 3), Sections 3.3.1 and 3.4.1 require a UT of the nozzle-to-safe-end weld and the safe-end extension wfien a &liable UT technique is identified. Until such time as a qualiied volumetric examination is available, enhanced leakage inspections (EVT-2) or surface examinations (PT) may be performed. (When BWRVIP-27-A was published in August 2003, it replaced BWRVIP-27

[Reference 21.) BWRW-03 (Reference l), Revision 6,.Standard 2.6, Section 3.3, states, Personnel performing fiial analysis and review of examinations of dissimilar metal welds in the standby liquid control system shall have current qualification for ction, length sizing, and/or depth sizing, as appropriate. in accordance with ASME Section XI, qualifications scope shall include the diameter and welds.

Venn0nt Yankee Devialioq how V e m i u merit.

U T techniques and personnel have been qualified for detection in accordance with ASME Section XI, Appendix VIII, Supplement 10 (Reference 6), for the diameter and thickness of the VY nozzle-to-safe-end There are two problems

2) It would be risky to perform manual UT for detection of cracking without having a through-wall Sizing technique. If a flaw wem detected, a repair (probably by weld overlay) would automaticallybe necessary. Automated weld overlay equipment.

A s an alternative to the ultrasonic examination, Vermont Yankeewill continue to perform either EVT-2 every refueling outage or Fj every other refueling outage.

justification (Provide the e propos eets the same objective and intent, or-level of consewatism exhibited by the BWRWF gui&Iines. The just$kation shaU be supported by calculations when warranted Clearly identiB all available infirmation and resources, which allow the deviation to be acceptable. CIearly irientijj the impact that the deviation will have on meeting the intent of the guideline.)

Acceptance Basis BFcrRVIP-27-A (Reference 3)- published in August 2003, governs inspection of the SLC and core plate AP system. BWRVIP-27-A asserts that the only safety critical welds in the SLCKore Plate AP system within the scope of the BWRVIP are the welds outside the reactor vessel which connect the SLC system piping to the vessel. BWRVIP-27-A, Section 2.1.5 and Figure 2-5 describe the Vermont Yankee TJ-2004-05 Page I of 3 Appendix C PP 7027 Rev. 3 Page 57 of 61

Appendix C (Continued) configuration, which is a stainless steel safe-end welded to a carbon steel forged nozzle and fabricated by C B & L V Y Drawing 5920-358 (Reference 13) shows this configuration and Drawing 5920-5266 (Reference 14) shows the replacement safe-end of improved material installed shortly before initial start-up. The safe-end thickness on both drawings is 7/8. The OD of the safe-end extensions is 3.69.

BWRVIP-27-A, Sections 3.3.1 and 3.4.1 state the requirements for the Vermont Yankee configuration; it requires that the nozzle-to-safe end weld and the safe-end extension be examined volumetrically.

However, per those same Sections, until such time as a qualified volumetric examination is available, enhanced leakage inspections (EVT-2) or surface examinations (PT)may be performed.

V Y performed EVT-2 inspections of this joint in RFO 20 (1998), RFO 21 (1999), and RFO 22 (2001) and PT of thejoint in RFO 23 (2002)(see References 7 though 10).

Prior to the publication of BWRW-27-A in August 2003,BWRViP-27 (Reference 2), which was published in October 1997, governed inspection of the SLC system. BWRVIP-27, Sections 3.3.1 and 3.4.1 also stated that, until such time as a qualified volumetric examination is availabe,enhanced leakage inspection during each Category B-P pressure boundary leak test should be performed. An enhanced leakage test is defined as requiring a view of this joint specifically, rather than as would normally be required by ASME Section X I , which would be an examination for leakage in the general area. Per BWRVP-27-A, insulation removal is required. This was not clarified until BWRVIP-274 was issued as a draft in July 2002. Until that time the need for insulation removal was not explicitly stated (in BWRVP-27) and VY did not do such in RFO 20 (1998), RFO 21 (1999), and RFO 22 (2001).

A stress corrosion crack through-wall crack would be detected before the safe-end would sever completely (leak before break). The alternative examinations - EVT-2 or PT - would detect a leak, especially with the insulation removed. Because Vermont Yankee has inspected this location recently

( t l cycle), and because of the short time planned between future inspections (one cycle for EVT-2 or two cycles or PT),growth over this short time would not result in a complete loss of structural integrity for this joint - especially given its large 0D:ID ratio (1.9). It is highly unlikely that a crack would extend through-wall in one area while at the same time losing structural integrity over the entire circumference. zf evidence of Ieakage is found a repair should be performed.

Conclusion Vermont Yank= considers this technical justification to provide an acceptable level of quality to demonstrate the structural integrity of the SLC nozzle-to-safe-end weld and safe-end extension to perform its intended function.

Duration of Technical JustXcatiog (Stare how long the deviution will be in Meet.)

This deviation will remain in effect either until a UT manual technique is q u a l e d for through-wall sizing or until automated UT equipment is developed that could access the SLC safeend. When this occurs, adequate time for site deployment will be also be factored, as allowed by PP 7027 (Reference ll),

Paragraph 4.2.1.

A s s u m d o d o w n I t e q (List a q a~s~tmptions used in the TJ and provide a bask for each. List m y open items requiring o d d i t i o d action prior to closure of the TJ..)

None.

TJ-2004-05 Page 2 of 3 Appendix C PP 7027 Rev. 3 Page 58 of 61

I Appendix C (Continued)

Recommendations (List detailed recommendations, as required to resolve the evaluared condiiwn. List all documents requiring changes and attach marked up pages. Clearly state recommendationsfor plant mod#ications or changes to operating f practices, including recommended changes to plant procedurm-)

None.

Approvals (Print name and provide signaturw'date. A thorough review shall include and conridcr input from a wide variety of sources.)

Reactor Internals Management Program Coordinator tu& Design (if applicable) er Cross-Discipline or IndependentReview (if applicable)

(signature) (date) -

Closeout (All actions thar were recommended by the Technical Justi&ation and accepted by rnmagernent have been initkted and any i d e n w d open 'itemhave been dhpositioned)

/ Reactor InternalsManagement Program Coordinator (signature) (&e) 12 ' NE 8067, Reactor Vessel Intemals Inspection Details 13 VY Drawing 5920-358 14 , V Y Drawing 5920-5266 TJ-2OO4-05 Page 3 of 3 Appendix C PP 7027 Rev. 3 Page 59 of 61

Appendix C (Continued)

Technical Justification No.

Title:

[Format Model]

Technicaljustification is required when utility procedures, inspections, methodoIogy, or guidelines are inconsistent with the intent of the supporting BWRVIP guidelines.

BWRVIP Requirement(Give BWRVTP document and Section reference with a restatement of the requirement.)

Vermont Yankee Deviation (Recordhow Vermont Yankee deviates or deviatedfiom the BWRVIP requirement.)

Justificaton (Provide the basis for determining that the proposed deviation meets the same objective and intent, or level of conservatism exhibited by the BWRWP guidelines. Thejustijkation shall be supported by calculations when warranted. Clearly identifi all available information and resources, which allow the deviation to be acceptable. Clearly identi3 ihe impact that the deviation will have on meting the intent of the guideline.)

Duration of Technicai Justification(State how long the deviation will be in efect.)

AssumptiondOpen Items ( f i t any assumptions used in the TE and provide a basis for each. List any open items requiring additional actionprior to closure of the TE.)

Recommendations (List detailed recommendutions, as required, to resolve the evaluated condition. List all documents requiring changes and attach marked up pages. Clearly state recommendationsfor plant modijkations or changes to operating practices, including recommended changes to plant procedures.)

Based on the above analysis, this Technical Justification recommends the following actions:

1.

Responsible Department -

Due Date -

2.

Responsible Department -

Due Date -

Appendix C PP 7027 Rev. 3 Page 60 of 61

Appendix C (Continued)

Approvals (Print name and provide signaturddate. A thorough review shall include and consider input from a wide varieo of sources.)

I Reactor Internals Management Program Coordinator I MechanicaYStructuralDesign (if applicable)

I Chemistry (if applicable)

I Other Cross-Disciplineor Independent Review (if applicable)

I Code Programs Manager (signature) (date)

Closeout (All actions that were recommended by the Technical Justification and accepted by management have been initiated and any ia!entij?ed open items have been dispositioned)

I Reactor Intemds ManagementProgram Coordinator f'

I 1 (signature) (date) i I I

1. I Document Title (includingRev. No. and Date, if applicable) 1 1 1 2 1 1 3

4 Appendix C PP 7027 Rev. 3 Page 61 of 61